PARKER DRILLING CO /DE/ - Annual Report: 2006 (Form 10-K)

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

 

 

COMMISSION FILE NUMBER 1-7573

 

PARKER DRILLING COMPANY

(Exact name of registrant as specified in its charter)

 

 

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:

 

 

Securities registered pursuant to Section 12(g) of the Act:

None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.  Yes o     No þ

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  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 Act Rule 12b-2. Large accelerated filer þ     Accelerated filer o     Non-accelerated filer o

 

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

 

The aggregate market value of our common stock held by non-affiliates on June 30, 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

 

 

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 on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish to, the Securities and Exchange Commission (“SEC”). Additionally, these reports are available on an Internet website maintained by the SEC. The address of that site is http://www.sec.gov. We voluntarily provide paper or electronic copies of our reports free of charge upon request.

 

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

 

We are a leading worldwide provider of contract drilling and drilling-related services. Since beginning operations in 1934, we have operated in 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:

 

 

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:

 

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 infrastructure and/or harsh environments requiring specialized drilling equipment with a large inventory of spare parts and other ancillary equipment; and (iii) difficult (i.e., high pressure, deep, hazardous or geologically challenging) wells requiring specialized drilling equipment and considerable experience to drill. Historically there have been a small number of competitors in international markets due to the remote locations and difficult drilling conditions; however a number of national drilling companies are now entering these markets due to a higher level of sustained oil and gas prices. A substantial portion of 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.

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

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.

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:

 

 

 

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

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.

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.

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.

 

The contract drilling and rental tools businesses involve a high degree of risk. You should consider carefully the risks and uncertainties described below and the other information included in this Form 10-K, including the financial statements and related notes, before deciding to invest in our securities. While these are the risks and uncertainties we believe are most important for you to consider, you should know that they are not the only risks or uncertainties facing us or which may adversely affect our business. If any of the following risks or uncertainties actually occur, our business, financial condition or results of operations could be adversely affected.

 

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:

 

 

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.

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:

 

 

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:

 

 

Our debt, and the covenants contained in the instruments governing our debt could have important consequences to you. For example, it could:

 

 

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

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:

 

 

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:

 

ITEM 1A.  RISK FACTORS (continued)

 

Risk Factors Related to Our Business (continued)

 

 

 

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.

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:

 

 

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 flights and/or the quarantine of drilling crews in foreign locations, which could materially impair our international operations

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,

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:

 

 

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

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:

 

ITEM 1A.  RISK FACTORS (continued)

 

 

 

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:

 

 

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.

ITEM 1A.  RISK FACTORS (continued)

 

DISCLOSURE NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

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

 

 

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

 

ITEM 1A.  RISK FACTORS (continued)

 

DISCLOSURE NOTE REGARDING FORWARD-LOOKING STATEMENTS (continued)

 

 

 

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

 

None.

 

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.

 

 

 

 

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.

 

 

 

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.

 

 

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.

 

 

 

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

 

There were no matters submitted to Parker Drilling Company security holders during the fourth quarter of 2006.

 

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:

 

 

Other Parker Drilling Company Officer

 

 

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:

 

 

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.

 

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 this Form 10-K.

 

 

 

 

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 a 10-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

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

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:

 

 

 

 

 

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

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 two variable-to-fixed interest rate swap agreements, which are still outstanding. The swap agreements do not qualify for hedge accounting and accordingly, we are reporting the mark-to-market change in the fair value of the interest rate derivatives currently in earnings. For 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

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:

 

 

 

RESULTS OF OPERATIONS (continued)

 

 

 

 

U.S. Drilling Segment

 

U.S. drilling revenues increased $39.7 million in 2005 to $128.3 million due to higher utilization and dayrates. 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.

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.

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

 

Loss on extinguishment of debt was $8.2 million in 2005 compared to $8.8 million in 2004, as we reduced outstanding debt and exchanged higher interest rate debt for lower interest rate debt in both years. In February 2005, we repurchased $25.0 million of our 10.125% Senior Notes with the proceeds received from the sale of jackup rig 25 and cash on hand, recognizing an expense of $1.4 million for the 105.0625 percent redemption price on the repurchase of the notes and capitalized debt issuance costs associated with the notes. In April 2005, we issued an additional $50.0 million in aggregate principal amount of our 9.625% Senior Notes due 2013 at a premium. The offering price of 111 percent of the principal amount resulted in gross proceeds of $55.5 million. The $5.5 million premium is recognized as long-term debt and is being amortized over the term of the notes. The additional notes were issued under an indenture dated October 10, 2003, under which $175.0 million in aggregate principal amount of notes in the same series were previously issued. On the same date that we issued the $50.0 million additional 9.625% Senior Notes, we issued a redemption notice for $65.0 million of our 10.125% Senior Notes at the redemption price of 105.0625 percent, resulting in a $3.3 million loss on the extinguishment of debt in the second quarter of 2005. During the third quarter of

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

 

 

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.

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

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 million sub-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:

 

 

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.

LIQUIDITY AND CAPITAL RESOURCES (continued)

 

Financing Activity (continued)

 

 

The following table summarizes our future contractual cash obligations.

 

 

 

 

 

We have entered into employment agreements with the executive officers of the Company; see Note 12 in the notes to the consolidated financial statements. We do not have any unconsolidated special-purpose entities, off-balance-sheet financing arrangements or guarantees of third-party financial obligations. We have no energy or commodity contracts.

 

OTHER MATTERS

 

Business Risks

 

Internationally, we specialize in drilling geologically challenging wells in locations that are difficult to access and/or involve harsh environmental conditions. Our international services are primarily utilized by major and national oil companies and integrated service providers in the exploration and development of reserves of oil 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

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, assumptions and/or estimates in the preparation of our consolidated financial statements. Other significant accounting policies are summarized in Note 1 in the notes to the consolidated financial statements.

 

Impairment of Property, Plant and Equipment.  We periodically evaluate our property, plant and equipment to ensure that the net carrying value is not in excess of the net realizable value. We review our property, plant and equipment for impairment when events or changes in circumstances indicate that the carrying value of such assets may be impaired. For example, evaluations are performed when we experience sustained significant declines in utilization and dayrates and we do not contemplate recovery in the near future, or when we reclassify property and equipment to assets held for sale or as discontinued operations as prescribed by SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” We consider a number of factors, including estimated undiscounted future cash flows, appraisals less estimated selling costs and current market value analysis in determining net realizable value. Assets are written down to fair value if the fair value is below net carrying value.

 

We recorded impairments to our long-lived assets of $4.9 million 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

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

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 two variable-to-fixed interest rate swap agreements to reduce our cash flow exposure to increases in interest rates on our Senior Floating Rate Notes. The interest rate swap agreements provide us with interest rate protection on the Senior Floating Rate Notes due 2010.

 

We do not use hedge accounting treatment for these interest rate swap agreements as we determined that the hedges would not be highly effective as defined by SFAS 133. The ineffectiveness of the hedges is caused by embedded written call options in the interest rate swap agreements that do not exist in the notes. Accordingly, we recognize the volatility of the swap agreements on a mark-to-market basis in our consolidated statement of operations. For the year ended December 31, 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 the mark-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.

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.

 

Interest Rate Risk

 

We entered into our current variable-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:

 

 

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.

 

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 in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

 

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over

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

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