Parker Drilling (PKDC) 10-K 2006 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)
þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	FOR THE FISCAL YEAR ENDED DECEMBER 31, 2006
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
Preferred Share Purchase Rights	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     Noo

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     Noo

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of thisForm 10-K or any amendment to thisForm 10-K.  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” and “large accelerated filer” in Exchange ActRule 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 inRule 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, 2006 was $726.0 million. At January 31, 2007, there were 109,985,207 shares of common stock issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of our definitive proxy statement for the Annual Meeting of Shareholders to be held on April 25, 2007 are incorporated by reference in Part III.

TABLE OF CONTENTS

			PAGE
PART I
	Item 1.	Business		1
	Item 1A.	Risk Factors		8
	Item 1B.	Unresolved Staff Comments		19
	Item 2.	Properties		19
	Item 3.	Legal Proceedings		21
	Item 4.	Submission of Matters to a Vote of Security Holders		21
	Item 4A.	Executive Officers		22
PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		23
	Item 6.	Selected Financial Data		24
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		25
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		42
	Item 8.	Financial Statements and Supplementary Data		43
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		89
	Item 9A.	Controls and Procedures		89
	Item 9B.	Other Information		90
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance		91
	Item 11.	Executive Compensation		91
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		91
	Item 13.	Certain Relationships, Related Transactions and Director Independence		91
	Item 14.	Principal Accounting Fees and Services		91
PART IV
	Item 15.	Exhibits and Financial Statement Schedule		92
Signatures				96
Second Amendment to Credit Agreement
Subsidiaries
Consent of Independent Registered Public Accounting Firm
Rule 13a-14(a)/15d-14(a) Certification
Rule 13a-14(a)/15d-14(a) Certification
Section 1350 Certification
Section 1350 Certification

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, who retired as chairman in April 2006, and the grandfather of Robert L. Parker Jr., chairman, 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 onForm 10-K, quarterly reports onForm 10-Q, current reports onForm 8-K, and amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish 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 53 foreign countries and the United States, making us among the most geographically experienced drilling contractors in the world. We have extensive experience and expertise in drilling geologically difficult wells and in managing the logistical and technological challenges of operating in remote, harsh and ecologically sensitive areas. Our quality, health, safety and environmental policies and procedures are best in class.

Our revenues are derived from three segments:

•  U.S. barge and land 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, 2006, 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;

•  three land rigs in the Latin America region;

•  three land rigs in the U.S. domestic region;

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

•  one land rig in the Middle East region;

•  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. Two workover rigs were subsequently sold in January 2007.

ITEM 1.  BUSINESS (continued)

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- pressure blowout preventers, choke manifolds, junk and cement mills and casing scrapers. Approximately one-fourth of Quail Tools’ equipment is utilized in offshore and coastal water operations of the Gulf of Mexico. Quail Tools’ base of operations is in New Iberia, Louisiana. Other rental facilities are located in Victoria and Odessa, Texas; Evanston, Wyoming and a new facility in Texarkana, Texas scheduled to open in the first half of 2007. Quail Tools’ principal customers are major and independent oil and gas exploration and production companies operating in the Gulf of Mexico and other major U.S. energy producing markets. Quail Tools also provides rental tools to customers operating internationally in Trinidad and Tobago, Mexico, Russia, Singapore, Nigeria 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 water transition zones, primarily in Louisiana 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 infrastructureand/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 our 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 dependable drilling performance, innovative drilling solutions and high-quality rental tools services. We manage our operations in accordance with a long-term strategic growth plan. Key elements in our strategy include:

Pursuing Strategic Growth Opportunities.  We are in the process of growing a fleet of preferred rigs that will be utilized regardless of the position in the energy business cycle. In 2006, we completed the construction of a 3,000 HP barge rig for use in the U.S. Gulf of Mexico. Two of four new 2,000 HP international land rigs were delivered early in 2007 for drilling operations in Algeria. The remaining two rigs under construction are expected to be delivered in the second and third quarters of 2007. The scope of our joint venture in Saudi Arabia has expanded from four rigs to six, with four of the 1,500 HP land rigs in country and rigging up for expected spud dates in the first half of 2007. Our new rental tools facility will open in March of 2007 and will include a new storage and inspection location.

Sustaining the High Utilization of Our Barge and Land Rigs.  Another one of our strategic objectives is to sustain the high utilization of our barge and land rigs with strategic placement in areas which evidence long term development opportunities. Our preventive maintenance program allows dependable operating efficiency, minimizing down time and creating “contractor of choice” mentality for contract extensions or renewals.

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ITEM 1.  BUSINESS (continued)

Our Strategy (continued)

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. During 2006, we implemented planning and forecasting tools that facilitate the review of all costs. Our operating philosophy emphasizes continuous improvement of processes, equipment standardization and global quality, safety and supply chain management. In early 2007, we implemented new supply chain management and reporting systems. Capital expenditures are aligned with core objectives and aggressive preventive maintenance programs.

Continuing to Reduce Our Debt to Capitalization Ratio and Enhance Our Liquidity.  Our long-term goal is to reduce our debt to capitalization ratio to be in the 30 percent range. Since the establishment of this goal, we have reduced our debt to capitalization ratio to 42 percent from a high of 76 percent. We expect to achieve our long-term goal by reducing our debt and interest costs and reporting strong earnings in the next few years.

Our Competitive Strengths

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

Geographically Diverse Operations and Assets.  We currently operate in Algeria, Bangladesh, China, Colombia, Indonesia, Kazakhstan, Kuwait, Libya, Mexico, New Zealand, Papua New Guinea, Russia, Saudi Arabia and the United States. Since our founding in 1934, we have operated in 53 foreign countries and the United States, making us among the most geographically diverse drilling contractors in the world. Our international revenues constituted approximately 47 percent of our total revenues in 2006. 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 Latin America, where we are operating two land rigs and one land rig in the Middle East. Our international offshore drilling operations focus on the Caspian Sea, where we own and operate the world’s largest arctic-class barge rig; and Mexico, where we have one barge rig. We currently have 17 drilling and workover barge rigs in the shallow water transition zones of the U.S. Gulf of Mexico, and three land rigs in the U.S. domestic region. See Note 2 to the consolidated financial statements.

Outstanding Safety, Preventive Maintenance, Inventory Control and Training Programs.  We have an outstanding safety record. In 2006, we achieved the lowest Total Recordable Incident Rate (“TRIR”) in our history. Our safety record, as evidenced by our low TRIR, has made us a leader in occupational injury prevention for the last 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 Jr. joined Parker Drilling in 1973 and has served as our president and chief executive officer since 1991 and chairman of the board since April 2006. Under the leadership of Mr. Parker Jr., we have sustained 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 25 years of experience to our drilling operations which enhances our ability to achieve our goals of increased utilization and profitable growth. Our chief financial officer, W. Kirk Brassfield, joined Parker Drilling in 1998 and has served in

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ITEM 1.  BUSINESS (continued)

Our Competitive Strengths (continued)

several executive positions including vice president, controller and principal accounting officer. He brings 27 years of experience to the management team, including 15 years in the oil and gas industry.

Project Management

We are active in managing and providing labor resources for drilling rigs owned by third parties. In Russia, we designed, constructed and sold a rig to Exxon Neftegas Limited (“ENL”) and currently manage drilling operations under a five-year Operations and Maintenance (“O&M”) contract that began in June 2003. We also supervised construction of a second rig to drill from the Orlan platform and began a five-year O&M contract for ENL offshore Sakhalin, Russia in September 2005.

Throughout 2006, we managed two projects in Papua New Guinea under full O&M contracts that began the third quarter of 2005. We are currently assisting with the construction of an operator-owned helicopter rig for the Papua New Guinea market and will provide operation and maintenance services once the rig is mobilized. We also provided labor services on third party-owned drilling rigs in Kuwait, China, Peru and Colombia in 2006.

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, quality of our equipment, repair and maintenance, our experience and our safety record. In international land and offshore markets, our experience in operating in challenging environments has been a factor in securing contracts. We believe that the market for drilling contracts, both land and offshore, will continue to be highly competitive for the foreseeable future. Our management believes that Quail Tools is one of the leading rental tools companies in the offshore Gulf of Mexico and other major U.S. energy producing markets. 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 2006, ExxonMobil accounted for approximately 14 percent of our total revenues, and Chevron accounted for approximately 8 percent of our total revenues. Our ten most significant customers collectively accounted for approximately 52 percent of our total revenues in 2006.

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ITEM 1.  BUSINESS (continued)

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 number of wells. The contract term in some instances may be extended by the customer exercising options for the drilling of additional wells or for an additional time period, or by exercising a right of first refusal. Most of our contracts may be terminated by the customer prior to the end of the term without penalty under certain circumstances, such as the loss or major damage to the drilling unit or other events that cause the suspension of drilling operations beyond a specified period of time. In certain cases we are able to obtain an early termination fee if the operator terminates a contract before the end of the term without cause.

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

Insurance and Indemnification

In our drilling contracts, we generally seek to obtain indemnification from our customers for some of the risks related to our drilling services. To the extent that we are unable to transfer such risks to customers by contract or indemnification agreements, we generally seek protection through insurance. To address the hazards inherent in our business, we maintain insurance coverage that includes physical damage coverage, third party general liability coverage, employer’s liability, environmental and pollution coverage and other coverage. We believe that our insurance coverage is customary for the industry and adequate for our business. However, there are risks 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.

Employees

The following table sets forth the composition of our employees:

	December 31,
	2006		2005
International drilling (1)		1,574		2,113
U.S. drilling		631		564
Rental tools		217		175
Corporate and other		206		188
Total employees		2,628		3,040

(1) Declines relate primarily to sale of rigs in Nigeria and contract completions in Mexico, Kazakhstan and Turkmenistan.

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

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ITEM 1.  BUSINESS (continued)

Environmental Considerations (continued)

types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require remedial action to prevent pollution from former operations, and impose substantial liabilities for pollution resulting from our operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly compliance could adversely affect our operations and financial position, as well as those of similarly situated entities operating in the Gulf Coast market. While our management believes that we are in substantial compliance with current applicable environmental laws and regulations, there is no assurance that compliance can be maintained in the future.

The drilling of oil and gas wells is subject to various federal, state, local and foreign laws, rules and regulations. As an owner or operator of both onshore and offshore facilities, including mobile offshore drilling rigs in or near waters of the United States, we may be liable for the costs of removal and damages arising out of a pollution incident to the extent set forth in the Federal Water Pollution Control Act, as amended by the Oil Pollution Act of 1990 (“OPA”), the Clean Water Act (“CWA”), the Clean Air Act (“CAA”), the Outer Continental Shelf Lands Act (“OCSLA”), the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), and comparable state laws, each as may be amended from time to time. In addition, we may also be subject to applicable state law and other civil claims arising out of any such incident.

The OPA and regulations promulgated pursuant thereto impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” includes the owner or operator of a vessel, pipeline or onshore facility, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability of oil removal costs and a variety of public and private damages to each responsible party.

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.

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ITEM 1.  BUSINESS (continued)

Environmental Considerations (continued)

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

All of our operating U.S. barge drilling rigs have zero-discharge capabilities as required by law, e.g. CWA. In addition, in recognition of environmental concerns regarding dredging of inland waters and permitting requirements, we conduct negligible dredging operations, with approximately two-thirds of our offshore drilling contracts involving directional drilling, which minimizes the need for dredging. However, the existence of such laws and regulations (e.g., Section 404 of the CWA, Section 10 of the Rivers and Harbors Act, etc.) has had and will continue to have a restrictive effect on us and our customers.

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

CERCLA (also known as “Superfund”) and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. While CERCLA exempts crude oil from the definition of hazardous substances for purposes of the statute, our operations may involve the use or handling of other materials that may be classified as hazardous substances. CERCLA assigns strict liability to each responsible party for all response and remediation costs, as well as natural resource damages. Few defenses exist to the liability imposed by CERCLA. 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.

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ITEM 1.  BUSINESS (continued)

FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS

We operate in three segments, U.S. drilling, international drilling and rental tools. Information about our business segments and operations by geographic areas for the years ended December 31, 2006, 2005 and 2004 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 thisForm 10-K, including the financial statements and related notes, before deciding to invest in our securities. While these are the risks and uncertainties we believe are most important for you to consider, you should know that they are not the only risks or uncertainties facing us or which may adversely affect our business. If any of the following risks or uncertainties actually occur, our business, financial condition or results of operations could be adversely affected.

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. We may also make significant expenditures when we move rigs from one location to another. Additionally, we are making substantial expenditures for the construction of new rigs consistent with our strategy to construct a fleet of preferred rigs that will operate continuously despite market fluctuations. Rig upgrade, refurbishment and construction projects are subject to the risks of delay or cost overruns inherent in any large construction project, including the following:

•  shortages of 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.

Risk Factors Related to Our Business

Failure to retain skilled and experienced 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.

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ITEM 1A.  RISK FACTORS (continued)

Risk Factors Related to Our Business (continued)

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

As of December 31, 2006, we had stockholders’ equity of $459.1 million compared to:

•  $329.4 million of long-term debt;

•  $11.0 million of operating lease commitments; and

•  $23.1 million of standby letters of credit.

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

Cash flows from operating activities were $166.9 million in 2006, $122.6 million in 2005 and $28.8 million in 2004. 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 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 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, including our Senior Floating Rate Notes, 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 flow from operating activities to pay the principal of and interest on our indebtedness is subject to certain market conditions and other factors which are beyond our control.

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

Our business requires substantial capital (we anticipate that our capital expenditures in 2007 will be approximately $200.0 million, including approximately $32.9 million for maintenance projects). We may

9

ITEM 1A.  RISK FACTORS (continued)

Risk Factors Related to Our Business (continued)

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

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 impact on our operations in the Gulf of Mexico.

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

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

•  advances in exploration, development and production technology;

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

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

•  new rig construction projects begun in the last eighteen months;

•  local and worldwide military, political and economic events, including events in the oil producing countries in the Middle East, Southeast Asia, Latin America and Commonwealth of Independent States (“CIS”);

•  the ability of the Organization of Petroleum Exporting Countries “OPEC” to set and maintain production levels;

•  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;

10

ITEM 1A.  RISK FACTORS (continued)

Risk Factors Related to Our Business (continued)

•  the availability of pipeline capacity; and

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

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

Most of our contracts are subject to cancellation by our customers without penalty with relatively little or no notice. Although drilling conditions are currently favorable, in the event the market becomes depressed, customers may seek renegotiation of contract terms or to exercise their termination rights.

Our customers may also seek to terminate drilling contracts if we experience operational problems. If our equipment fails to function properly and cannot be repaired promptly, we will not be able to engage in drilling operations, and customers may have the right to terminate the drilling contracts. The cancellation or renegotiation of a number of our drilling contracts could adversely affect our financial performance.

We rely on a small number of customers, and the loss of a significant customer could adversely affect us.

A substantial percentage of our revenues are generated from a relatively small number of customers, and the loss of a major customer would adversely affect us. In 2006, ExxonMobil accounted for approximately 14 percent of our total revenues, and Chevron, for approximately 8 percent of our total revenues. Our ten most significant customers collectively accounted for approximately 52 percent of our total revenues in 2006. 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 strong demand for our rental tools for the foreseeable future. However, if commodity prices decline or other factors adversely affect demand for drilling activity, our utilization rates and financial performance will be adversely affected. Contract drilling companies compete primarily on a regional basis, and competition may vary significantly from region to region at any particular time. Many drilling and workover rigs can be moved from one region to another in response to changes in levels of activity, provided market conditions warrant, which may result in an oversupply of rigs in an area. Many competitors have begun new rig construction programs in response to recent energy price levels. In many markets in which we operate, the number of rigs available has historically exceeded the demand for rigs for extended periods of time, resulting in intense price competition. Most drilling and workover contracts are awarded on the basis of competitive bids, which also results in price competition. 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 existing and emerging competitors. Many of our competitors in both the contract drilling and rental tools business possess significantly greater financial resources than we do.

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

11

ITEM 1A.  RISK FACTORS (continued)

Risk Factors Related to Our Business (continued)

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

We have operations in 13 foreign countries. Our international operations are subject to interruption, suspension and possible expropriation due to terrorism, war, civil disturbances, political instability and similar events and we have previously suffered loss of revenue and damage to equipment due to political violence. We may not be able to obtain insurance policies covering such risks, especially political violence coverage, or such policies may only be available with premiums that are not commercially justifiable.

Our international operations are also subject to governmental regulation and other risks.

We derive a significant portion of our revenues from our international operations. In 2006, we derived approximately 47 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.

Our international operations are subject to the laws and regulations of a number of foreign countries. Additionally, our ability to compete in international contract drilling markets may be adversely affected by foreign governmental regulations or other policies that favor the awarding of contracts to contractors in which nationals of those foreign countries have substantial ownership interests. Furthermore, our foreign subsidiaries may face governmentally imposed restrictions or fees from time to time on the transfer of funds to us. While we have been successful in most cases in contractually limiting these risks by transferring the risk of loss to the operators, we cannot completely eliminate such risk.

A significant portion of the workers we employ in our international operations are members of labor unions or otherwise subject to collective bargaining. We may not be able to hire and retain a sufficient number of skilled and experienced workers for wages and other benefits that we believe are commercially reasonable.

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

Our international operations are also subject to disruption due to risks associated with worldwide health concerns. In particular, although we have no evidence to believe this will occur, it is possible that concerns due to the transmission of avian flu could result in cancellations or delays in international flightsand/or the quarantine of drilling crews in foreign locations, which could materially impair our international operations

12

ITEM 1A.  RISK FACTORS (continued)

Risk Factors Related to Our Business (continued)

and consequently have an adverse effect on our business and financial results for the operations that are affected.

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

Tax and other laws and regulations are not always interpreted consistently among local, regional and national authorities. For example, we currently have a case pending in the Supreme Court involving an assessment of US$61.9 million in income taxes based on $99 million of reimbursements received to upgrade Rig 257 prior to its importation into Kazakhstan. The Supreme Court of Kazakhstan has on two previous occasions ruled that this reimbursement is not income to Parker and thus not subject to tax in Kazakhstan, but the Ministry of Finance (“MinFin”) of Kazakhstan continues to re-assess taxes on the same amount. The latest assessment of MinFin was in October 2005, which was appealed to the Supreme Court. Contrary to its two earlier rulings, in May 2006 the Supreme Court ruled in favor of MinFin. Parker received an immediate stay of execution of this ruling pending a determination of the Supreme Court whether or not to grant supervisory review of this ruling. The Supreme Court has delayed any action on supervisory review pending a meeting of the Competent Authorities of MinFin and the U.S. Treasury, which is a tax treaty procedure to resolve disputes as to which country may tax income covered under the treaty. The Competent Authorities are currently scheduled to meet on March 20, 2007. The Supreme Court is scheduled to meet on March 31, 2007. See Note 12 to the notes to the consolidated financial statements. 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 drilling contractor’s fault. To the extent that we are unable to transfer such risks to customers by contract or indemnification agreements, we generally seek protection through insurance. However, we have 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 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,

13

ITEM 1A.  RISK FACTORS (continued)

Risk Factors Related to Our Business (continued)

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. We undertake all reasonable steps to defend ourselves in such lawsuits. However, there can be no assurance as to the ultimate outcome of such lawsuits, in which case the Company could suffer material adverse consequences.

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 thisForm 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

14

ITEM 1A.  RISK FACTORS (continued)

Risks Related to Our Common Stock (continued)

Certificate of Incorporation provides for a staggered Board of Directors and permits the Board of Directors, without stockholder approval, to issue additional shares of common stock or a new series of preferred stock.

Risks Related to our Debt Securities

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

We have granted the lenders under our senior secured credit facility a security interest in (i) all accounts receivable, and certain deposit accounts, of (a) Parker Drilling Company and (b) substantially all of our material direct and indirect domestic subsidiaries; and (ii) substantially all of the rental tool 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. As of December 31, 2006, our non-guarantor subsidiaries and joint ventures collectively owned approximately 11.6 percent of our consolidated total assets and held approximately $17.8 million of our consolidated cash and cash equivalents of approximately $92.2 million. See Note 5 to the notes to the consolidated financial statements.

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

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

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

15

ITEM 1A.  RISK FACTORS (continued)

•  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.

16

ITEM 1A.  RISK FACTORS (continued)

DISCLOSURE NOTE REGARDING FORWARD-LOOKING STATEMENTS

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

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

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

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

•  our future operating results and profitability;

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

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

•  growth through acquisitions of companies or assets;

•  construction or upgrades of rigs;

•  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;

•  the availability of insurance coverage for pending future claims;

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

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

•  organic growth of our operations.

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

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

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

•  fluctuations in the market prices of oil and gas;

•  imposition of unanticipated trade restrictions;

17

ITEM 1A.  RISK FACTORS (continued)

DISCLOSURE NOTE REGARDING FORWARD-LOOKING STATEMENTS (continued)

•  unanticipated operating hazards and uninsured risks;

•  political instability, terrorism or war;

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

•  adverse environmental events;

•  adverse weather conditions;

•  changes in the concentration of customer and supplier relationships;

•  unexpected cost increases for upgrade and refurbishment projects;

•  delays in obtaining components for capital projects;

•  shortages of skilled labor;

•  unanticipated cancellation of contracts by operators without cause;

•  breakdown of equipment and other operational problems;

•  changes in competition; and

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

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

18

ITEM 1B.   UNRESOLVED STAFF COMMENTS

None.

ITEM 2.   PROPERTIES

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, 2006, the locations and drilling depth ratings of our 24 land rigs available for service. Thirteen of these rigs were under contract and the remainder were available for contract as of December 31, 2006.

	Drilling Depth Rating in Feet
	10,000		10,000-		Over
Region	or Less		25,000		25,000		Total
Asia Pacific		1		8		—		9
CIS (1)		—		5		3		8
Latin America		—		—		3		3
United States		—		2		1		3
Africa/Middle East		—		—		1		1
Total		1		15		8		24

(1) Two rigs are owned by AralParker.

Barge Rigs

The following table shows our two international deep drilling barges as of December 31, 2006. Both of these rigs were under contract at December 31, 2006.

			Year Built		Maximum
			or Last		Drilling
International (1)	Horsepower		Refurbished		Depth (Feet)
Caspian Sea:
Rig No. 257		3,000		1999		30,000
Mexico:
Rig No. 53		1,600		2004		20,000

(1) Two barge rigs in Nigeria were sold in September 2006.

19

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. Twelve of these barge rigs were under contract and the remainder were available for contract as of December 31, 2006.

			Year Built		Maximum
			or Last		Drilling
U.S.	Horsepower		Refurbished		Depth (Feet)
Deep drilling:
Rig No. 12(3)		1,500		2006		20,000
Rig No. 15		1,000		1998		15,000
Rig No. 50		2,000		2006		25,000
Rig No. 51		2,000		2003		25,000
Rig No. 54		2,000		2006		25,000
Rig No. 55		2,000		2001		25,000
Rig No. 56		2,000		2005		25,000
Rig No. 72		3,000		2002		30,000
Rig No. 76		3,000		2004		30,000
Rig No. 77		3,000		2006		30,000
Intermediate drilling:
Rig No. 8		1,000		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)(2)		650		1996		—
Rig No. 16		1,000		1994		13,500
Rig No. 23		1,000		1993		13,000
Rig No. 26 (1)(2)		650		2005		—

(1)	Workover rig.
(2)	Rigs 9 and 26 were sold on January 2, 2007.
(3)	Rig 12 was upgraded from a workover barge to a deep drilling barge in 2006.

20

ITEM 2.  PROPERTIES (continued)

The following table presents our utilization rates and rigs available for service for the years ended December 31, 2006 and 2005.

	Year Ended December 31,
Transition Zone Rig Data	2006			2005
U.S. barge deep drilling:
Rigs available for service (1)		9.6			8.8
Utilization rate of rigs available for service (2)		81	%		92	%
U.S. barge intermediate drilling:
Rigs available for service (1)		4.0			4.0
Utilization rate of rigs available for service (2)		72	%		74	%
U.S. barge workover and shallow drilling:
Rigs available for service (1)		5.4			6.0
Utilization rate of rigs available for service (2)		53	%		56	%
International barge drilling:
Rigs available for service (1)		3.2			4.2
Utilization rate of rigs available for service (2)		100	%		96	%
U.S. Land Rig Data
Rigs available for service (1):		0.8			—
Utilization rate of rigs available for service (2):		80	%		—
International Land Rig Data
Rigs available for service (1):		23.1			29.9
Utilization rate of rigs available for service (2):		63	%		75	%

(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 calculated 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 onForm 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 2006.

21

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 Jr., 58, chairman, 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, and was elected chairman in April 2006. He has been a director since 1973.
(2)	David C. Mannon, 49, 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.
(3)	W. Kirk Brassfield, 51, senior vice president and chief financial officer, joined Parker Drilling in March 1998 as controller and principal accounting officer. From 1991 through March 1998, Mr. Brassfield served in various positions, including subsidiary controller and director of financial planning of MAPCO Inc., a diversified energy company. From 1979 through 1991, Mr. Brassfield served at the public accounting firm, KPMG.
(4)	Denis J. Graham, 57, vice president of engineering, joined Parker Drilling in 2000. Mr. Graham was previously the senior vice president of technical services for Diamond Offshore Inc., an international offshore drilling contractor. His experience with Diamond Offshore ranged from 1978 through 1999 in the areas of offshore drilling rig design, new construction, conversions, marine operations, maintenance and regulatory compliance.
(5)	Ronald C. Potter, 53, vice president and general counsel, re-joined Parker Drilling in June 2003. From 2001 through May 2003, Mr. Potter was our outside legal counsel as a shareholder of Conner & Winters, P.C. in Tulsa, Oklahoma. From 1980 to 2001, he served Parker Drilling in various positions, most recently as chief legal counsel and corporate secretary.
(6)	Lynn G. Cullom, 52, 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.
(7)	Michael D. Drennon, 51, vice president of 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

(8)  David W. Tucker, 51, 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.

22

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, 2006, there were 2,079 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:

	2006				2005
Quarter	High		Low		High		Low
First	$	12.44	$	8.07	$	6.15	$	3.75
Second		9.84		6.10		7.21		4.50
Third		7.65		6.25		9.66		6.79
Fourth		10.05		6.50		11.82		7.41

Substantially all of our stockholders maintain their shares in “street name” accounts and are not, individually, stockholders of record. As of January 31, 2007, our common stock was held by 2,073 holders of record and an estimated 27,715 beneficial owners.

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 25, 2007, is incorporated herein by reference.

We purchased 42,948 shares at a price per share of $8.74 on May 6, 2006, 4,409 shares at a price of $6.32 on June 19, 2006 and 661 shares at a price of $6.64 on September 18, 2006 from Parker Drilling executives, which shares were tendered by executives to the Company to satisfy tax liabilities when portions of restricted stock grants issued in May 2005 and September 2006 vested. Upon vesting of the restricted shares, tax withholding obligations were satisfied by the executives delivering back to Parker Drilling some of the shares on which the restrictions had lapsed.

On January 18, 2006 in coordination with Lehman Brothers, Inc., our underwriters, we issued 8,900,000 shares of our common stock 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 underwriting discounts and commissions of $1.1 million, from the offering.

23

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, 2006. The following financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes appearing elsewhere in thisForm 10-K.

	Year Ended December 31,
	2006 (1)		2005 (2)		2004			2003 (3)			2002 (4)
	(Dollars in Thousands, Except Per Share Amounts)
Income Statement Data
Total drilling and rental revenues	$	586,435	$	531,662	$	376,525		$	338,653		$	385,714
Total operating income		143,326		115,123		23,867			22,927			38,556
Income (loss) from continuing operations		81,026		98,812		(50,565	)		(52,434	)		(21,193	)
Net income (loss)		81,026		98,883		(47,083	)		(109,699	)		(114,054	)
Basic earnings (loss) per share:
Income (loss) from continuing operations	$	0.76	$	1.03	$	(0.54	)	$	(0.56	)	$	(0.23	)
Net income (loss)	$	0.76	$	1.03	$	(0.50	)	$	(1.17	)	$	(1.23	)
Diluted earnings (loss) per share:
Income (loss) from continuing operations	$	0.75	$	1.02	$	(0.54	)	$	(0.56	)	$	(0.23	)
Net income (loss)	$	0.75	$	1.02	$	(0.50	)	$	(1.17	)	$	(1.23	)
Balance Sheet Data
Cash and cash equivalents	$	92,203	$	60,176	$	44,267		$	67,765		$	51,982
Marketable securities		62,920		18,000		—			—			—
Property, plant and equipment, net		435,473		355,397		382,824			387,664			641,278
Assets held for sale		4,828		—		23,665			150,370			896
Total assets		901,301		801,620		726,590			847,632			953,325
Total long-term debt and capital leases, including current portion		329,368		380,015		481,063			571,625			589,930
Stockholders’ equity		459,099		259,829		148,917			192,803			300,626

(1)	The 2006 results reflect the reversal of a $12.6 million valuation allowance at the end of 2006 and the current year utilization of $5.4 million of NOL’s, both related to Louisiana State net operating loss carryforwards. See Note 7 in the notes to the consolidated financial statements.
(2)	The 2005 results reflect the reversal of a $71.5 million valuation allowance related to federal net operating loss federal carryforwards and other deferred tax assets. See Note 7 in the notes to the consolidated financial statements.
(3)	In June 2003, we recognized a $53.8 million impairment charge in discontinued operations related to our plan to sell the U.S. Gulf of Mexico offshore assets. See Note 2 in the notes to the consolidated financial statements.
(4)	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.

24

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

RESULTS OF OPERATIONS

Overview — Our U.S. Gulf of Mexico operations and rental tools business shouldered our 24 percent increase in operating results for 2006 over 2005 giving us the opportunity to provide improved performance even as we transition our international operations to new long-term contracts. Demand for our services continued to be robust in spite of the wide fluctuation in energy commodity prices experienced throughout 2006. We expect to have continued strong results in 2007 as well.

Drilling and rental operating income was up $45.3 million, even though overall drilling operations utilization was 69.1 percent, down from 78 percent in 2005. Dayrates in the U.S. Gulf of Mexico market increased 54 percent, and we moved two land rigs into the U.S. land market from Mexico at significantly higher dayrates. Utilization in the U.S. markets was down slightly at 71.1 percent in 2006 from 76.7 percent in 2005, as we had downtime for barge Rig 12 while we upgraded it from workover to deep drilling status and completed planned maintenance and improvements for three other barge rigs. Our new ultra-deep drilling barge, Rig 77 which is capable of drilling in both ultra shallow and open water commenced operation in December under two consecutive three-month terms. Rental tools revenues also improved providing a $16.5 million increase in operating profit.

In international markets, we had 67.3 percent utilization in 2006 (78.0 percent in 2005) as 13 rigs (7 Mexico, 3 Kazakhstan and 3 Turkmenistan) in our existing fleet completed long-term contracts and experienced downtime as the rigs were repositioned to new markets. In addition we sold our two Nigerian barge rigs in August 2006. Four land rigs transitioned from Mexico to new contracts, two to the U.S. and two to Colombia, all of which commenced in 2006. Rig 107, released from our Tengiz Chevroil (“TCO”) contract and Rig 236, released in Turkmenistan, both returned to work under new contracts in 2006. Rig 53 in Mexico had no downtime as we negotiated a new, nine-month contract in June and subsequently a new two-year contract effective in March 2007 at current market rates. We also had strong results in Papua New Guinea and Bangladesh and on our Operations and Maintenance (“O&M”) contracts in Russia as all of these operations were in place all year.

Benefits from our debt reduction program initiative continued to pay off in 2006 as interest expense declined by $10.5 million and debt extinguishment costs by $6.3 million during 2006 versus 2005 on debt reductions of $50.6 million in 2006, following the $100.1 million and $90.6 million reductions accomplished during 2005 and 2004, respectively. Gains on sales of assets declined as 2006 sales reflect primarily our corporate strategy to exit Nigeria. Sales in 2005 included the wrap up of our asset sales program that was an integral part of our debt reduction program.

Outlook — Strong results are anticipated in 2007 as our U.S. operations are expected to be steady throughout 2007. Drilling barge Rig 50 completed its refurbishment program in November and began operating under a six month contract, and Rig 8 will begin a10-month contract in April. We will also have the benefit of our new rental tool facility that will open in Texarkana in March 2007 to serve the Barnett and Fayetteville shale areas in East Texas and Oklahoma, respectively.

In addition to the benefit of a full-year of long-term international contracts negotiated in 2006, we expect our working rig count in the CIS region to grow by three rigs during the third quarter. Once upgrades are completed on Rig 247, a fourth rig could re-enter that market by the second quarter of 2007. We expect both rigs in Papua New Guinea to operate all of 2007. Rig 188 contract terms were extended for two years to drill in New Zealand. We are pursuing several projects in Mexico and our Africa/Middle East region, including expansion into Libya.

We will have grown our fleet by over 20 percent over 2006 with newly constructed rigs and rigs under joint venture projects. Two of our four new 2,000 HP rigs were delivered to Algeria in early 2007 and are expected to commence operations in the first and second quarters. Our joint venture in Saudi Arabia, which

25

RESULTS OF OPERATIONS (continued)

Outlook(continued)

has a drilling contract for three years with a one-year extension option, has expanded from four rigs to six. Expected spud dates for these rigs range from the second quarter of 2007 through the end of 2007.

In August 2006, we were awarded a technical service project to provide the conceptual design for a drilling rig for use in BP’s Liberty Field in the Alaskan Beaufort Sea. In January 2007, we expanded this contract with BP to design and procure long lead-time equipment for the rig. This rig will initially be located on a satellite drilling island and will be capable of drilling extended-reach wells in excess of 40,000 feet.

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 three years. To mitigate the risks from future changes in market conditions, we have been negotiating longer-term contracts in U.S. markets where possible. In international markets, contracts are generally longer term and insulate us somewhat from short-term price fluctuations. Over extended periods, however, international market conditions typically follow the demand for oil. Under our strategic plan, we have embarked on a construction program to build preferred rigs that will remain in demand regardless of business cycle that should help us maintain high utilization in periods of lower drilling activity. We also leverage ourselves with our significant international experience and our safety record, which continues to be one of the lowest total incident rates in our industry from a safety, training and preventive maintenance perspective. Our safety record continues to be one of the best in our industry.

International markets also present the challenges of foreign regulation and civil unrest, which we continually monitor and apply risk management strategies to minimize. Our rigs are also subject to a range of potential incidents. Although we insure against these risks, the cost and availability of insurance are subject to significant change that is not subject to our control. We continuously refine our quality assurance, health, safety and environmental programs to help prevent future well-control incidents.

Our operating margins must also cover interest expense and income taxes. We have significantly reduced our interest and financial costs with approximately $240 million of debt reduction and subsequent lowering of interest expense over the last three years. We are currently completing a worldwide corporate reorganization that is designed to help us more efficiently manage our operations. The reorganization will also help us achieve greater tax efficiencies through the establishment of a holding Company structure based in The Netherlands. Laws in various jurisdictions will continue to evolve, and the Company will continue to review and adapt as necessary.

While many of our current rig construction projects are coming into fruition early in 2007, we do face delay, cost overrun and quality risks with regard to our rig construction projects. We manage these risks through contractual provisions and project management strategies. All major components have detailed specifications and construction standards that must be met before we accept delivery.

Retaining qualified, trained crews to operate our rigs has been challenging globally, with the increase in the number of rigs operating, creating competing job opportunities for our personnel. We have responded with competitive compensation programs designed to reduce attrition for critical personnel. In addition, with our training programs and facilities, we are able to promote from within and will continue to emphasize these training programs and our safety record to attract the necessary personnel.

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

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

26

RESULTS OF OPERATIONS (continued)

December 31, 2005. Gain on disposition of assets was $7.6 million for the 2006 period as compared to $25.6 million for the 2005 period.

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

	Year Ended December 31,
	2006				2005
	(Dollars in Thousands)
Drilling and rental revenues:
U.S. drilling	$	191,225		33%	$	128,252		24%
International drilling		273,216		46%		308,572		58%
Rental tools		121,994		21%		94,838		18%
Total drilling and rental revenues	$	586,435		100%	$	531,662		100%
Drilling and rental operating income:
U.S. drilling gross margin excluding depreciation and amortization (1)	$	107,763		56%	$	61,425		48%
International drilling gross margin excluding depreciation and amortization (1)		53,506		20%		71,411		23%
Rental tools gross margin excluding depreciation and amortization (1)		75,540		62%		56,627		60%
Depreciation and amortization		(69,270	)			(67,204	)
Total drilling and rental operating income (2)		167,539				122,259
General and administrative expense		(31,786	)			(27,830	)
Provision for reduction in carrying value of certain assets		—				(4,884	)
Gain on disposition of assets, net		7,573				25,578
Total operating income	$	143,326			$	115,123

(1) Drilling and rental gross margins, excluding depreciation and amortization, are computed as drilling and rental revenues less direct drilling and rental operating expenses, excluding depreciation and amortization expense; drilling and rental gross margin percentages are computed as drilling and rental gross margin excluding depreciation and amortization as a percent of drilling and rental revenues. The gross margin amounts excluding depreciation and amortization and gross margin percentages should not be used as a substitute for those amounts reported under accounting principles generally accepted in the United States (“GAAP”). However, we monitor our business segments based on several criteria, including drilling and rental gross margin. Management believes that this information is useful to our investors because it more accurately reflects cash generated by segment. Such gross margin amounts are reconciled to our most comparable GAAP measure as follows:

			International
	U.S. Drilling		Drilling		Rental Tools
	(Dollars in Thousands)
Year Ended December 31, 2006
Drilling and rental operating income (2)	$	83,370	$	27,465	$	56,704
Depreciation and amortization		24,393		26,041		18,836
Drilling and rental gross margin excluding depreciation and amortization	$	107,763	$	53,506	$	75,540
Year Ended December 31, 2005
Drilling and rental operating income (2)	$	41,739	$	40,281	$	40,239
Depreciation and amortization		19,686		31,130		16,388
Drilling and rental gross margin excluding depreciation and amortization	$	61,425	$	71,411	$	56,627

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

27

RESULTS OF OPERATIONS (continued)

U.S. Drilling Segment

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

As of December 31, 2006 this segment consisted of 19 barge rigs: ten deep drilling barge rigs, four intermediate drilling barge rigs and five workover barge rigs; and two land rigs. Two of the workover barge rigs are reflected as assets held for sale as of December 31, 2006 and were sold in early January 2007 (see Note 2 in the notes to the consolidated financial statements for further details).

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

International Drilling Segment

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

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

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

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

28

RESULTS OF OPERATIONS (continued)

International Drilling Segment (continued)

$1.8 million in New Zealand due primarily to lower operating and reimbursable revenues relating to Rig 188 which was idle during the second quarter of 2006.

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

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

Rental Tools Segment

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

Other Financial Data

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

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

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

In 2004, we entered into twovariable-to-fixed interest rate swap agreements, which are still outstanding. The swap agreements do not qualify for hedge accounting and accordingly, we are reporting themark-to-market change in the fair value of the interest rate derivatives currently in earnings. For 2006, there was no significant change in the fair value of the derivative positions and for 2005, there was a $2.1 million increase in fair value during the year. For additional information see Note 6 in the notes to the consolidated financial statements.

Income tax expense from continuing operations is $36.4 million and consists of U.S. federal current tax expense of $13.0 million and U.S. federal and state deferred tax expense of $17.8 million, current foreign tax expense of $7.6 million and foreign deferred tax benefit of $2.1 million for the year ended December 31, 2006. Income tax benefit from continuing operations is $28.6 million and consists of U.S. federal current tax expense of $1.8 million and U.S. federal deferred benefit of $46.5 million, current foreign tax expense of $14.5 million and foreign deferred tax benefit of $1.6 million for the year ended December 31, 2005. Our effective income tax rates for financial reporting purposes were approximately 31 percent and (41) percent for

29

RESULTS OF OPERATIONS (continued)

Other Financial Data (continued)

the years ended December 31, 2006 and 2005, respectively. The 2006 effective tax rate of 31 percent is lower than the US federal and State statutory rates due primarily to the 2006 benefit of $12.6 million related to the State net operating loss (“NOL”) carryforwards and the current year utilization of $5.4 million of State NOL’s. Our effective tax rate of (41%) in 2005 is primarily due to the reversal of the $71.5 million valuation allowance related to federal NOL carryforwards. Foreign taxes decreased $6.9 million in 2006 due primarily to a reduction of taxes in Kazakhstan, South America and Nigeria offset by an increase in taxes associated with continuing operations in New Zealand, Mexico and Russia. U.S. taxes are provided on earnings of foreign corporations since we do not defer recognition of income under APB No. 23, “Accounting for Income Taxes — Special Areas.”

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.

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

	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 excluding depreciation and amortization (1)	$	61,425		48	%	$	34,386		39	%
International drilling gross margin excluding depreciation and amortization (1)		71,411		23	%		52,395		24	%
Rental tools gross margin excluding depreciation and amortization (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, excluding depreciation and amortization, are computed as drilling and rental revenues less direct drilling and rental operating expenses, excluding depreciation and amortization expense; drilling and rental gross margin percentages are computed as drilling and rental gross margin excluding depreciation and amortization as a percent of drilling and rental

30

RESULTS OF OPERATIONS (continued)

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 accurately reflects cash generated by segment. Such gross margin amounts are reconciled to our most comparable GAAP measure as follows:

			International
	U.S. Drilling		Drilling		Rental Tools
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 excluding depreciation and amortization	$	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 excluding depreciation and amortization	$	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.

U.S. Drilling Segment

U.S. drilling revenues increased $39.7 million in 2005 to $128.3 million due to higher utilization and dayrates. 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, in the fourth quarter of 2005.

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 excluding depreciation and amortization 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 excluding depreciation and amortization increased by $19.0 million to $71.4 million due to a $12.6 million increase for international offshore and $6.4 million for international land operations.

International land drilling results in 2005 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.

31

RESULTS OF OPERATIONS (continued)

International Drilling Segment (continued)

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 excluding depreciation and amortization 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 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 excluding depreciation and amortization 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 before depreciation and amortization 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 before depreciation and amortization 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 excluding depreciation and amortization increased $17.5 million due to the increased volume of business and granting of fewer discounts off listed rental prices.

32

RESULTS OF OPERATIONS (continued)

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 Sr., former 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, 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.

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 in Nigeria and $2.8 million on sale of tubulars and scrap equipment.

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 twovariable-to-fixed interest rate swap agreements. The swap agreements do not qualify for hedge accounting and accordingly, we are reporting themark-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

33

RESULTS OF OPERATIONS (continued)

Other Financial Data (continued)

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 had 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 benefit 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 offset by an increase in taxes related to the sale of the Latin America 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 federal 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.

Analysis of Discontinued Operations

	Year Ended December 31,
	2005		2004
	(Dollars in Thousands)
U.S jackup and platform drilling operating income (loss)	$	100	$	7,720
Depreciation and amortization		—		—
Drilling gross margin	$	100	$	7,720

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.

34

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

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

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

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.

Financing Activity

In January 2006 we issued 8,900,000 shares of our common stock, realizing $11.23 per share or a total of $99.9 million of net proceeds before expenses, but after underwriter discount, from the offering. Proceeds from this offering are being used for capital expansions, including rig upgrades, new rig construction and expansion of our rental tools business.

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

Our 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 requires a borrowing

35

LIQUIDITY AND CAPITAL RESOURCES (continued)

Financing Activity (continued)

base calculation only when the credit facility has outstanding loans, including letters of credit, totaling at least $25.0 million. As of December 31, 2006, there were $23.1 million in letters of credit outstanding and no loans. On March 1, 2006, an amendment was signed to eliminate the $25.0 millionsub-limit for letters of credit and to give us the ability to call outstanding Senior Notes and Senior Floating Rate Notes without limitation concerning commitments, including letters of credit, under the credit facility.

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

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

On the same date that we issued the $50.0 million additional 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 of the $50.0 million 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 $329.4 million as of December 31, 2006. The long-term debt included:

•  $100.0 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 $4.4 million in unamortized debt premium.

As of December 31, 2006, we had approximately $172.0 million of liquidity. This liquidity was comprised of $155.1 million of cash, cash equivalents and marketable securities on hand and $16.9 million of availability under the revolving credit facility. We do not have any unconsolidated special-purpose entities, off-balance-sheet financing arrangements or guarantees of third-party financial obligations. We have no energy or commodity contracts.

36

LIQUIDITY AND CAPITAL RESOURCES (continued)

Financing Activity (continued)

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)	$	325,000	$	—	$	—	$	100,000	$	225,000
Long-term debt — interest (1)		178,440		30,370		60,973		49,199		37,898
Operating leases (2)		11,008		4,958		4,650		1,227		173
Purchase commitments (3)		62,484		62,484		—		—		—
Total contractual obligations	$	576,932	$	97,812	$	65,623	$	150,426	$	263,071
Commercial commitments:
Revolving credit facility (4)	$	—	$	—	$	—	$	—	$	—
Standby letters of credit(4)		23,061		23,061		—		—		—
Total commercial commitments	$	23,061	$	23,061	$	—	$	—	$	—

(1)	Long-term debt includes the principal and interest cash obligations of the 9.625% Senior Notes but the remaining unamortized premium of $4.4 million is not included in the contractual cash obligations schedule. A portion of the interest on the Senior Floating Rate Notes has been fixed throughvariable-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. See Note 4 and 6 in the notes to the consolidated financial statements.
(2)	Operating leases consist of lease agreements in excess of one year for office space, equipment, vehicles and personal property. See Note 12 in the notes to the consolidated financial statements.
(3)	We have purchase commitments outstanding as of December 31, 2006, related to rig upgrade projects and new rig construction.
(4)	We have a $40.0 million revolving credit facility. As of December 31, 2006 no amounts have been drawn down, but $23.1 million of availability has been used to support letters of credit that have been issued, resulting in an estimated $16.9 million availability. The revolving credit facility expires in December 2007. See Note 4 in the notes to the consolidated financial statements.

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 accessand/or involve harsh environmental conditions. Our international services are primarily utilized by major and national oil companies and integrated service providers in the exploration and development of reserves of oil and gas. In the United States, we primarily drill in the transition zones of the U.S. Gulf of Mexico for major and independent oil and gas companies. Business activity is primarily dependent on the exploration and development activities of the companies that make up our customer base. See Item 1A 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

37

OTHER MATTERS (continued)

Critical Accounting Policies (continued)

financial statements and the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, we evaluate our estimates, including those related to bad debts, materials and supplies obsolescence, property and equipment, goodwill, income taxes, workers’ compensation and health insurance and contingent liabilities for which settlement is deemed to be probable. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. While we believe that such estimates are reasonable, actual results could differ from these estimates.

We believe the following are our most critical accounting policies as they are complex and require significant judgments, assumptionsand/or estimates in the preparation of our consolidated financial statements. Other significant accounting policies are summarized in Note 1 in the notes to the consolidated financial statements.

Impairment of Property, Plant and Equipment.  We periodically evaluate our property, plant and equipment to ensure that the net 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 and $13.1 million in 2005 and 2004, 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.

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

As required by SFAS No. 142, “Goodwill and Other Intangible Assets,” we perform an annual impairment analysis of goodwill. Our annual impairment tests of goodwill for 2004, 2005 and 2006 indicated that the fair value of operations to which goodwill relates exceeded the carrying values as of December 31, 2004, 2005 and 2006; 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

38

OTHER MATTERS (continued)

Critical Accounting Policies (continued)

responsibilities between a drilling company and its customer, and we seek to obtain indemnification from our customers by contract for certain of these risks. To the extent that we are unable to transfer such risks to customers by contract or indemnification agreements, we seek protection through insurance. However, there is no assurance that such insurance or indemnification agreements will adequately protect us against liability from all of the consequences of the hazards described above. Moreover, our insurance coverage generally provides that we assume a portion of the risk in the form of an insurance coverage deductible.

Based on the risks discussed above, we estimate our liability in excess of insurance coverage and record reserves for these amounts in our consolidated financial statements. Reserves related to insurance are based on the facts and circumstances specific to the insurance claims and our past experience with similar claims. The actual outcome of insured claims could differ significantly from the amounts estimated. We accrue actuarially determined amounts in our consolidated balance sheet to cover self-insurance retentions for workers’ compensation, employers’ liability, general liability, automobile liability claims and health benefits. These accruals use historical data based upon actual claim settlements and reported claims to project future losses. These estimates and accruals have historically been reasonable in light of the actual amount of claims paid.

As the determination of our liability for insurance claims could be material and is subject to significant management judgment and in certain instances is based on actuarially estimated and calculated amounts, management believes that accounting estimates related to insurance reserves are critical.

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

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

39

OTHER MATTERS (continued)

Critical Accounting Policies (continued)

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

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

In 2004, we entered into twovariable-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 amark-to-market basis in our consolidated statement of operations. For the year ended December 31, 2006, there was no significant change in the fair value of the interest rate derivatives. For the year ended December 31, 2005, we recognized a non-cash increase in the fair value of $2.1 million. These non-cash items are reported in the consolidated statement of operations as “Changes in fair value of derivative positions.”

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 monthly basis and record themark-to-market impact based on the analysis. For additional information see Note 6 in the notes to the consolidated financial statements.

Recent Accounting Pronouncements

In July 2006, FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109” (FIN 48), was issued. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new FASB standard provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, and the provisions are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the “more likely than not” recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN 48. The cumulative effect of applying the provisions of FIN 48 must be reported as an adjustment to the opening balance of retained earnings for that fiscal year. The Company is currently evaluating the impact of FIN 48 on its Consolidated Financial Statements. See Note 12 to the consolidated financial statements regarding Kazakhstan tax claims.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measures” (SFAS 157). SFAS 157 defines fair value, establishes a framework for measuring fair value and enhances disclosures about fair value measures required under other accounting pronouncements, but does not change existing guidance as to whether or not an instrument is carried at fair value. SFAS 157 is effective for fiscal years beginning after November 15, 2007 (i.e., the beginning of the Company’s fiscal year 2008). The Company is currently evaluating the impact of SFAS 157 on its Consolidated Financial Statements.

40

OTHER MATTERS (continued)

Recent Accounting Pronouncements (continued)

In September 2006, the SEC issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (SAB 108), which provides guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB 108 requires that the materiality of the effect of a misstated amount be evaluated on each financial statement and the related financial statement disclosures, and that the materiality evaluation be based on quantitative and qualitative factors. SAB 108 is effective for fiscal years ending after November 15, 2006. The adoption of this guidance did not have a material impact on the Company’s financial position, results of operations or cash flows.

41

ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

We entered into our currentvariable-to-fixed interest rate swap agreement as a strategy to manage the floating rate risk on our Senior Floating Rate Notes. On August 18, 2004, the swap agreement 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.

The swap agreement does not meet the hedge criteria in SFAS No. 133 and is, 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, 2006, 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	%	$	740
	September 1, 2005		September 4, 2007	$	50,000	Three-month LIBOR plus 475 basis points		8.48	%		582
										$	1,322

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 $246.7 million at December 31, 2006. The estimated fair value of our $100.0 million principal amount of Senior Floating Rate Notes due 2010 was $102.0 million on December 31, 2006.

42

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 consolidated financial statements and of its internal control over financial reporting as of December 31, 2006 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, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule 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, 2006 based on criteria established inInternal Control — Integrated Frameworkissued 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, 2006, based on criteria established inInternal Control — Integrated Frameworkissued 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

43

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (continued)

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 assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Houston, Texas

February 28, 2007

44

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

	Year Ended December 31,
	2006			2005			2004
Drilling and rental revenues:
U.S. drilling	$	191,225		$	128,252		$	88,512
International drilling		273,216			308,572			220,846
Rental tools		121,994			94,838			67,167
Total drilling and rental revenues		586,435			531,662			376,525
Drilling and rental operating expenses:
U.S. drilling		83,462			66,827			54,126
International drilling		219,710			237,161			168,451
Rental tools		46,454			38,211			28,037
Depreciation and amortization		69,270			67,204			69,241
Total drilling and rental operating expenses		418,896			409,403			319,855
Drilling and rental operating income		167,539			122,259			56,670
General and administration expense		(31,786	)		(27,830	)		(23,413	)
Provision for reduction in carrying value of certain assets		—			(4,884	)		(13,120	)
Gain on disposition of assets, net		7,573			25,578			3,730
Total operating income		143,326			115,123			23,867
Other income and (expense):
Interest expense		(31,598	)		(42,113	)		(50,368	)
Change in fair value of derivative positions		40			2,076			(794	)
Interest income		7,963			2,241			816
Loss on extinguishment of debt		(1,912	)		(8,241	)		(8,753	)
Minority interest		(229	)		1,905			(1,143	)
Other		(155	)		(763	)		819
Total other income and (expense)		(25,891	)		(44,895	)		(59,423	)
Income (loss) before income taxes		117,435			70,228			(35,556	)
Income tax expense (benefit):
Current tax expense		20,654			16,328			15,009
Deferred tax benefit		15,755			(44,912	)		—
Total income tax expense (benefit)		36,409			(28,584	)		15,009
Income (loss) from continuing operations		81,026			98,812			(50,565	)
Discontinued operations		—			71			3,482
Net income (loss)	$	81,026		$	98,883		$	(47,083	)
Basic earnings (loss) per share:
Income (loss) from continuing operations	$	0.76		$	1.03		$	(0.54	)
Discontinued operations	$	—		$	—		$	0.04
Net income (loss)	$	0.76		$	1.03		$	(0.50	)
Diluted earnings (loss) per share:
Income (loss) from continuing operations	$	0.75		$	1.02		$	(0.54	)
Discontinued operations	$	—		$	—		$	0.04
Net income (loss)	$	0.75		$	1.02		$	(0.50	)
Number of common shares used in computing earnings per share:
Basic		106,552,015			95,818,893			94,113,257
Diluted		108,138,384			97,208,345			94,113,257

See accompanying notes to the consolidated financial statements.

45

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

	December 31,
ASSETS	2006		2005
Current assets:
Cash and cash equivalents	$	92,203	$	60,176
Marketable securities		62,920		18,000
Accounts and notes receivable, net of allowance for bad debts of $1,481 in 2006 and $1,639 in 2005		112,359		104,681
Rig materials and supplies, net		15,000		18,179
Deferred costs		6,662		4,223
Deferred income taxes		17,307		12,018
Other current assets		11,123		64,058
Total current assets		317,574		281,335
Property, plant and equipment, at cost:
Drilling equipment		722,501		750,368
Rental tools		141,594		119,028
Buildings, land and improvements		17,365		17,448
Other		34,794		31,528
Construction in progress		89,869		23,193
		1,006,123		941,565
Less accumulated depreciation and amortization		570,650		586,168
Property, plant and equipment, net		435,473		355,397
Assets held for sale		4,828		—
Other assets:
Goodwill		100,315		107,606
Rig materials and supplies		5,654		2,819
Debt issuance costs		5,552		8,088
Deferred income taxes		13,405		34,449
Other assets		18,500		11,926
Total other assets		143,426		164,888
Total assets	$	901,301	$	801,620

See accompanying notes to the consolidated financial statements.

46

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

	December 31,
LIABILITIES AND STOCKHOLDERS’ EQUITY	2006			2005
Current liabilities:
Current portion of long-term debt	$	—		$	—
Accounts payable		35,223			31,909
Accrued liabilities		60,003			109,068
Accrued income taxes		6,677			9,778
Total current liabilities		101,903			150,755
Long-term debt		329,368			380,015
Other long-term liabilities		10,931			11,021
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 109,149,659 shares (97,836,254 shares in 2005)		18,220			16,306
Capital in excess of par value		568,253			456,135
Unamortized restricted stock plan compensation		—			(4,212	)
Accumulated deficit		(127,374	)		(208,400	)
Total stockholders’ equity		459,099			259,829
Total liabilities and stockholders’ equity	$	901,301		$	801,620

See accompanying notes to the consolidated financial statements.

47

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

	Year Ended December 31,
	2006			2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	81,026		$	98,883		$	(47,083	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		69,270			67,204			69,241
Amortization of debt issuance and premium		764			958			1,924
Loss on extinguishment of debt		910			935			2,657
Gain on disposition of assets		(7,573	)		(25,549	)		(3,620	)
Gain on disposition of marketable securities		—			—			(762	)
Provision for reduction in carrying value of certain assets		—			4,884			17,248
Deferred tax expense (benefit)		15,755			(44,912	)		—
Other		9,674			2,913			6,132
Change in assets and liabilities:
Accounts and notes receivable		(3,456	)		(568	)		(10,565	)
Rig materials and supplies		(2,605	)		(3,179	)		361
Other current assets		34,420			7,589			(30,735	)
Accounts payable and accrued liabilities		(28,143	)		18,218			12,749
Accrued income taxes		(3,101	)		(5,100	)		895
Other assets		(73	)		331			10,360
Net cash provided by operating activities		166,868			122,607			28,802
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(195,022	)		(69,492	)		(47,318	)
Proceeds from the sale of assets		50,790			61,046			51,053
Proceeds from insurance claims		4,501			13,850			41,566
Investment in joint venture		(10,000	)		—			—
Purchase of marketable securities		(198,120	)		(18,000	)		—
Proceeds from sale of marketable securities		153,200			—			1,377
Net cash provided by (used in) investing activities		(194,651	)		(12,596	)		46,678

See accompanying notes to the consolidated financial statements.

48

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

	Year Ended December 31,
	2006				2005			2004
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of debt	$	—			$	55,500		$	200,000
Principal payments under debt obligations		(50,000	)			(155,632	)		(290,206	)
Proceeds from common stock offering		99,947				—			—
Payment of debt issuance costs		—				(655	)		(10,243	)
Proceeds from stock options exercised		7,537				6,685			1,471
Excess tax benefit from stock-based compensation		2,326				—			—
Net cash provided by (used in) financing activities		59,810				(94,102	)		(98,978	)
Net increase (decrease) in cash and cash equivalents		32,027				15,909			(23,498	)
Cash and cash equivalents at beginning of year		60,176				44,267			67,765
Cash and cash equivalents at end of year	$	92,203			$	60,176		$	44,267
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest, net of amounts capitalized	$	30,898			$	41,308		$	49,181
Income taxes	$	21,566			$	13,415		$	15,062
Discontinued operations:
Depreciation	$	—			$	—		$	—
Loss on disposition of assets	$	—		��	$	29		$	110
Provision for reduction in carrying value of certain assets	$	—			$	—		$	4,128

See accompanying notes to the consolidated financial statements.

49

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, 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 income of $98,883)		—		—		—			—			—			98,883
Balances, December 31, 2005		97,836		16,306		456,135			(4,212	)		—			(208,400	)
Adoption of FAS 123R		—		—		(4,212	)		4,212			—			—
Activity in employees’ stock plans		2,414		431		9,031			—			—			—
Common stock offering		8,900		1,483		98,464			—			—			—
Excess tax benefit from stock based compensation		—		—		2,326			—			—			—
Amortization of restricted stock plan compensation		—		—		6,509			—			—			—
Net income (total comprehensive income of $81,026)		—		—		—			—			—			81,026
Balances, December 31, 2006		109,150	$	18,220	$	568,253		$	—		$	—		$	(127,374	)

See accompanying notes to the consolidated financial statements.

50

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 a subsidiary of Parker Drilling has a 50 percent stock ownership but exert control over both of the entities’ operations (collectively, the “Company”). A subsidiary of Parker Drilling also has a 50 percent interest in a joint venture, 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, 2006, the Company’s marketable rig fleet consists of 21 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 are deferred and amortized over the contract term.

Reimbursable Costs — The Company recognizes reimbursements received forout-of-pocket expenses incurred as revenues and accounts forout-of-pocket expenses as direct operating costs. Such amounts totaled $35.9 million, $41.3 million and $26.0 million during the years ended December 31, 2006, 2005 and 2004, respectively.

Cash and Cash Equivalents — For purposes of the consolidated balance sheet and the consolidated statement of cash flows, the Company considers cash equivalents to be highly liquid debt instruments that have a remaining maturity of three months or less at the date of purchase.

Marketable Securities — The Company 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 between June 2030 and December 2045, 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.

51

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 1 — Summary of Significant Accounting Policies (continued)

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

	December 31,
	2006			2005
	(Dollars in Thousands)
Trade	$	113,819		$	105,982
Employee (1)		21			338
Allowance for doubtful accounts (2)		(1,481	)		(1,639	)
Total receivables	$	112,359		$	104,681

(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, 2006, 2005 and 2004 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. Interest cost capitalized during 2006 related to the construction of rigs totaled $3.6 million. No interest was capitalized in 2005 or 2004. Expenditures for maintenance and repairs are charged to expense as incurred.

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 $4.3 million and $3.4 million at December 31, 2006 and 2005, 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 fees which are not expected to be paid or recognized within the next year.

52

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 1 — Summary of Significant Accounting Policies (continued)

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

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, 2006 and 2005, the Company had deposits in domestic banks in excess of federally insured limits of approximately $79.2 million and $68.1 million, respectively. In addition, the Company had deposits in foreign banks at December 31, 2006 and 2005 of $18.2 million and $10.2 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. In 2006, ExxonMobil accounted for approximately 14 percent of total revenues and Chevron accounted for approximately 8 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 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 amark-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 $246.7 million at December 31, 2006. The estimated fair value of the Company’s $100.0 million principal amount of Senior Floating Rate Notes due 2010 was $102.0 million on December 31, 2006. See Note 6 for fair value disclosure for derivative financial instruments.

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 — For periods prior to 2006, we accounted for stock-based compensation plans using the recognition and measurement principles of the Accounting Principles Board (“APB”) Opinion No. 25 “Accounting for Stock Issued to Employees,” and related interpretations. Under these principles no stock-based employee compensation cost related to stock options granted was reflected in net income, as all options granted under the various plans had exercise prices equal to or greater than the fair market value of the underlying common stock on the date of the grants. On January 1, 2006 we adopted the provisions of SFAS No. 123R, “Share-Based Payment” which requires that we include an estimate of the fair value of stock-based compensation costs related to stock options in net income. We elected the modified prospective transition method as permitted by SFAS 123R. Under this transition method, stock-based compensation expense includes (1) compensation expense for all stock-based compensation awards granted prior to, but not

53

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 1 — Summary of Significant Accounting Policies (continued)

yet vested as of December 31, 2005, based on the grant date fair value estimated in accordance with the original pro forma provisions of SFAS 123, “Accounting for Stock-Based Compensation” and (2) compensation expense for all stock-based compensation awards granted subsequent to December 31, 2005, based on the grant date fair value estimated in accordance with the provisions of SFAS 123R. As a result of adopting this standard, we were required to estimate forfeitures, and, if material, record a one-time cumulative effect of a change in accounting principal adjustment. As a result of our estimates, the adoption of this standard did not have a significant effect on our consolidated condensed financial statements and, as such, no adjustment was recorded. Also, in accordance with the modified prospective transition method, our consolidated condensed financial statements for prior periods have not been restated, and do not include the impact of SFAS 123R. The following table illustrates the effect on net income and net income per share as if we had applied the fair value based provisions of SFAS 123R for the periods ended December 31, 2005 and 2004.

	Year Ended December 31,
	2005			2004
	(Dollars in Thousands)
Net income (loss) as reported	$	98,883		$	(47,083	)
Stock-based compensation expense included in net income (loss) as reported		1,704			1,097
Stock-based compensation expense determined under fair value method		(1,855	)		(1,738	)
Net income (loss) pro forma	$	98,732		$	(47,724	)
Basic earnings (loss) per share:
Net income (loss) as reported	$	1.03		$	(0.50	)
Net income (loss) pro forma	$	1.03		$	(0.51	)
Diluted earnings (loss) per share:
Net income (loss) as reported	$	1.02		$	(0.50	)
Net income (loss) pro forma	$	1.02		$	(0.51	)

Under SFAS No. 123R, we continue to use the Black-Scholes option-pricing model to estimate the fair value of our stock options. Expected volatility is determined by using historical volatilities based on historical stock prices for a period that matches the expected term. The expected term of options represents the period of time that options granted are expected to be outstanding and typically falls between the options’ vesting and contractual expiration dates. The expected term assumption is developed by using historical exercise data adjusted as appropriate for future expectations. The risk-free rate is based on the yield at the date of grant of a zero-coupon U.S. Treasury bond whose maturity period equals the option’s expected term. The fair value of each option is estimated on the date of grant. The following is a summary of valuation assumptions for grants during the years ended December 31, 2006, 2005 and 2004:

	2006 (1)	2005	2004
Expected price volatility	16.90%	51.1%	60.0%
Risk-free interest rate range	4.23%	3.38%	1.95%-3.89%
Expected life of stock options	3 months	3-7 years	3-7 years

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

Options granted in 2006 were under the 2005 Long-Term Incentive Plan and had an estimated fair value of $82 thousand. Options granted in 2005 and 2004 under the 1997 Stock Plan had an estimated fair value of $50 thousand and $0.4 million, respectively. In November 2005, the Financial Accounting Standards Board (“FASB”) issued FASB Staff Position (“FSP”) No. FAS 123(R)-3, “Transition Election Related to Accounting

54

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 1 — Summary of Significant Accounting Policies (continued)

for the Tax Effects of Share-Based Payment Awards.” The alternative transition method includes simplified methods to establish the beginning balance of the additional paid-in capital pool (“APIC pool”) related to the tax effects of employee stock-based compensation, and to determine the subsequent impact on the APIC pool and consolidated condensed statements of cash flows of the tax effects of employee stock-based compensation awards that are outstanding upon adoption of SFAS No. 123R. We have elected to adopt the transition method described in FSP 123(R)-3. The tax benefit realized for the tax deductions from option exercises and restricted stock vesting totaled $2.3 million for the year ended December 31, 2006 which has been reported as a financing cash inflow in the consolidated condensed statement of cash flows. Cash received from option exercises for the year ended December 31, 2006 was $7.5 million. Refer to Note 8 for additional information about the Company’s stock plans.

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

Note 2 — Disposition of Assets

Discontinued Operations — Pursuant to a board approved plan to sell the Company’s Latin America assets and U.S. Gulf of Mexico offshore assets in 2003, the Company included these assets and related spare parts and inventories as discontinued operations beginning in 2003. 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 Latin America rigs and related spare parts sold in 2003 for $1.8 million.

In September 2003, jackup rig 14 (which was included in the discontinued operations) 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. Prior to the accident, the net book value of jackup rig 14 was $17.7 million. In the first quarter of 2004, the Company recorded the impairment of the assets and insurance recovery in discontinued operations. 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 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 Company decided 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

55

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 2 — Disposition of Assets (continued)

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,
	2006		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
Depreciation and amortization		—		—			—
Loss on disposition of assets, net of gains and impairment		—		(29	)		(4,238	)
Income from discontinued operations	$	—	$	71		$	3,482

Disposition of Assets — In September 2006, we finalized the sale of Nigerian barge rigs and related assets for proceeds of $46.0 million, resulting in a gain of $1.8 million. On May 6, 2005 the Company entered into definitive agreements with affiliates of Saxon Energy Services, Inc. (“Saxon”) to sell its seven remaining land rigs and related assets in Colombia and Peru for a total purchase price of $34 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 adjustment to the impairment of $3.4 million originally 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. As the rig was immediately rendered a total loss by our insurer in early July, the Company wrote off the net book value of the rig of $5.6 million and recorded insurance proceeds of $13.8 million, the insured value of assets destroyed, resulting in a gain of $8.2 million in the second quarter of 2005. Another $2.3 million gain was recognized in the fourth quarter of 2005. As we received partial settlement from our insurance accident site cleanup and settled on rig materials and supplies that were not destroyed in the incident, we recorded another $1.4 million gain in 2006 relating to the sale of the rig’s salvageable assets. The Company received $7.5 million of the insurance proceeds in the third quarter of 2005 and the remaining proceeds were received in the fourth quarter 2005.

Barge rig 74 was evacuated in March 2003 due to community unrest in Nigeria 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, who was chairman of the board and director of

56

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 2 — Disposition of Assets (continued)

the Company, in anticipation of a settlement of its obligation under this arrangement. See Note 13. In addition, barge rig 57 was damaged in July 2005 in a towing incident resulting in a $2.6 million impairment. Subsequently, during the third quarter of 2006, we settled with the insurance carrier and recorded a gain of $1.9 million relating to this rig. On November 8, 2005, a well control incident on rig 247 occurred while operating under contract in Turkmenistan. Rig equipment has been assessed for repair or replacement. The Company recorded a $1.2 million estimated impairment to the rig and a $1.2 million insurance receivable in December 2005.

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.

Assets Held for Sale — The assets held for sale of $4.8 million as of December 31, 2006 was comprised of the net book value of two workover barge rigs and related inventory that were subsequently sold on January 2, 2007 for $20.5 million.

Note 3 — Goodwill

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. In 2006, the Nigerian barge rigs were sold and $7.3 million of goodwill relating to those rigs was written off. As of December 31, 2006, the goodwill by reporting unit was: U.S. drilling barge rigs — $64.2 million, and rental tools — $36.1 million.

Note 4 — Long-Term Debt

	December 31,
	2006		2005
	(Dollars in Thousands)
Senior Floating Rate Notes payable in September 2010 with interest at three-month LIBOR + 4.75% payable quarterly in March, June, September and December (effective interest rate of 10.12% at December 31, 2006 and 9.16% at December 31, 2005)	$	100,000	$	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 $4,368 at December 31, 2006 and $5,015 at December 31, 2005 (effective interest rate of 9.27% at December 31, 2006 and 9.20% at December 31, 2005)		229,368		230,015
Total debt		329,368		380,015
Less current portion		—		—
Total long-term debt	$	329,368	$	380,015

57

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 4 — Long-Term Debt (continued)

The aggregate maturities of long-term debt for the five years ending December 31, 2010 are as follows: $0 for2006-2009, $100.0 million for 2010 and $225.0 million thereafter.

Activity in 2006 — On September 8, 2006, we redeemed $50.0 million face value of our Senior Floating Rate Notes pursuant to a redemption notice dated August 8, 2006 at the redemption price of 102.0 percent. Proceeds from the sale of our Nigerian barge rigs and cash on hand were used to fund the redemption. An expense of $1.9 million was recognized as loss on extinguishment of debt.

Activity in 2005 — On February 7, 2005, the Company redeemed $25.0 million face value of its 10.125% Senior Notes pursuant to a redemption notice dated January 6, 2005 at the redemption price of 105.0625 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 face value of its 10.125% Senior Notes at the redemption price of 105.0625 percent. The redemption date was May 21, 2006. 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 face value 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. An expense of $1.6 million was recognized as loss on extinguishment of debt.

Each of the Company’s Senior Note offerings 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 onForm S-4 offering to exchange the new notes for notes of the Company having substantially identical terms in all material respects as the outstanding notes. New notes and exchange notes are governed by the terms of the indentures executed by the Company, the subsidiary guarantors and the trustee. Each of the 9.625% Senior Notes, the Senior Floating Rate Notes and the credit agreement contains customary affirmative and negative covenants, including restrictions on incurrence of debt, sales of assets and dividends. In addition, the credit agreement contains covenants which require minimum ratios for consolidated leverage, consolidated interest coverage and consolidated senior secured leverage.

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

Set forth on the following pages are the consolidating condensed financial statements of (i) Parker Drilling, (ii) its restricted subsidiaries that are guarantors of the Senior Notes and Senior Floating Rate Notes (“the Notes”) and (iii) the restricted and unrestricted subsidiaries that are not guarantors of the Notes. The Notes are guaranteed by substantially all of the restricted subsidiaries of Parker Drilling. There are currently no restrictions on the ability of the restricted subsidiaries to transfer funds to Parker Drilling in the form of cash dividends, loans or advances. Parker Drilling is a holding company with no operations, other than through its subsidiaries. Separate financial statements for each guarantor company are not provided as the company complies with the exception toRule 3-10(a)(1) ofRegulation S-X, set forth insub-paragraph (f) of such rule.

58

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

All guarantor subsidiaries are owned 100% by the parent company, all guarantees are full and unconditional and all guarantees are joint and several.

AralParker (a Kazakhstan closed joint stock company, owned 80 percent by Parker Drilling (Kazakhstan), Ltd. and 20 percent by Aralnedra, CJSC), Casuarina Limited (a wholly-owned captive insurance company), KDN Drilling Limited, Mallard Drilling of South America, Inc., Mallard Drilling of Venezuela, Inc., Parker Drilling Investment Company, Parker Drilling (Nigeria), Limited, Parker Drilling Company (Bolivia) S.A., Parker Drilling Company Kuwait Limited, Parker Drilling Company Limited (Bahamas), Parker Drilling Company of New Zealand Limited, Parker Drilling Company of Sakhalin, Parker Drilling de Mexico S. de R.L. de C.V., Parker Drilling International of New Zealand Limited, Parker Drilling Tengiz, Ltd., Parker TNK Drilling, PD Servicios Integrales, S. de R.L. de C.V., PKD Sales Corporation, Parker SMNG Drilling Limited Liability Company (owned 50 percent by Parker Drilling Company International, LLC), Parker Drilling Kazakhstan, B.V., Parker Drilling AME Limited, Parker Drilling Asia Pacific, LLC, PD International Holdings C.V.,PD Dutch Holdings C.V., PD Selective Holdings C.V., PD Offshore Holdings C.V., Parker Drilling Netherlands B.V., Parker Drilling Dutch B.V., Parker Hungary Rig Holdings Limited Liability Company, Parker Drilling Spain Rig Services, S L, Parker 3Source, LLC and Parker Enex, LLC are all non-guarantor subsidiaries. The Company is providing consolidating condensed financial information of the parent, Parker Drilling, the guarantor subsidiaries, and the non-guarantor subsidiaries as of December 31, 2006 and December 31, 2005 and for the years ended December 31, 2006, 2005 and 2004. The consolidating condensed financial statements present investments in both consolidated and unconsolidated subsidiaries using the equity method of accounting.

The consolidating condensed statement of operations for the year ended December 31, 2004 reflects adjustments in the amount of $47.2 million in the guarantor column and $9.7 million in the non-guarantor column to reduce the amount of gain recorded from that which was previously reported to correct for an overstatement of “step-up” in basis of assets that were transferred between wholly-owned subsidiaries. In addition, the consolidating condensed balance sheet as of December 31, 2005 reflects adjustments in the amount of $62.0 million in the guarantor column and $9.7 million in the non-guarantor column to reduce the amount of property, plant and equipment balance and retained earnings (accumulated deficit) balance from that previously reported to adjust for the overstatement of accumulated gains from the “step-up” in basis reported in 2004 and prior years. Adjustments were also made to reduce the corresponding amounts in the eliminations columns. These adjustments had no impact on the consolidated totals.

59

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

	Year Ended December 31, 2006
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Drilling and rental revenues	$	3		$	510,157		$	123,506		$	(47,231	)	$	586,435
Drilling and rental operating expenses		—			274,862			121,995			(47,231	)		349,626
Depreciation and amortization		—			65,221			4,049			—			69,270
Drilling and rental operating income		3			170,074			(2,538	)		—			167,539
General and administration expense(1)		(166	)		(31,606	)		(14	)		—			(31,786	)
Gain (loss) on disposition of assets, net		(6	)		7,416			163			—			7,573
Total operating income (loss)		(169	)		145,884			(2,389	)		—			143,326
Other income and (expense):
Interest expense		(36,313	)		(47,178	)		(1,674	)		53,567			(31,598	)
Changes in fair value of derivative positions		40			—			—			—			40
Interest income		50,102			8,458			2,970			(53,567	)		7,963
Loss on extinguishment of debt		(1,912	)		—			—			—			(1,912	)
Minority interest		—			—			(229	)		—			(229	)
Other		21			(216	)		40			—			(155	)
Equity in net earnings of subsidiaries		80,335			—			—			(80,335	)		—
Total other income and (expense)		92,273			(38,936	)		1,107			(80,335	)		(25,891	)
Income (loss) before income taxes		92,104			106,948			(1,282	)		(80,335	)		117,435
Income tax expense (benefit):
Current		(4,873	)		21,243			4,284			—			20,654
Deferred		15,951			(4,144	)		3,948			—			15,755
Income tax expense		11,078			17,099			8,232			—			36,409
Net income (loss)	$	81,026		$	89,849		$	(9,514	)	$	(80,335	)	$	81,026

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

60

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.

61

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		—			3,305			425			—			3,730
Total operating income (loss)		(1,731	)		27,305			(1,707	)		—			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		775			32			12			—			819
Equity in net losses of subsidiaries		(29,149	)		—			—			29,149			—
Total other income and (expense)		(44,287	)		(41,853	)		(2,432	)		29,149			(59,423	)
Income (loss) before income taxes		(46,018	)		(14,548	)		(4,139	)		29,149			(35,556	)
Income tax expense		1,065			12,685			1,259			—			15,009
Income (loss) from continuing operations		(47,083	)		(27,233	)		(5,398	)		29,149			(50,565	)
Discontinued operations		—			3,482			—			—			3,482
Net income (loss)	$	(47,083	)	$	(23,751	)	$	(5,398	)	$	29,149		$	(47,083	)

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

62

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

	December 31, 2006
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	60,029		$	14,367		$	17,807		$	—		$	92,203
Marketable securities		60,920			2,000			—			—			62,920
Accounts and notes receivable, net		53,844			143,905			33,625			(119,015	)		112,359
Rig materials and supplies		—			7,173			7,827			—			15,000
Deferred costs		—			6,321			341			—			6,662
Other current assets		18,105			8,969			1,319			37			28,430
Total current assets		192,898			182,735			60,919			(118,978	)		317,574
Property, plant and equipment, net		134			354,356			80,861			122			435,473
Assets held for sale		—			4,828			—			—			4,828
Goodwill		—			100,315			—			—			100,315
Investment in subsidiaries and intercompany advances		694,050			846,800			(8,053	)		(1,532,797	)		—
Other noncurrent assets		18,043			19,774			5,294			—			43,111
Total assets	$	905,125		$	1,508,808		$	139,021		$	(1,651,653	)	$	901,301
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	44,667		$	175,092		$	44,611		$	(169,144	)	$	95,226
Accrued income taxes		(10,514	)		17,039			152			—			6,677
Total current liabilities		34,153			192,131			44,763			(169,144	)		101,903
Long-term debt		329,368			—			—			—			329,368
Other long-term liabilities		1,596			9,030			265			40			10,931
Intercompany payables		80,909			544,250			37,219			(662,378	)		—
Stockholders’ equity:
Common stock		18,220			39,899			21,251			(61,150	)		18,220
Capital in excess of par value		568,253			1,013,736			34,526			(1,048,262	)		568,253
Retained earnings (accumulated deficit)		(127,374	)		(290,238	)		997			289,241			(127,374	)
Total stockholders’ equity		459,097			763,397			56,774			(820,169	)		459,099
Total liabilities and stockholders’ equity	$	905,125		$	1,508,808		$	139,021		$	(1,651,653	)	$	901,301

63

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			324,637			30,504			122			355,397
Goodwill		—			107,606			—			—			107,606
Investment in subsidiaries and intercompany advances		606,711			740,140			35,403			(1,382,254	)		—
Other noncurrent assets		46,080			10,997			244			(39	)		57,282
Total assets	$	754,892		$	1,386,346		$	134,362		$	(1,473,980	)	$	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	)		(380,087	)		10,511			369,576			(208,400	)
Total stockholders’ equity		259,829			637,371			65,712			(703,083	)		259,829
Total liabilities and stockholders’ equity	$	754,892		$	1,386,346		$	134,362		$	(1,473,980	)	$	801,620

64

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

	Year Ended December 31, 2006
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	81,026		$	89,849		$	(9,514	)	$	(80,335	)	$	81,026
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization		—			65,221			4,049			—			69,270
Amortization of debt issuance and premium		764			—			—			—			764
Loss on extinguishment of debt		910			—			—			—			910
Gain on disposition of assets		6			(7,416	)		(163	)		—			(7,573	)
Deferred tax expense (benefit)		15,951			(4,144	)		3,948			—			15,755
Other		8,474			1,200			—			—			9,674
Equity in net earnings of subsidiaries		(80,335	)		—			—			80,335			—
Change in operating assets and liabilities		(2,952	)		6,797			(6,803	)		—			(2,958	)
Net cash provided by operating activities		23,844			151,507			(8,483	)		—			166,868
Cash flows from investing activities:
Capital expenditures		—			(191,308	)		(3,714	)		—			(195,022	)
Investment in joint venture		(10,000	)		—			—			—			(10,000	)
Proceeds from the sale of assets		(6	)		48,481			2,315			—			50,790
Proceeds from insurance settlements		—			4,501			—			—			4,501
Purchase of marketable securities		(196,120	)		(2,000	)		—			—			(198,120	)
Sale of marketable securities		151,200			2,000			—			—			153,200
Net cash used in investing activities		(54,926	)		(138,326	)		(1,399	)		—			(194,651	)
Cash flows from financing activities:
Principal payments under debt obligations		(50,000	)		—			—			—			(50,000	)
Proceeds from common stock offering		99,947			—			—			—			99,947
Proceeds from stock options exercised		7,537			—			—			—			7,537
Excess tax benefit from stock options exercised		2,326			—			—			—			2,326
Intercompany advances, net		(677	)		(9,959	)		10,636			—			—
Net cash provided by (used in) financing activities		59,133			(9,959	)		10,636			—			59,810
Net increase in cash and cash equivalents		28,051			3,222			754			—			32,027
Cash and cash equivalents at beginning of year		31,978			11,145			17,053			—			60,176
Cash and cash equivalents at end of year	$	60,029		$	14,367		$	17,807		$	—		$	92,203

65

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 operating assets and liabilities		139,247			(131,278	)		9,322			—			17,291
Net cash provided by (used in) operating activities		132,890			(24,519	)		14,236			—			122,607
Cash flows from investing activities:
Capital expenditures		—			(63,806	)		(5,686	)		—			(69,492	)
Proceeds from the sale of assets		38			57,184			3,824			—			61,046
Proceeds from insurance claims		—			13,850			—			—			13,850
Purchase of marketable securities		(16,000	)		(2,000	)		—			—			(18,000	)
Net cash provided by (used in) investing activities		(15,962	)		5,228			(1,862	)		—			(12,596	)
Cash flows from financing activities:
Proceeds from issuance of debt		55,500			—			—			—			55,500
Principal payments under debt obligations		(155,632	)		—			—			—			(155,632	)
Payment of debt issuance costs		(655	)		—			—			—			(655	)
Proceeds from stock options exercised		6,685			—			—			—			6,685
Intercompany advances, net		(7,525	)		22,498			(14,973	)		—			—
Net cash provided by (used in) financing activities		(101,627	)		22,498			(14,973	)		—			(94,102	)
Net increase (decrease) in cash and cash equivalents		15,301			3,207			(2,599	)		—			15,909
Cash and cash equivalents at beginning of year		16,677			7,938			19,652			—			44,267
Cash and cash equivalents at end of year	$	31,978		$	11,145		$	17,053		$	—		$	60,176

66

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	)	$	(23,751	)	$	(5,398	)	$	29,149		$	(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		—			(3,195	)		(425	)		—			(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		29,149			—			—			(29,149	)		—
Change in operating assets and liabilities		(24,883	)		(7,941	)		15,889			—			(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

67

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 6 — Derivative Financial Instruments

The Company entered into twovariable-to-fixed interest rate swap agreements as a strategy to manage the floating rate risk on its Senior Floating Rate Notes. The first agreement, signed on August 18, 2004, fixed the interest rate on $50.0 million at 8.83% for a three-year period beginning September 1, 2006 and terminating September 2, 2008 and fixed the interest rate on an additional $50.0 million at 8.48% for the two-year period beginning September 1, 2006 and terminating September 4, 2007. In each case, an option to extend each swap for an additional two years at the same rate was given to the issuer, Bank of America, N.A. The second agreement, signed on September 14, 2004, fixed the interest rate on $150.0 million at 6.54% for the three-month period beginning December 1, 2004 and terminating March 1, 2005. Options to extend $100.0 million at a fixed interest rate of 7.08% for a six-month period beginning March 1, 2005 and to extend $50.0 million at a fixed interest rate of 7.60% for an18-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, 2006, 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	%	$	740
	September 1, 2005		September 4, 2007	$	50,000	Three-month LIBOR plus 475 basis points		8.48	%		582
										$	1,322

Note 7 — Income Taxes

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

	Year Ended December 31,
	2006		2005		2004
	(Dollars in Thousands)
United States	$	99,024	$	23,021	$	(14,847	)
Foreign		18,411		47,207		(20,709	)
	$	117,435	$	70,228	$	(35,556	)

68

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,
	2006			2005			2004
	(Dollars in Thousands)
Current:
United States:
Federal	$	13,046		$	1,837		$	124
State		—			18			—
Foreign		7,608			14,473			14,885
Deferred:
United States:
Federal		30,436			(46,537	)		—
State		(12,617	)		—			—
Foreign		(2,064	)		1,625			—
	$	36,409		$	(28,584	)	$	15,009

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,
	2006						2005						2004
				% of						% of						% of
				Pre-Tax						Pre-Tax						Pre-Tax
	Amount			Income			Amount			Income			Amount			Income
	(Dollars in Thousands)
Computed expected tax expense	$	41,104			35	%	$	24,580			35	%	$	(12,445	)		(35	)%
Foreign taxes, net of federal benefit		5,820			5	%		7,496			11	%		12,672			36	%
Change in valuation allowance		—			—		$	(71,497	)		(102	)%		12,231			34	%
Foreign corporation income		1,524			2	%		9,055			13	%		1,116			3	%
Benefit of State NOL		(12,617	)		(11	)%		—			—			—			—
Permanent differences		1,404			1	%		1,740			2	%		1,311			4	%
Other		(826	)		(1	)%		42			—			124			—
Actual tax expense	$	36,409			31	%	$	(28,584	)		(41	)%	$	15,009			42	%

69

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, 2006 and 2005 are shown below:

	December 31,
	2006			2005
	(Dollars in Thousands)
Deferred tax assets:
Current deferred tax assets:
Reserves established against realization of certain assets	$	4,375		$	5,951
Accruals not currently deductible for tax purposes		12,932			6,067
Current deferred tax assets		17,307			12,018
Long-term deferred tax assets:
Net operating loss carryforwards		—			34,783
Alternative minimum tax carryforwards		—			2,363
Property, plant and equipment		10,940			10,199
State net operating loss carryforwards		12,617			—
Other long-term liabilities		2,149			2,149
Deferred stock compensation		3,693			741
Gross long-term deferred tax assets		29,399			50,235
Long-term deferred tax valuation allowance		—			—
Long-term deferred tax assets		29,399			50,235
Deferred tax assets		46,706			62,253
Deferred tax liabilities:
Long-term deferred tax liabilities:
Goodwill		(14,561	)		(12,234	)
Other		(1,433	)		(3,552	)
Long-term deferred tax liabilities		(15,994	)		(15,786	)
Net deferred tax assets	$	30,712		$	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 2006 and 2005 results reflect the reversal of valuation allowances related to NOL carryforwards and other deferred tax assets in the U.S. The valuation allowances were originally recorded in accordance with GAAP as an offset to the Company’s deferred tax assets, which consisted primarily of federal and state NOL carryforwards. GAAP required the Company to record a valuation allowance unless it was “more likely than

70

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 7 — Income Taxes (continued)

not” that the Company could realize the benefit of the NOL carryforwards and deferred tax assets in future periods. Having returned to profitability in 2005, the Company determined that earnings performance should allow the Company to benefit from the federal NOL carryforwards and that the valuation allowance for federal NOL’s was no longer required. The $29.5 million decrease in the NOL carryforward component of deferred tax assets in 2005 is primarily due to utilization of NOL carryforwards in the Company’s 2005 federal income tax return that was filed in 2006. The $56.0 million decrease in the valuation allowance component in 2005 was primarily due to expected utilization of gross NOL carryforwards. The $34 .8 million decrease in the NOL carryforward component of deferred tax assets in 2006 is primarily due to the projected full utilization of NOL carryforwards in the Company’s 2006 federal income tax return to be filed in 2007.

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

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, 2006, the amounts accrued for tax contingencies totaled $25.1 million, with $8.8 million classified as long-term and included in “Other long-term liabilities.”

Note 8 — Common Stock and Stockholders’ Equity

Common Stock Offering — On January 18, 2006, we issued 8,900,000 shares of our common stock 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 underwriting discount, from the offering.

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

71

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

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 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 aForm S-8 filed with the Securities and Exchange Commission (“SEC”) on May 6, 2005.

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

72

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

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

	1991 Stock
	Grant Plan
	Restricted
	Shares
Outstanding at December 31, 2005		100,000
Granted		—
Exercised		—
Cancelled		—
Outstanding at December 31, 2006		100,000

	1994 Non-Employee Director
	Stock Incentive Plan
				Weighted
				Average
				Exercise		Intrinsic
	Shares			Price		Value
Outstanding at December 31, 2005		124,000		$	9.137
Granted		—			—
Exercised		(30,000	)		8.880	$	3,975
Cancelled		(10,000	)		10.700
Outstanding at December 31, 2006		84,000		$	9.047

	1994 Executive Stock Option Plan
	Incentive Options							Non-Qualified Options
				Weighted							Weighted
				Average							Average
				Exercise		Intrinsic					Exercise		Intrinsic
	Shares			Price		Value		Shares			Price		Value
Outstanding at December 31, 2005		141,539		$	8.875				790,995		$	8.875
Granted		—			—				—			—
Exercised		(33,801	)		8.875	$	84,333		(161,199	)		8.875	$	404,730
Cancelled		(6,335	)		8.875				(11,199	)		8.875
Outstanding at December 31, 2006		101,403		$	8.875				618,597		$	8.875

73

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		Intrinsic					Exercise		Restricted		Intrinsic
	Shares			Price		Value		Shares			Price		Shares		Value
Outstanding at December 31, 2005		1,205,368		$	8.947				2,631,448		$	5.049		—
Granted		—			—				—			—		—
Exercised		(277,622	)		4.144	$	1,647,359		(927,928	)		4.018		—	$	6,009,490
Cancelled		(196,564	)		9.781				(24,902	)		4.958		—
Outstanding at December 31, 2006		731,182		$	10.547				1,678,618		$	5.623		—

	2005 Long-Term Incentive Plan
	Non-Qualified Options
				Weighted
				Average
				Exercise		Intrinsic		Restricted
	Shares			Price		Value		Shares
Outstanding at December 31, 2005		200,000		$	8.875				1,005,000
Granted		10,000			3.188				753,500
Exercised		(135,000	)		3.523	$	254,950		(270,184	)
Cancelled		(50,000	)		8.875				(30,165	)
Outstanding at December 31, 2006		25,000		$	8.875				1,458,151

74

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, 2006:

				Outstanding Options
				Weighted
				Average		Weighted
				Remaining		Average		Aggregate
		Number of		Contractual		Exercise		Intrinsic
Plan	Exercise Prices	Shares		Life		Price		Value
1994 Non-Employee Director Incentive Plan
Non-qualified	$3.281		4,000		2.0 years	$	3.280	$	19,560
Non-qualified	$8.875 – $12.094		80,000		0.4 years	$	9.335	$	—
1994 Executive Stock Option Plan
Incentive option	$8.875		101,403		0.4 years	$	8.875	$	—
Non-qualified	$8.875		618,597		0.4 years	$	8.875	$	—
1997 Stock Plan Incentive option	$3.188 – $5.938		—		—	$	—	$	—
Incentive option	$8.875 – $12.188		731,182		0.6 years	$	10.547	$	—
Non-qualified	$1.960 – $6.070		1,087,800		0.4 years	$	3.847	$	4,702,222
Non-qualified	$8.875 – $10.813		590,818		0.3 years	$	8.892	$	—
2005 Long-Term Incentive Plan
Non-qualified	$8.875		25,000		0.4 years	$	8.875	$	—

		Exercisable Options
				Weighted
				Average		Aggregate
		Number of		Exercise		Intrinsic
Plan	Exercise Prices	Shares		Price		Value
1994 Non-Employee Director Incentive Plan
Non-qualified	$3.281		4,000	$	3.280	$	19,560
Non-qualified	$8.875 – $12.094		80,000	$	9.335	$	—
1994 Executive Stock Option Plan
Incentive option	$8.875		101,403	$	8.875	$	—
Non-qualified	$8.875		618,597	$	8.875	$	—
1997 Stock Plan
Incentive option	$3.188 – $5.938		—	$	—	$	—
Incentive option	$8.875 – $12.188		731,182	$	10.547	$	—
Non-qualified	$1.960 – $6.070		1,079,466	$	3.847	$	4,666,219
Non-qualified	$8.875 – $10.813		590,818	$	8.892	$	—
2005 Long-Term Incentive Plan
Non-qualified	$8.875		25,000	$	8.875	$	—

The Company had 838,875 and 760,699 shares held in Treasury stock at December 31, 2006 and 2005, respectively.

75

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,
	2006		2005
Stock plans		5,372,934		7,938,484
Stock bonus plan		87,983		307,187
Total shares reserved for issuance		5,460,917		8,245,671

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 would declare 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.

76

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, 2006
	Income		Shares		Per-Share
	(Numerator)		(Denominator)		Amount
Basic EPS:
Income from continuing operations	$	81,026,000		106,552,015	$	0.76
Discontinued operations		—				—
Net income	$	81,026,000			$	0.76
Effect of dilutive securities:
Stock options and restricted stock				1,586,368	$	(0.01	)
Diluted EPS:
Income from continuing operations	$	81,026,000		108,138,384	$	0.75
Discontinued operations		—				—
Net income	$	81,026,000			$	0.75

	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	)

77

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 2,135,166 shares of common stock with exercise prices ranging from $8.875 to $12.188 per share were outstanding during the year ended December 31, 2006, but were not included in the computation of diluted EPS because the options’ exercise prices were greater than the average market price of the common shares. For the year ended December 31, 2005, options to purchase 2,796,000 shares of common stock at prices ranging from $8.875 to $12.188, which were outstanding during the period, were not included in the computation of diluted EPS because the assumed exercise of the options would have had an anti-dilutive effect on EPS because the options’ exercise prices were greater than the average market price of the common shares. For the fiscal 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 during 2004.

Note 10 — Employee Benefit Plan

The Company sponsors a defined contribution 401(k) plan (“Plan”) in which substantially all U.S. employees are eligible to participate. Company matching contributions to the Plan are based on the amount of employee contributions and are made in Parker Drilling common stock. The Company issued 219,204, 205,011 and 402,760 shares to the Plan in 2006, 2005 and 2004, respectively, with the Company recognizing expense of $1.8 million, $1.4 million, and $1.4 million for each of the respective periods.

78

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	2006			2005			2004
	(Dollars in Thousands)
Drilling and rental revenues:
U.S. drilling (1)	$	191,225		$	128,252		$	88,512
International drilling (1)		273,216			308,572			220,846
Rental tools (1)		121,994			94,838			67,167
Total drilling and rental revenues		586,435			531,662			376,525
Drilling and rental operating income (loss):
U.S. drilling (2)		83,370			41,739			15,938
International drilling (2)		27,465			40,281			15,858
Rental tools (2)		56,704			40,239			24,874
Total drilling and rental operating income		167,539			122,259			56,670
Net construction contract operating income		—			—			—
General and administrative expense		(31,786	)		(27,830	)		(23,413	)
Provision for reduction in carrying value of certain assets		—			(4,884	)		(13,120	)
Gain on disposition of assets, net		7,573			25,578			3,730
Total operating income		143,326			115,123			23,867
Interest expense		(31,598	)		(42,113	)		(50,368	)
Changes in fair value of derivative positions		40			2,076			(794	)
Loss on extinguishment of debt		(1,912	)		(8,241	)		(8,753	)
Minority interest		(229	)		1,905			(1,143	)
Other		7,808			1,478			1,635
Income (loss) from continuing operations before income taxes	$	117,435		$	70,228		$	(35,556	)
Identifiable assets: (3)
U.S. drilling	$	255,275		$	120,647
International drilling		318,767			378,427
Rental tools		166,270			98,531
Total identifiable assets		740,312			597,605
Corporate assets		160,989			204,015
Total assets	$	901,301		$	801,620

(1)	In 2006, ExxonMobil and Chevron accounted for approximately 14 percent and 8 percent of the Company’s total revenues, respectively. ExxonMobil accounted for approximately $65.8 million of the Company’s international drilling segment revenues and approximately $19.0 million of the Company’s rental tools segment revenues. Chevron accounted for approximately $28.5 million of the Company’s international drilling segment revenues, $9.8 million of the U.S. drilling segment and approximately $10.3 million of the Company’s rental tools segment revenues. In 2005, ExxonMobil and Chevron accounted for approximately 14 percent and 11 percent of the Company’s total revenues, respectively. ExxonMobil accounted for approximately $54.8 million of the Company’s international drilling segment revenues and approximately $18.2 million of the Company’s rental tools segment revenues. Chevron accounted for approximately $50.6 million of the Company’s international drilling segment revenues and approximately $9.2 million of the Company’s rental tools segment revenues.
(2)	Drilling and rental operating income — drilling and rental revenues less direct drilling and rental operating expenses, including depreciation and amortization expense.
(3)	Includes assets related to discontinued operations.

79

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 11 — Business Segments (continued)

	Year Ended December 31,
Operations by Industry Segment	2006		2005		2004
	(Dollars in Thousands)
Capital expenditures:
U.S. drilling	$	72,373	$	16,724	$	13,549
International drilling		75,448		23,524		20,128
Rental tools		40,773		27,962		13,031
Corporate		6,428		1,282		610
Total capital expenditures	$	195,022	$	69,492	$	47,318
Depreciation and amortization:
U.S. drilling	$	23,867	$	19,354	$	18,090
International drilling		25,290		30,330		35,642
Rental tools		18,501		16,142		13,984
Corporate		1,612		1,378		1,525
Total depreciation and amortization	$	69,270	$	67,204	$	69,241

80

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 11 — Business Segments (continued)

	Year Ended December 31,
Operations by Geographic Area	2006			2005			2004
	(Dollars in Thousands)
Drilling and rental revenues:
United States	$	309,757		$	218,056		$	154,995
Latin America		31,466			67,954			39,614
Asia Pacific		79,665			58,623			42,468
Africa and Middle East		24,219			33,377			31,352
CIS		141,328			153,652			108,096
Total drilling and rental revenues		586,435			531,662			376,525
Drilling and rental operating income (loss):
United States (1)		136,690			77,560			40,130
Latin America (1)		(5,679	)		4,018			(1,215	)
Asia Pacific (1)		19,884			14,353			9,379
Africa and Middle East (1)		(2,594	)		(834	)		(8,181	)
CIS (1)		19,238			27,162			16,557
Total drilling and rental operating income		167,539			122,259			56,670
Net construction contract operating income (United States)		—			—			—
General and administrative expense		(31,786	)		(27,830	)		(23,413	)
Provision for reduction in carrying value of certain assets		—			(4,884	)		(13,120	)
Gain on disposition of assets, net		7,573			25,578			3,730
Total operating income		143,326			115,123			23,867
Interest expense		(31,598	)		(42,113	)		(50,368	)
Changes in fair value of derivative positions		40			2,076			(794	)
Loss on extinguishment of debt		(1,912	)		(8,241	)		(8,753	)
Minority interest		(229	)		1,905			(1,143	)
Other		7,808			1,478			1,635
Income (loss) from continuing operations before income taxes	$	117,435		$	70,228		$	(35,556	)
Long-lived assets: (2)
United States	$	401,349		$	257,302
Latin America		17,217			36,853
Asia Pacific		24,420			18,732
Africa and Middle East		2,412			51,615
CIS		90,389			98,501
Total long-lived assets	$	535,787		$	463,003

(1)	Drilling and rental operating income — drilling and rental revenues less direct drilling and rental operating expenses, including depreciation and amortization expense.
(2)	Is primarily comprised of property, plant and equipment, net and goodwill and excludes assets held for sale.

Note 12 — Commitments and Contingencies

At December 31, 2006, 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, 2006, $23.1 million of availability has

81

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 12 — Commitments and Contingencies (continued)

been reserved to support letters of credit that have been issued. At December 31, 2006, 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, 2006, under operating leases with non-cancelable terms are as follows (dollars in thousands):

2007	$	4,958
2008		2,844
2009		1,806
2010		662
2011		565
Thereafter		173
Total	$	11,008

Total rent expense for all operating leases amounted to $9.0 million for 2006, $10.2 million for 2005, and $9.3 million for 2004.

As of December 31, 2006, the Company had $62.5 million in outstanding purchase commitments related to rig upgrade projects and new rig construction.

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, 2006, the Company’s gross self-insurance accruals for workers’ compensation, employers’ liability, general liability, protection and indemnity and maritime employers’ liability totaled $9.3 million and the related insurance recoveries/receivables were $3.7 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.

82

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 12 — Commitments and Contingencies (continued)

Kazakhstan Tax Claims

On October 12, 2005, the Kazakhstan Branch (“PKD Kazakhstan”) of Parker Drilling Company International Limited (“PDCIL”) received an Act of Tax Audit from the Ministry of Finance of Kazakhstan (“MinFin”) assessing PKD Kazakhstan an amount of KZT (Kazakhstan Tenge) 14.9 billion (approximately $125.5 million). Approximately KZT 7.5 billion or $63.6 million was assessed for import Value Added Tax (“VAT”), administrative fines and interest on equipment imported to perform the drilling contracts (the “VAT Assessment”) and approximately KZT 7.4 billion or $61.9 million for corporate income tax, individual income tax and social tax, administrative fines and interest in connection with the reimbursements received from the client for the upgrade of barge Rig 257 and other issues (the “Income Tax Assessment”).

The VAT and Income Tax Assessment were both appealed to the Astana City Court and on April 6, 2006, the Astana City Court issued an opinion in favor of PKD Kazakhstan on the Income Tax Assessment and in favor of MinFin on the VAT Assessment, but reduced the amount of the VAT Assessment. MinFin and PKD Kazakhstan appealed the decision of the Astana City Court to the Civil Panel of the Supreme Court of Kazakhstan. On May 24, 2006, the Civil Panel of the Supreme Court issued a decision upholding the ruling of the Astana City Court on the VAT Assessment. Consistent with its contractual obligations, on November 20, 2006, the client advanced the actual amount of the VAT Assessment and this amount has been remitted to MinFin. The client has also contractually agreed to reimburse PKD Kazakhstan for any incremental income taxes that PKD Kazakhstan incurs from the reimbursement of this VAT Assessment.

Contrary to two previous rulings on this precise issue, the May 24, 2006, ruling of the Civil Panel of the Supreme Court affirmed the Income Tax Assessment. PKD Kazakhstan immediately made application for a stay of execution of the ruling, based on the fact that the Supreme Court has decided this issue in favor of PKD Kazakhstan on two previous occasions and because the decision is inconsistent with the US-Kazakhstan tax treaty, and also requested that the five-member supervisory panel of the Supreme Court grant a supervisory review of the decision. On May 30, 2006, the Supreme Court granted a stay of execution of the decision pending a determination of the five-member panel of the Supreme Court whether or not to grant supervisory review of the decision. The Supreme Court has postponed a hearing on the supervisory review issue on two occasions, and is currently scheduled a hearing on March 31, 2007. It is management’s understanding that the Supreme Court has postponed a hearing on this issue until the Competent Authority from MinFin and the U.S. Treasury meet as explained below.

The Company initiated a petition for Competent Authority review of this issue in 2004. Competent Authority review is a tax treaty procedure to resolve disputes as to which country may tax income covered under the treaty. A meeting between the U.S. IRS Treaty Division and MinFin has been scheduled for March 20, 2007. Because the execution of this decision has been stayed by the Supreme Court and there is a substantial basis to conclude that the decision will not be upheld, the Company has not recorded an accrual for any adverse final determination of the Income Tax Assessment. The Company is currently evaluating the impact that the adoption of FIN 48, “Uncertain Tax Positions” will have on its reported liability assessment upon the adoption of this standard effective January 1, 2007.

Bangladesh Claim

In September 2005, a subsidiary of the Company was served with a lawsuit filed in the 152nd District Court of Harris County State of Texas on behalf of numerous citizens of Bangladesh claiming $250 million in damages due to various types of property damage and personal injuries (none involving loss of life) arising as a result of two blowouts that occurred in Bangladesh in January and June 2005, although only the June 2005 blowout involved the Company. This case was dismissed against the subsidiary of the Company based onforum non conveniens,a legal defense raised by the subsidiary claiming that Houston, Texas, is not the appropriate location for this suit to be filed. The plaintiffs have appealed this dismissal; however the Company believes the plaintiffs’ prospects of being successful on appeal is remote.

83

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 12 — Commitments and Contingencies (continued)

Asbestos-Related Claims

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

The complaints allege that the Company’s subsidiaries and other drilling contractors used asbestos-containing products in offshore drilling operations, land-based drilling operations and in drilling structures, drilling rigs, vessels and other equipment and assert claims based on, among other things, negligence and strict liability and claims under the Jones Act and that the Plaintiffs are entitled to monetary damages. Based on the report of the special master, these complaints have been severed and venue of the claims transferred to the county in which the plaintiff resides or the county in which the cause of action allegedly accrued. Subsequent to the filing of amended complaints, Parker has joined with other co-defendants in filing motions to compel discovery to determine what plaintiffs have an employment relationship with which defendant, including whether or not any plaintiffs have an employment relationship with subsidiaries of the Company. Out of 528 amended single-plaintiff complaints filed to date, eleven plaintiffs have identified Parker Drilling or one of its affiliates as a defendant.

The subsidiaries named in these asbestos-related lawsuits intend to defend themselves vigorously and, based on the information available to the Company at this time, the Company does not expect the outcome to have a material adverse effect on its financial condition, results of operations or cash flows; however, there can be no assurance as to the ultimate outcome of these lawsuits.

Other Litigation

The Company is a party to various other 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 other matters would not materially affect the results of operations, the financial position or the net cash flows of the Company.

Note 13 — Related Party Transactions

Agreements with Robert L. Parker and Robert L. Parker, Jr.

The Company entered into a consulting agreement and a termination of split dollar life insurance agreement with Robert L. Parker in April 2006, in connection with Mr. Parker’s retirement. All other agreements relating to Mr. Robert L. Parker, discussed below, were terminated as of December 31, 2006. In addition, all agreements with Mr. Robert L. Parker Jr. relating to use of Robert L. Parker Jr.’s private ranch terminated as of December 31, 2006, as discussed below.

  Consulting Agreement

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

  (i) A consulting contract and severance agreement,

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

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

84

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 13 — Related Party Transactions (continued)

Consulting Agreement (continued)

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

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

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

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

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

  Termination of Split Dollar Life Insurance Agreement

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 2006 and 2005, 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 provided certain personnel to the Limited Partnership to maintain the Cypress Springs Ranch and the Mazie Ranch. During 2006 and 2005, the Limited Partnership paid the Company a total of $0.3 million for the provision of such personnel per year. The Lease Agreement and the Services Agreement were terminated effective December 31, 2006.

On April 4, 2006, Mr. Parker Sr.  and the Company entered into a Termination of Split Dollar Life Insurance Agreement between the Company and Robert L. Parker, Sr. and Catherine M. Parker Family Trust Under Indenture Dated the 23rd Day of July, 1993 (the “Trust”) (the “Termination Agreement”). The terms of the Termination Agreement provide that the Trust will pay the Company $2,400,000 in exchange for a release of the Company’s collateral assignment of all insurance policies owned by the trust on the lives of either Mr. Parker Sr. or both Mr. Parker Sr. and his spouse, Mrs. Parker. Subject to the parties complying with their respective undertakings in regard to the lawsuit filed by the Company and the Trust against the insurer and brokers in connection with the insurance policies that were the subject of the Split Dollar Life Insurance Agreement, i.e. the Company’s agreement to pay the expenses of the lawsuit and the parties agreement that any proceeds shall be paid first to repay these expenses plus interest at 7% and then shared equally, the parties also agreed to mutually release each other from any further obligations under the Split Dollar Life Insurance Agreement.

85

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 13 — Related Party Transactions (continued)

  Lease Agreements

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 2006 and 2005, 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 2006 and 2005, Mr. Parker Jr. paid the Company a total of $63,000 and $58,000 for the provision of such personnel, respectively. The Lease Agreement and the Services Agreement were terminated effective December 31, 2006.

Other Related Party Agreements

During 2006, one of the Company’s directors held the position of executive vice president and chief financial officer of Apache Corporation (“Apache”). During 2006, subsidiaries of the Company recognized $5.1 million in gross revenues for performance of drilling services and provision of rental tools for a subsidiary of Apache. The board of directors determined that there were no independence concerns due to the relative size of these transactions compared to the gross revenues of Apache.

Note 14 — Supplementary Information

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

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. Other long-term obligations included $2.0 million of workers’ compensation liabilities as of December 31, 2005.

86

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 15 — Selected Quarterly Financial Data

	Quarter
Year 2006	First		Second		Third		Fourth (2)		Total (2)
	(Dollars in Thousands Except Per Share Amounts)
	(Unaudited)
Revenues	$	147,334	$	145,988	$	146,783	$	146,330	$	586,435
Drilling and rental operating income	$	41,065	$	39,636	$	44,217	$	42,621	$	167,539
Operating income	$	33,819	$	34,186	$	40,553	$	34,768	$	143,326
Income from continuing operations	$	11,458	$	13,761	$	18,639	$	37,168	$	81,026
Discontinued operations	$	—	$	—	$	—	$	—	$	—
Net income	$	11,458	$	13,761	$	18,639	$	37,168	$	81,026
Basic earnings per share: (1)
Income from continuing operations	$	0.11	$	0.13	$	0.17	$	0.35	$	0.76
Discontinued operations	$	—	$	—	$	—	$	—	$	—
Net income	$	0.11	$	0.13	$	0.17	$	0.35	$	0.76
Diluted earnings per share: (1)
Income from continuing operations	$	0.11	$	0.13	$	0.17	$	0.34	$	0.75
Discontinued operations	$	—	$	—	$	—	$	—	$	—
Net income	$	0.11	$	0.13	$	0.17	$	0.34	$	0.75

(1)

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

(2)

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

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

87

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 15 — Selected Quarterly Financial Data (continued)

(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.

Note 16 — Recent Accounting Pronouncements

In July 2006, FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109” (FIN 48), was issued. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, “Accounting for Income Taxes.” FIN 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new FASB standard provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, and the provisions are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN 48. The cumulative effect of applying the provisions of FIN 48 must be reported as an adjustment to the opening balance of retained earnings for that fiscal year. The Company is currently evaluating the impact of FIN 48 on its Consolidated Financial Statements, including whether or not it will result in any accrual in connection with the Kazakhstan tax issues. See Note 12 to the Notes to Consolidated Financial Statements.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measures” (SFAS 157). SFAS 157 defines fair value, establishes a framework for measuring fair value and enhances disclosures about fair value measures required under other accounting pronouncements, but does not change existing guidance as to whether or not an instrument is carried at fair value. SFAS 157 is effective for fiscal years beginning after November 15, 2007 (i.e., the beginning of the Company’s fiscal year 2008). The Company is currently evaluating the impact of SFAS 157 on its Consolidated Financial Statements.

In September 2006, the SEC issued Staff Accounting Bulletin No. 108, “Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements” (SAB 108), which provides guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB 108 requires that the materiality of the effect of a misstated amount be evaluated on each financial statement and the related financial statement disclosures, and that the materiality evaluation be based on quantitative and qualitative factors. SAB 108 is effective for fiscal years ending after November 15, 2006. The adoption of this guidance did not have a material impact on the Company’s financial position, results of operations or cash flows.

88

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 underRegulation 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 inRules 13a-15(e) and15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)), as of December 31, 2006. In designing and evaluating the disclosure controls and procedures, management recognized that disclosure controls and procedures, no matter how well designed and operated, can provide only reasonable, not absolute, assurance of achieving the desired control objectives, and management necessarily was required to apply its judgment in evaluating the cost-benefit relationship of possible disclosure controls and procedures. Based on the evaluation, the chief executive officer and chief financial officer have concluded that the disclosure controls and procedures were effective to ensure that information required to be disclosed by the Company in the reports it files under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to management as appropriate to allow timely decisions regarding required disclosure.

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

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

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

•  provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

The Company’s management with the participation of the chief executive officer and chief financial officer, assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006 based on criteria established inInternal 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, 2006.

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ITEM 9A.   CONTROLS AND PROCEDURES (continued)

Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report that is included herein.

Changes in Internal Control over Financial Reporting — There were no changes in the Company’s internal control over financial reporting during the quarter ended December 31, 2006, that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

ITEM 9B.   OTHER INFORMATION

None.

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PART III

ITEM 10.   DIRECTORS, EXECUTIVE AND CORPORATE GOVERNANCE

Information with respect to directors can be found under the caption; “Item 1 — Election of Directors” and “Board of Directors” of the Company’s 2007 Proxy Statement for the Annual Meeting of Shareholders to be held on April 25, 2007. Such information is incorporated herein by reference.

Information with respect to executive officers is shown in Item 4A of this report onForm 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 2007 Proxy Statement for the Annual Meeting of Shareholders to be held on April 25, 2007 and is incorporated herein by reference.

The information in the Company’s 2007 Proxy Statement for the Annual Meeting of Shareholders to be held on April 25, 2007 set forth under the caption; “Section 16(a) Beneficial Ownership Reporting Compliance” is incorporated herein by reference.

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

ITEM 11.   EXECUTIVE COMPENSATION

The information under the captions “Executive Compensation,” “Director Compensation Interlocks and Insider Participation and Compensation Committee Report” in the Company’s 2007 Proxy Statement for the Annual Meeting of Shareholders to be held on April 25, 2007 is incorporated herein by reference.

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

The information required by this item is hereby incorporated by reference from the information appearing under the captions “Equity Ownership of Officers, Directors and Principal Stockholders” and “Equity Compensation Plan Information” in the Company’s 2007 Proxy Statement for the Annual Meeting of Shareholders to be held on April 25, 2007.

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

The information required by this item is hereby incorporated by reference to such information appearing under the caption “Related Party Transactions” and “Director Independence Determination” in the Company’s 2007 Proxy Statement for the Annual Meeting of Shareholders to be held April 25, 2007, to be filed with the SEC within 120 days of the end of the Company’s year ended December 31, 2006.

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 2007 Proxy Statement for the Annual Meeting of the Shareholders to be held April 25, 2007.

91

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	43
Consolidated Statement of Operations for the years ended December 31, 2006, 2005 and 2004	45
Consolidated Balance Sheet as of December 31, 2006 and 2005	46
Consolidated Statement of Cash Flows for the years ended December 31, 2006, 2005 and 2004	48
Consolidated Statement of Stockholders’ Equity for the years ended December 31, 2006, 2005 and 2004	50
Notes to the Consolidated Financial Statements	51

(2) Financial Statement Schedule:

Schedule II — Valuation and qualifying accounts 94

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 onForm 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’sForm 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 toForm 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) ofForm 10-K dated March 17, 2003).
4(c)	—	Indenture dated as of October 10, 2003 between the Company, as issuer, certain Subsidiary Guarantors (as defined therein) and JPMorgan Chase Bank, as Trustee, respecting the 9.625% Senior Notes due 2013 (incorporated by reference to the Company’sS-4 Registration StatementNo. 333-110374 dated November 10, 2003).
4(d)	—	First Supplemental Indenture dated as of November 8, 2006, between Parker Drilling Company and the Subsidiary Guarantors and the Bank of New York Trust Company, N.A., as Trustee, respecting the 9.625% Senior Notes due 2013 (incorporated herein by reference to Exhibit 4.3 to the Company’sForm 10-Q for the quarter ended November 30, 2006).
4(e)	—	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’sForm 8-K, dated September 7, 2004).
4(f)	—	First Supplemental Indenture dated as of November 8, 2006, between Parker Drilling Company and the Subsidiary Guarantors and the Bank of New York Trust Company, N.A., as Trustee, respecting the Floating Rate Notes due 2010 (incorporated herein by reference to Exhibit 4.4 to the Company’sForm 10-Q for the quarter ended November 30, 2006).
10(a)	—	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 toForm 8-K dated December 27, 2004).

92

EXHIBIT
NUMBER		DESCRIPTION
ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (continued)
10(b)	—	First Amendment to the Credit Agreement dated December 20, 2004 among Parker Drilling Company, as Borrower, the Several Lenders Parties thereto, Lehman Brothers, Inc., as Sole Advisor, Sole Lead Arranger and Sole Bookrunner, Bank of America, N.A., as Syndication Agent and Lehman Commercial Paper, Inc., as Administrative Agent dated March 1, 2006, (incorporated herein by reference to Exhibit 4(i) to Annual Report onForm 10-K for the year ended December 31, 2005).
10(c)	—	Second 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 February 9, 2007.
10(d)	—	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 onForm 10-Q for the three months ended March 31, 1999).*
10(e)	—	1994 Parker Drilling Company Limited Deferred Compensation Plan (incorporated herein by reference to Exhibit 10(h) to Annual Report onForm 10-K for the year ended August 31, 1995).*
10(f)	—	1994 Non-Employee Director Stock Option Plan (incorporated herein by reference to Exhibit 10(i) to Annual Report onForm 10-K for the year ended August 31, 1995).*
10(g)	—	1994 Executive Stock Option Plan (incorporated herein by reference to Exhibit 10(j) to Annual Report onForm 10-K for the year ended August 31, 1995).*
10(h)	—	Parker Drilling Company and Subsidiaries 1991 Stock Grant Plan (incorporated by reference to Exhibit 10(c) toForm 10-K dated November 2, 1992).*
10(i)	—	Third Amended and Restated Parker Drilling 1997 Stock Plan effective July 24, 2002 (incorporated herein by reference to Exhibit 10(c) to Annual Report onForm 10-K dated March 20, 2003).*
10(j)	—	2006 Long Term Incentive Plan (“2006 LTIP”) (incorporated by reference to the Company’s 2006 Proxy Statement dated March 22, 2006).*
10(k)	—	Form of Indemnification Agreement entered into between Parker Drilling Company and each director and executive officer of Parker Drilling Company, dated on or about October 15, 2002 (incorporated by reference to Exhibit 10(g) toForm 10-K dated March 12, 2004).*
10(l)	—	Form of Employment Agreement entered into between Parker Drilling Company and certain executive and other officers of Parker Drilling Company, (incorporated by reference to Exhibit 10(h) toForm 10-K dated March 17, 2003).*
10(m)	—	Form of Stock Option Award Agreement to the Third Amended and Restated Parker Drilling 1997 Stock Plan (incorporated by reference to Exhibit 10(m) toForm 10-K dated March 14, 2006).*
10(n)	—	Form of Stock Grant Award Agreement to the Third Amended and Restated Parker Drilling 1997 Stock Plan (incorporated by reference to Exhibit 10(n) toForm 10-K dated March 14, 2006).*
10(o)	—	Form of Restricted Stock Award Agreement under the 2006 LTIP (incorporated by reference to Exhibit 10.2 toForm 8-K dated April 27, 2006).*
10(p)	—	Form of Performance Based Restricted Stock Award Agreement under the 2006 LTIP (incorporated by reference to Exhibit 10.3 toForm 8-K dated April 27, 2006).*
10(q)	—	Form of Lease Agreement between Parker Drilling Management Services, Inc. entered into by the Robert L. Parker Sr. Family Limited Partnership and Robert L. Parker Jr. dated January 1, 2004 (incorporated by reference to Exhibit 10(a) to theForm 10-Q dated August 6, 2004).*
10(r)	—	Form of Personnel Services Contract between Parker Drilling Management Services, Inc. and the Robert L. Parker Sr. Family Limited Partnership and Robert L. Parker Jr. dated January 1, 2004 (incorporated by reference to Exhibit 10(b) to theForm 10-Q dated August 6, 2004).*
10(s)	—	Consulting Agreement between Parker Drilling Company and Robert L. Parker Sr. dated April 12, 2006, (incorporated by reference to Exhibit 10.1 to theForm 8-K dated April 12, 2006).*

93

EXHIBIT
NUMBER		DESCRIPTION
ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (continued)
10(t)	—	Termination of Split Dollar Life Insurance Agreement between Parker Drilling Company, Robert L. Parker Sr., and Robert L. Parker Sr. and Catherine Mae Parker Family Trust Under Indenture dated the 23rd day of July 1993, dated April 12, 2006 (incorporated by reference to Exhibit 10.2 to the Form 8-K dated April 12, 2006).*
21	—	Subsidiaries of the Registrant.
23	—	Consent of Independent Registered Public Accounting Firm.
31.1	—	Robert L. Parker Jr., Chairman, President and Chief Executive Officer,Rule 13a-14(a)/15d-14(a) Certification.
31.2	—	W. Kirk Brassfield, Senior Vice President and Chief Financial Officer,Rule 13a-14(a)/15d-14(a) Certification.
32.1	—	Robert L. Parker Jr., Chairman, President and Chief Executive Officer, Section 1350 Certification.
32.2	—	W. Kirk Brassfield, Senior Vice President and Chief Financial Officer, Section 1350 Certification.

* Management Contract, Compensatory Plan or Agreement

(b) Reports onForm 8-K: None.

94

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			Deductions			year
Year ended December 31, 2006:
Allowance for doubtful accounts and notes	$	1,639	$	—	$	—		$	158		$	1,481
Reduction in carrying value of rig materials and supplies	$	3,451	$	1,200	$	—		$	314		$	4,337
Deferred tax valuation allowance	$	—	$	—	$	18,026	(1)	$	18,026	(2)	$	—
Year ended December 31, 2005:
Allowance for doubtful accounts and notes	$	3,591	$	613	$	—		$	2,565		$	1,639
Reduction in carrying value of rig materials and supplies	$	6,468	$	1,200	$	—		$	4,217		$	3,451
Deferred tax valuation allowance	$	56,003	$	—	$	15,494	(3)	$	71,497	(4)	$	—
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

(1)	During 2006 and prior to the reversal of the state valuation allowance, the Company completed a process of reconciling its Louisiana state income tax balance sheet for the purpose of properly adjusting its deferred tax assets and liabilities. As a result of this process, the Company recognized an additional net deferred tax asset of approximately $18.0 million. Additionally, the Company increased its valuation allowance by $18.0 million resulting in no impact to the net deferred tax asset.
(2)	This deduction relates to the reversal of the valuation allowance related to Louisiana state net operating loss carryforwards and other deferred tax assets resulting from the Company’s return to profitability in Louisiana and expected future earnings performance.
(3)	During 2005 and prior to the reversal of the valuation allowance, the Company completed a process of reconciling its United States federal income tax balance sheet for the purpose of properly adjusting its deferred tax assets and liabilities. As a result of this process, the Company recognized an additional net deferred tax asset of approximately $15.5 million. Additionally, the Company increased its valuation allowance by $15.5 million resulting in no impact to the net deferred tax asset.
(4)	This deduction relates to the reversal of the valuation allowance related to net operating loss carryforwards and other deferred tax assets resulting from the Company’s return to profitability and expected future earnings performance.

95

SIGNATURES

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

PARKER DRILLING COMPANY

By: 

/s/  Robert L. Parker Jr.

Robert L. Parker Jr.

Chairman, President, Chief Executive Officer and Director

Date: February 27, 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 Jr. Robert L. Parker Jr.	Chairman, President and Chief Executive Officer and Director (Principal Executive Officer)	February 27, 2007
By:	/s/  James W. Whalen James W. Whalen	Vice Chairman of the Board and Director	February 27, 2007
By:	/s/  David C. Mannon David C. Mannon	Senior Vice President and Chief Operating Officer	February 27, 2007
By:	/s/  W. Kirk Brassfield W. Kirk Brassfield	Senior Vice President and Chief Financial Officer (Principal Financial Officer)	February 27, 2007
By:	/s/  Lynn G. Cullom Lynn G. Cullom	Controller (Principal Accounting Officer)	February 27, 2007
By:	/s/  George J. Donnelly George J. Donnelly	Director	February 27, 2007
By:	/s/  John W. Gibson John W. Gibson	Director	February 27, 2007
By:	/s/  Robert W. Goldman Robert W. Goldman	Director	February 27, 2007
By:	/s/  Robert E. McKee III Robert E. McKee III	Director	February 27, 2007

96

Signature		Title	Date
By:	/s/  Roger B. Plank Roger B. Plank	Director	February 27, 2007
By:	/s/  R. Rudolph Reinfrank R. Rudolph Reinfrank	Director	February 27, 2007

97

INDEX TO EXHIBITS

EXHIBIT
NUMBER				DESCRIPTION
	10	(c)	—	Second 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 10(c) Commercial Paper, Inc., as Administrative Agent dated February 9, 2007.
	21		—	Subsidiaries of the Registrant.
	23		—	Consent of Independent Registered Public Accounting Firm.
	31	.1	—	Robert L. Parker Jr., Chairman, 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.
	31	.1	—	Robert L. Parker Jr., Chairman, President and Chief Executive Officer, Section 1350 Certification.
	31	.2	—	W. Kirk Brassfield, Senior Vice President and Chief Financial Officer, Section 1350 Certification.