PARKER DRILLING CO /DE/ - Annual Report: 2008 (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 o     No þ

 

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

 

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

 

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

 

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

(Do not check if a smaller reporting company)

 

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

 

The aggregate market value of our common stock held by non-affiliates on June 30, 2008 was $941.9 million. At January 31, 2009, there were 113,455,821 shares of common stock issued and outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of our definitive proxy statement for the Annual Meeting of Shareholders to be held on April 21, 2009 are incorporated by reference in Part III.

 

 

TABLE OF CONTENTS

 

 

 

General

 

Parker Drilling Company was incorporated in the state of Oklahoma in 1954. In March 1976, the state of incorporation of the Company was changed to Delaware through the merger of the Oklahoma corporation into its wholly-owned subsidiary Parker Drilling Company, a Delaware corporation. Unless otherwise indicated, the terms “Company,” “we,” “us” and “our” refer to Parker Drilling Company together with its subsidiaries and “Parker Drilling” refers solely to the parent, Parker Drilling Company. We make available free of charge on our website at www.parkerdrilling.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish such material to, the Securities and Exchange Commission (“SEC”). Additionally, these reports are available on an Internet website maintained by the SEC at http://www.sec.gov. We voluntarily provide paper or electronic copies of our reports free of charge upon request.

 

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

 

We are a leading worldwide provider of contract drilling and drilling-related services. Since beginning operations in 1934, we have operated in 53 foreign countries and the United States, making us among the most geographically experienced drilling contractors in the world. We have extensive experience and expertise in drilling geologically difficult wells and in managing the logistical and technological challenges of operating in remote, harsh and ecologically sensitive areas. Our quality, health, safety and environmental policies and procedures are best in class.

 

Our 2008 revenues are derived from five segments:

 

 

 

Our Rig Fleet

 

The diversity of our rig fleet, both in terms of geographic location and asset class, enables us to provide a broad range of services to oil and gas operators worldwide. As of December 31, 2008, our fleet of rigs consisted of:

 

 

 

Our Project Management and Engineering Services Business

 

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

 

Our Rental Tools Business

 

Our subsidiary, Quail Tools, L.P., (Quail Tools) provides premium rental tools for land and offshore oil and gas drilling and workover activities. Quail Tools offers a full line of drill pipe, drill collars, tubing, high- and low-pressure blowout preventers, choke manifolds, junk and cement mills and casing scrapers. Approximately one-fourth of Quail Tools’ equipment is utilized in offshore and coastal water operations of the Gulf of Mexico. Quail Tools’ base of operations is in New Iberia, Louisiana. Other facilities are located in Texas, Wyoming and North Dakota. Quail Tools’ principal customers are major and independent oil and gas exploration and production companies operating in the Gulf of Mexico and other major U.S. energy producing markets. Quail Tools also provides rental tools to customers operating internationally in Trinidad and Tobago, Mexico, Russia, Singapore, Nigeria, Brazil and Chad.

 

Construction Contracts Business

 

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

 

Our Market Areas

 

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

 

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

 

Our Strategy

 

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

 

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

 

Our Strategy (continued)

 

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

 

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

 

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

 

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

 

Our Competitive Strengths

 

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

 

Geographically Diverse Operations and Assets.  We currently operate in Algeria, Colombia, Indonesia, Kazakhstan, Kuwait, Mexico, New Zealand, Papua New Guinea, Russia, Turkmenistan and the United States. Since our founding in 1934, we have operated in 53 foreign countries and the United States, making us among the most geographically diverse drilling contractors in the world. Our international revenues constituted approximately 52 percent of our total revenues in the twelve months ended December 31, 2008.

 

Outstanding Safety, Preventive Maintenance, Inventory Control and Training Programs.  We have an outstanding safety record. In 2008, we achieved the lowest Total Recordable Incident Rate (“TRIR”) in our history. Our safety record, as evidenced by our low TRIR, has made us a leader in occupational injury prevention for the last ten years. In recognition of our achievements we were named one of America’s Safest Companies by Occupational Hazards magazine in 2007. This, along with integrated quality and safety maintenance, and supply chain management programs, has contributed to our success in obtaining drilling contracts, as well as contracts to manage and provide labor resources to drilling rigs owned by third parties. Our training center provides safety and technical training curriculums in four different languages and provides regulatory compliance training throughout the world.

 

Strong and Experienced Senior Management Team.  Our management team has extensive experience in the contract drilling industry. Our chairman and chief executive officer, Robert L. Parker Jr. joined Parker Drilling in 1973 and has served as our president from 1977 through June 2007, chief executive officer since 1991 and chairman of the board since April 2006. Under the leadership of Mr. Parker Jr., we have continued our reputation as a leading worldwide provider of contract drilling services. David C. Mannon joined our senior management team in late 2004 as senior vice president and chief operating officer and was appointed president in July 2007. Prior to joining our Company, Mr. Mannon served in various managerial positions, culminating with his appointment as president and chief executive officer for Triton Engineering Services Company, a subsidiary of Noble Drilling. He brings a broad range of over 25 years of experience to our drilling operations which enhances our ability to achieve our goals. Our chief financial officer, W. Kirk Brassfield, joined Parker Drilling in 1998 and has served in several executive positions including vice

 

Our Competitive Strengths (continued)

 

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

 

Project Management

 

We are active in managing and providing labor resources for drilling rigs owned by third parties. In Russia, we designed, constructed and sold a rig to Exxon Neftegas Limited (“ENL”) and currently manage drilling operations under a five-year Operations and Maintenance (“O&M”) contract. This rig has drilled one of the world’s longest extended reach wells from Sakhalin Island reaching out over seven miles under the sea floor for a total measured depth of 38,322 feet. We also supervised construction of a second rig to drill from the Orlan platform and began a five-year O&M contract for ENL offshore Sakhalin, Russia in September 2005.

 

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

 

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

 

Competition

 

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

 

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

 

In international land markets, we compete with a number of international drilling contractors as well as smaller local contractors. Most contracts are awarded on a competitive bidding basis, but the operators often consider factors other than the lowest price, including technical expertise and quality of equipment. National drilling contractors have increased competition in international markets in recent years. Although national drilling contractors typically have lower labor and mobilization costs, we are generally able to distinguish ourselves from these national companies based on our technical expertise, quality of our equipment, preventive maintenance, experience and safety record. In international markets, our experience in operating in challenging environments has been a significant factor in securing contracts. We believe that the market for drilling contracts will continue to be highly competitive for the foreseeable future.

 

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

 

Customers

 

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

 

Customers (continued)

 

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

 

An increasing trend indicates that a number of our customers have been seeking to establish exploration or development drilling programs based on partnering relationships or alliances with a limited number of preferred drilling contractors. Such relationships or alliances can result in longer-term work and higher efficiencies that increase profitability for drilling contractors and result in a lower overall well cost for oil and gas operators. We are currently a preferred contractor for operators in certain U.S. and international locations which our management believes is a result of our reputation for providing efficient, safe, environmentally conscious and innovative drilling services, in addition to the quality of equipment, personnel, service and experience. At the core of our operating philosophy are the four pillars of a preferred drilling contractor: Safety, Training, Performance and Technology.

 

Contracts

 

Most drilling contracts are awarded based on competitive bidding. The rates specified in drilling contracts are generally on a dayrate basis, and vary depending upon the type of rig employed, equipment and services supplied, geographic location, term of the contract, competitive conditions and other variables. Our contracts generally provide for an operating dayrate during drilling operations, with lower rates for periods of equipment breakdown, adverse weather or other conditions, or no payment if the conditions continue beyond a certain time. When a rig mobilizes to or demobilizes from an operating area, the contract typically provides for a different dayrate or specified fixed payments during the mobilization or demobilization. The terms of most of our contracts are based on either a specified period of time or the time required to drill a specified number of wells. The contract term in some instances may be extended by the customer exercising options for the drilling of additional wells or for an additional time period, or by exercising a right of first refusal. Most of our contracts may be terminated by the customer prior to the end of the term without penalty under certain circumstances, such as the loss or major damage to the drilling unit or other events that cause the suspension of drilling operations beyond a specified period of time. The majority of our contracts require the operator to pay an early termination fee if the operator terminates a contract before the end of the term without cause, but in the remainder of the contracts the operator has the discretion to terminate the contract without cause prior to the end of the term without penalty.

 

Rental tools contracts are typically on a dayrate basis with rates based on type of equipment, investment and competition. Rental rates generally apply from the time the equipment leaves our facility until it is returned. Rental contracts generally require the customer to reimburse Parker for lost or damaged equipment.

 

Insurance and Indemnification

 

In our drilling contracts, we generally seek to obtain indemnification from our customers for some of the risks related to our drilling services. To the extent that we are unable to transfer such risks to customers by contract or indemnification agreements, we generally seek protection through insurance. To address the hazards inherent in our business, we maintain insurance coverage that includes physical damage coverage, third party general liability coverage, employer’s liability, environmental and pollution coverage and other coverage. We believe that our insurance coverage is customary for the industry and adequate for our business. However, there are risks against which insurance will not adequately protect us or insurance may not be available to cover any or all of the potential liability arising from all of the consequences and hazards we may encounter in our drilling operations. See Item 1A, “Risk Factors” for additional information.

 

Employees

 

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

 

 

Environmental Considerations

 

Our operations are subject to numerous federal, state, local and foreign laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous foreign and domestic governmental agencies, such as the U.S. Environmental Protection Agency (“EPA”), issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or may result in injunctive relief for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences; restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities; limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas; require remedial action to prevent pollution from former operations; and impose substantial liabilities for pollution resulting from our operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly compliance could adversely affect our operations and financial position, as well as those of similarly situated entities operating in the same markets. While our management believes that we are in substantial compliance with current applicable environmental laws and regulations, there is no assurance that compliance can be maintained in the future.

 

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

 

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

 

The OPA liability for a mobile offshore drilling rig is determined by whether the unit is functioning as a vessel or is in place and functioning as an offshore facility. If operating as a vessel, liability limits of $600 per gross ton or $0.5 million, whichever is greater, apply. If functioning as an offshore facility, the mobile offshore drilling rig is considered a “tank vessel” for spills of oil on or above the water surface, with liability limits of $1,200 per gross ton or $10.0 million, whichever is greater. To the extent damages and removal costs exceed this amount, the mobile offshore drilling rig will be treated as an offshore facility and the offshore lessee will

 

Environmental Considerations (continued)

 

be responsible up to higher liability limits for all removal costs plus $75.0 million. The party must reimburse all removal costs actually incurred by a governmental entity for actual or threatened oil discharges associated with any Outer Continental Shelf facilities, without regard to the limits described above. A party also cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply.

 

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

 

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

 

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

 

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

 

CERCLA (also known as “Superfund”) and comparable state laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. While CERCLA exempts crude oil from the definition of hazardous substances for purposes of the statute, our operations may involve the use or handling of other materials that may be classified as hazardous substances. CERCLA assigns strict liability to each responsible party for all response and remediation costs, as well as natural resource damages. Few defenses exist to the liability imposed by CERCLA. Several years ago we received an information request under CERCLA identifying a subsidiary of Parker Drilling as a potentially responsible party with respect to the Gulfco Marine Maintenance, Inc. Superfund site in Freeport, Texas (EPA No. TXD055144539). We responded with information and documents. In January, 2008 we received an administrative order to participate in an

 

Environmental Considerations (continued)

 

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

 

RCRA generally does not regulate most wastes generated by the exploration and production of oil and gas. RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters, and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy.” However, these wastes may be regulated by EPA or state agencies as solid waste. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes, and waste oils, may be regulated as hazardous waste. Although the costs of managing solid and hazardous wastes may be significant, we do not expect to experience more burdensome costs than similarly situated companies involved in drilling operations in the Gulf Coast market.

 

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

 

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

 

FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS

 

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

 

EXECUTIVE OFFICERS

 

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

 

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

 

(2) David C. Mannon, 51, president and chief operating officer, joined Parker Drilling in December 2004 as senior vice president and chief operating officer. He was appointed president in July 2007. From April 2003 through November 2004, Mr. Mannon held the positions of President and chief executive officer of Triton Engineering Services Company (“Triton”), a subsidiary of Noble Drilling. From 1988 to March 2003 he held various other positions with Triton. From 1980 through 1988, Mr. Mannon served SEDCO-FOREX, formerly SEDCO, as a drilling engineer. Mr. Mannon is currently a member of the International Association of Drilling Contractors (IADC), Society of Petroleum Engineers (SPE) and the American Association of Drilling Engineers (AADE), and also serves on the Upstream Committee of the American Petroleum Institute (API).

 

(3) W. Kirk Brassfield, 53, senior vice president and chief financial officer, joined Parker Drilling in March 1998 as controller and principal accounting officer. From 1991 through March 1998, Mr. Brassfield served in various positions, including subsidiary controller and director of financial planning of MAPCO Inc., a diversified energy company. From 1979 through 1991, Mr. Brassfield served at the public accounting firm, KPMG.

 

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

 

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

 

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

 

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

 

EXECUTIVE OFFICERS (continued)

 

Other Parker Drilling Company Officer

 

(8) David W. Tucker, 53, treasurer, joined Parker Drilling in 1978 as a financial analyst and served in various financial and accounting positions before being named chief financial officer of the Company’s wholly-owned subsidiary, Hercules Offshore Corporation, in February 1998. Mr. Tucker was named treasurer in 1999.

 

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

 

Risks Related to Our Business

 

Due to the on-going volatility in oil and natural gas prices, the ongoing credit crisis, and the deteriorating global economic environment, certain customers have curtailed or delayed drilling programs. We are unable to anticipate whether or not our customers will further curtail or delay drilling programs. There is a risk that our vendors will not fulfill their commitments. The global economic conditions may result in an extended decrease in demand for our drilling rigs and rental tools business, which could have a material adverse effect on our drilling and rental tool business.

 

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

 

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

 

Rig upgrade, refurbishment and construction projects are subject to risks, including delays and cost overruns, which could have an adverse impact on our results of operations and cash flows.

 

We often have to make upgrade and refurbishment expenditures for our rig fleet to comply with our quality management and preventive maintenance system or contractual requirements or when repairs are required or to comply with environmental regulations. We may also make significant expenditures when we move rigs from one location to another. Rig upgrade, refurbishment and construction projects are subject to the risks of delay or cost overruns inherent in any large construction project, including the following:

 

ITEM 1A.  RISK FACTORS (continued)

 

Risks Related to Our Business (continued)

 

 

 

Significant cost overruns or delays could adversely affect our financial condition and results of operations. Additionally, capital expenditures for rig upgrade, refurbishment or construction projects could exceed our planned capital expenditures, impairing our ability to service our debt obligations.

 

Failure to retain skilled and experienced personnel could affect our operations.

 

We require highly skilled and experienced personnel to provide technical services and support for our drilling operations. Although we use our training center to train personnel and promote from within, it has become more difficult to retain existing personnel.

 

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

 

As of December 31, 2008, we had:

 

 

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

 

Cash flows from operating activities have been strong in recent years. However, we have in the past, and may in the future, incur negative cash flows from one or more segments of our operating activities. Our future cash flows from operating activities will be influenced by the demand for our drilling services, the utilization of our rigs, the dayrates that we receive for our rigs, general economic conditions and financial, business and other factors affecting our operations, many of which are beyond our control.

 

If we are unable to service our debt obligations, we may have to:

 

 

Additional indebtedness or equity financing may not be available to us in the future for the refinancing or repayment of existing indebtedness, or if available, such additional indebtedness or equity financing may not be available on a timely basis, or on terms acceptable to us and within the limitations contained in the

ITEM 1A.  RISK FACTORS (continued)

 

Risks Related to Our Business (continued)

 

documentation contained in our existing debt instruments. In addition, in the event we decide to sell assets, we can provide no assurance as to the timing of any asset sales or the proceeds that could be realized by us from any such asset sale. Our ability to generate sufficient cash flow from operating activities to pay the principal of and interest on our indebtedness is subject to certain market conditions and other factors which are beyond our control.

 

Increases in the level of our debt and the covenants contained in the instruments governing our debt could have important consequences to you. For example, they could:

 

 

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

 

Our business requires substantial capital (we anticipate that our capital expenditures in 2009 will be approximately $180 — $200 million, including approximately $30 — $35 million for maintenance projects). We may require additional capital in the event of significant departures from our current business plan or unanticipated expenses. Sources of funding for our future capital requirements may include any or all of the following:

 

 

Due to the current credit crisis and our leveraged capital structure, additional financing may not be available on a timely basis or on terms acceptable to us and within the limitations contained in the indentures governing the 9.625% Senior Notes and the 2.125% Convertible Senior Notes and the documentation governing our senior secured credit facility. Failure to obtain appropriate financing, should the need for it develop, could impair our ability to fund our capital expenditure requirements and meet our debt service requirements and could have an adverse effect on our business.

 

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

 

The success of our operations is materially dependent upon the exploration and development activities of the major, independent and national oil and gas companies that comprise our customer base. Oil and natural gas prices and market expectations can be extremely volatile, and therefore, the level of exploration and production activities can be extremely volatile. Increases or decreases in oil and natural gas prices and

ITEM 1A.  RISK FACTORS (continued)

 

Risks Related to Our Business (continued)

 

expectations of future prices could have an impact on our customers’ long-term exploration and development activities, which in turn could materially affect our business and financial performance. Generally, changes in the price of oil have a greater impact on our international operations while changes in the price of natural gas have a greater impact on our operations in the Gulf of Mexico.

 

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

 

 

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

 

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

 

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

 

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

 

A substantial percentage of our revenues are generated from a relatively small number of customers, and the loss of a major customer would adversely affect us. In 2008, our two largest customers, ExxonMobil (including subsidiaries and joint ventures) and Schlumberger accounted for approximately 13 percent and 9 percent of our total revenues, respectively. Our ten most significant customers collectively accounted for approximately 56 percent of our total revenues in 2008. Our results of operations could be adversely affected if any of our major customers terminate their contracts with us, fail to renew our existing contracts or refuse to award new contracts to us.

ITEM 1A.  RISK FACTORS (continued)

 

Risks Related to Our Business (continued)

 

Contract drilling and the rental tools business are highly competitive.

 

The contract drilling and rental tools markets are highly competitive and no single competitor is dominant. Although the international drilling market has not experienced any material decrease in utilization as a result of the credit crisis and worldwide economic downturn, demand in the Gulf of Mexico barge market has decreased significantly during the past few months. During periods of decreased demand we historically experience significant reductions in dayrates and utilization. We anticipate that current demand for our rental tools to maintain at or near current levels for the foreseeable future. Contract drilling companies compete primarily on a regional basis, and competition may vary significantly from region to region at any particular time. Many drilling and workover rigs can be moved from one region to another in response to changes in levels of activity, provided market conditions warrant, which may result in an oversupply of rigs in an area. Many competitors have constructed numerous rigs during the previous period of high energy prices. We have previously reported that historically the number of rigs available in the markets we operate has exceeded the demand for rigs for extended periods of time, resulting in intense price competition, as we expect this to occur based on current market conditions. Most drilling and workover contracts are awarded on the basis of competitive bids, which also results in price competition. We believe that competition for drilling contracts will continue to be intense for the foreseeable future. If we cannot keep our rigs utilized, our financial performance will be adversely impacted. The rental tools market is also characterized by vigorous competition among several competitors. Many of our competitors in both the contract drilling and rental tools business possess greater financial resources than we do.

 

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

 

We have operations in 10 foreign countries. Our international operations are subject to interruption, suspension and possible expropriation due to terrorism, war, civil disturbances, political instability and similar events and we have previously suffered loss of revenue and damage to equipment due to political violence. We may not be able to obtain insurance policies covering such risks, especially political violence coverage, and such policies may only be available with premiums that are not commercially justifiable.

 

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

 

We derive a significant portion of our revenues from our international operations. In 2008, we derived approximately 52 percent of our revenues from operations in countries outside the United States. Our international operations are subject to the following risks, among others:

 

 

Our international operations are subject to the laws and regulations of a number of foreign countries. Additionally, our ability to compete in international contract drilling markets may be adversely affected by

ITEM 1A.  RISK FACTORS (continued)

 

Risks Related to Our Business (continued)

 

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

 

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

 

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

 

Our international operations are also subject to disruption due to risks associated with worldwide health concerns. In particular, although we have no evidence to believe this will occur, it is possible that concerns due to the transmission of illness (viral, bacterial or parasitic) could result in cancellations or delays in international flights and/or the quarantine of drilling crews in foreign locations, which could materially impair our international operations and consequently have an adverse effect on our business and financial results for the operations that are affected.

 

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

 

Tax and other laws and regulations are not always interpreted consistently among local, regional and national authorities. See Note 13 in the notes to the consolidated financial statements for an example of pending tax disputes. The ultimate outcome of these disputes is not certain, and it is possible that the outcome could have an adverse effect on our financial performance. It is also possible that in the future we will be subject to similar disputes concerning taxation and other matters in countries in which we do business, and these disputes could have a material adverse effect on our financial performance.

 

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

 

Substantially all of our operations are subject to hazards that are customary for oil and natural gas drilling operations, including blowouts, reservoir damage, loss of well control, cratering, oil and natural gas well fires and explosions, natural disasters, pollution and mechanical failure. Our offshore operations also are subject to hazards inherent in marine operations, such as capsizing, grounding, collision and damage from severe weather conditions. Any of these risks could result in damage to or destruction of drilling equipment, personal injury and property damage, suspension of operations or environmental damage. We have had accidents in the past demonstrating some of these hazards. Generally, drilling contracts provide for the division of responsibilities between a drilling company and its customer, and we generally obtain indemnification from our customers by contract for some of these risks. However, the laws of certain countries place significant limitations on the enforceability of indemnification provisions that allow a contractor to be indemnified for damages resulting from the drilling contractor’s fault. To the extent that we are unable to transfer such risks to customers by contract or indemnification agreements, we generally seek protection through insurance. However, we have self-insured retention or deductibles for certain losses relating to workers’ compensation, employers’ liability,

ITEM 1A.  RISK FACTORS (continued)

 

Risks Related to Our Business (continued)

 

general liability (for onshore liability), protection and indemnity (for offshore liability), and property damage. In addition, insurance for some risks, such as reservoir damage, is not available. For further information, see Note 13 in the notes to the consolidated financial statements. These insurance or indemnification agreements may not adequately protect us against liability from all of the consequences of the hazards and risks described above. The occurrence of an event not fully insured or for which we are not indemnified against, or the failure of a customer or insurer to meet its indemnification or insurance obligations, could result in substantial losses. In addition, insurance may not continue to be available to cover any or all of these risks. Even if such insurance is available, insurance premiums or other costs may rise significantly in the future, so as to make the cost of such insurance prohibitive.

 

Although not a hazard specific to our drilling operations, we could incur significant liability in the event of loss or damage to proprietary data of operators or third parties during our transmission of this valuable data.

 

Government regulations and environmental risks, which reduce our business opportunities and increase our operating costs, might worsen in the future.

 

Government regulations control and often limit access to potential markets and impose extensive requirements concerning employee safety, environmental protection, pollution control and remediation of environmental contamination. Environmental regulations, in particular, prohibit access to some markets and make others less economical, increase equipment and personnel costs and often impose liability without regard to negligence or fault. In addition, governmental regulations may discourage our customers’ activities, reducing demand for our products and services. We may be liable for damages resulting from pollution of offshore waters and, under United States regulations, must establish financial responsibility in order to drill offshore. See Part I, Business, “Environmental Considerations.”

 

We are regularly involved in litigation, some of which may be material.

 

We are regularly involved in litigation, claims and disputes incidental to our business, which at times involve claims for significant monetary amounts, some of which would not be covered by insurance. We undertake all reasonable steps to defend ourselves in such lawsuits. Nevertheless, we cannot predict the ultimate outcome of such lawsuits and any resolution which is adverse to us could have a material adverse effect on our financial condition. See Note 13, “Commitments and Contingencies” in Item 8 of this Form 10-K for a discussion of the material legal proceedings affecting us.

 

We are subject to the Foreign Corrupt Practices Act (“FCPA”) and other laws concerning our international operations, and currently are conducting an investigation into possible violations. The Securities and Exchange Commission and the Department of Justice are conducting parallel investigations into possible FCPA violations. If we are found to have violated the FCPA or other legal requirements, we may be subject to criminal and civil penalties and other remedial measures, which could materially harm our business, results of operations, financial condition and liquidity.

 

The Company operates in a number of jurisdictions that pose an elevated risk of potential violations under the FCPA and other laws concerning our international operations. As previously disclosed, the Company received requests from the Department of Justice (“DOJ”) in July 2007 and the United States Securities and Exchange Commission (“SEC”) in January 2008 relating to the Company’s utilization of the services of a freight forwarding and customs agent. In response to these requests, the Company is conducting an internal investigation. The DOJ and the SEC are conducting parallel investigations into possible violations of U.S. law by the Company, including the FCPA. In particular, the DOJ and SEC are investigating the Company’s use of customs and freight forwarding services agents in certain countries in which the Company currently operates or formerly operated, including Kazakhstan and Nigeria. The Company is fully cooperating with the DOJ and SEC investigations. At this point, we are unable to predict the duration, scope or result of the DOJ and SEC investigations or whether either agency will commence any legal action. If we are not in compliance with the

ITEM 1A.  RISK FACTORS (continued)

 

Risks Related to Our Business (continued)

 

FCPA and other laws governing the conduct of our business in international locations (including other United States laws and regulations as well as local laws), we may be subject to criminal and civil penalties and other remedial measures, which could have an adverse impact on our business, results of operations, financial condition and liquidity.

 

We are subject to laws and regulations concerning our international operations, including export restrictions, U.S. economic sanctions and other activities that we conduct abroad. We are conducting an internal review concerning our compliance with these legal requirements. If we are not in compliance with applicable legal requirements, we may be subject to civil or criminal penalties and other remedial measures, which could materially harm our business, results of operations, financial condition and liquidity.

 

Our international operations are subject to laws and regulations restricting our international operations, including activities involving restricted countries, organizations, entities and persons that have been identified as unlawful actors or that are subject to U.S. economic sanctions. Pursuant to an internal review, we have identified certain shipments of equipment and supplies that were routed through Iran as well as other activities that may have violated applicable U.S. laws and regulations. In addition, we have engaged in drilling wells in the Korpedje Field in Turkmenistan, from where natural gas may be exported by pipeline to Iran. We are currently reviewing these shipments, transactions and drilling activities to determine whether the timing, nature and extent of such activities or other conduct may have given rise to violations of these laws and regulations. Although we are unable to predict the scope or result of this internal review or its ultimate outcome, we have initiated voluntary disclosure of these potential compliance issues to the appropriate U.S. government agency. Any violations of these laws and regulations, including fines, penalties or restrictions on routes of shipping and drilling activities, could adversely affect our reputation and the market for our shares, and may require certain of our investors to disclose their investment in our Company under certain state laws. If we are not in compliance with export restrictions, U.S. economic sanctions or other laws and regulations that apply to our international operations, we may be subject to civil or criminal penalties and other remedial measures, which could have an adverse impact on our business, results of operations, financial condition and liquidity.

 

Risks Related to Our Common Stock

 

Market price of our common stock currently changing significantly.

 

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

 

ITEM 1A.  RISK FACTORS (continued)

 

Risks Related to Our Common Stock (continued)

 

 

A hostile takeover of our Company would be difficult.

 

Some of the provisions of our Restated Certificate of Incorporation and of the Delaware General Corporation Law may make it difficult for a hostile suitor to acquire control of our Company and to replace our incumbent management. For example, our Restated Certificate of Incorporation provides for a staggered Board of Directors and permits the Board of Directors, without stockholder approval, to issue additional shares of common stock or a new series of preferred stock.

 

Risks Related to our Debt Securities

 

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

 

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

 

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

 

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

 

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

 

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

ITEM 1A.  RISK FACTORS (continued)

 

Risks Related to our Debt Securities (continued)

 

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

 

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

 

 

 

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

 

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

 

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

 

In addition, the change of control provisions in the indenture governing our 9.625% Senior Notes may not protect the holders of our notes from certain important corporate events, such as a leveraged recapitalization (which would increase the level of our indebtedness), reorganization, restructuring, merger or other similar transaction, unless such transaction constitutes a “Change of Control” under the indenture. Such a transaction may not involve a change in voting power or beneficial ownership or, even if it does, may not involve a

ITEM 1A.  RISK FACTORS (continued)

 

Risks Related to our Debt Securities (continued)

 

change that constitutes a “Change of Control” as defined in the indenture that would trigger our obligation to repurchase the notes. Therefore, if an event occurs that does not constitute a “Change of Control” as defined in the indenture, we will not be required to make an offer to repurchase the notes and the holders may be required to continue to hold their notes despite the event.

 

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

 

Upon the occurrence of a fundamental change as defined in the indenture governing our 2.125% Convertible Senior Notes, subject to certain conditions, we will be required to make an offer to repurchase for cash all outstanding notes at 100% of their principal amount plus accrued and unpaid interest, including additional amounts, if any, up to but not including the date of repurchase. In addition, unless we elect to satisfy our conversion obligation entirely in shares of our common stock, upon a conversion, we will be required to make a cash payment of up to $1,000 for each $1,000 in principal amount of notes converted. However, we may not have enough available cash or be able to obtain financing at the time we are required to make repurchases of tendered notes or settlement of converted notes. Any credit facility in place at the time of a repurchase or conversion of the notes may also define as a default thereunder the events requiring repurchase or cash payment upon conversion of the notes or otherwise limit our ability to use borrowings to pay any cash payable on a repurchase or conversion of the notes and may prohibit us from making any cash payments on the repurchase or conversion of the notes if a default or event of default has occurred under that facility without the consent of the lenders under that credit facility. Our failure to repurchase tendered notes at a time when the repurchase is required by the indenture or to pay any cash payable on a conversion of the notes would constitute a default under the indenture. A default under the indenture or the fundamental change itself could lead to a default under the other existing and future agreements governing our indebtedness. If the repayment of the related indebtedness were to be accelerated after any applicable notice or grace periods, we may not have sufficient funds to repay the indebtedness and repurchase the notes or make cash payments upon conversion thereof.

ITEM 1A.  RISK FACTORS (continued)

 

DISCLOSURE NOTE REGARDING FORWARD-LOOKING STATEMENTS

 

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

 

 

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

 

Land Rigs

 

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

 

 

 

Barge Rigs

 

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

 

 

Barge Rigs (continued)

 

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

 

 

 

 

Barge Rigs (continued)

 

 

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

 

 

 

 

 

For information on Legal Proceedings, see Note 13, Commitments and Contingencies, in the notes to the consolidated financial statements included in Item 8 of this annual report on Form 10-K, which information is incorporated herein by reference.

 

 

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

 

 

Parker Drilling Company’s common stock is listed for trading on the New York Stock Exchange under the symbol “PKD.” At the close of business on December 31, 2008, there were 1,895 holders of record of Parker Drilling common stock. The following table sets forth the high and low prices per share of Parker Drilling’s common stock, as reported on the New York Stock Exchange composite tape, for the periods indicated:

 

 

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

 

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

 

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

 

The following table presents selected historical consolidated financial data derived from the audited financial statements of Parker Drilling Company for each of the five years in the period ended December 31, 2008. The following financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes appearing elsewhere in this Form 10-K.

 

 

 

 

 

 

OVERVIEW AND OUTLOOK

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

OVERVIEW AND OUTLOOK (continued)

 

Overview  (continued)

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

We recorded net income of $25.6 million for the year ended December 31, 2008 which included a goodwill write-off of $100.3 million, as compared to net income of $104.1 million for the year ended December 31, 2007. Operating gross margin was $191.5 million for the year ended December 31, 2008 which consists of increases in international drilling operations, project management and engineering services, construction contract and rental tools of $63.6 million offset by a decrease of $41.7 million in U.S. drilling and a $31.2 million increase in depreciation expense as compared to the year ended December 31, 2007.

 

In 2008, we began separate presentation of our project management and engineering services segment. . We have begun to separately monitor this non-capital intensive segment as a focus of our long-term strategic growth plan. Prior to 2008, these results were included in the U.S. and International drilling segments, and as

OVERVIEW AND OUTLOOK (continued)

 

Overview  (continued)

 

such, 2007 segment information has been recasted to conform to the new presentation. We also created a new segment in 2008 to separately reflect results of our extended-reach rig construction contract.

 

RESULTS OF OPERATIONS (continued)

 

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

 

 

 

RESULTS OF OPERATIONS (continued)

 

 

 

U.S. Drilling Segment

 

Revenues for the U.S drilling segment decreased $51.6 million to $173.6 million for the year ended December 31, 2008 as compared to the year ended December 31, 2007. The decreased revenues were primarily due to a $40.3 million decrease for our barge drilling operations as average dayrates for our deep drilling barges fell approximately $4,500 per day. Also in 2007 we had two land rigs drilling in the U.S. that historically operate in our international land segment. These rigs contributed $11.3 million in revenues as compared to no U.S. revenues in the same period for 2008 as the two rigs were relocated to our Mexico operations during 2007.

 

As a result of the above mentioned factors, gross margins, excluding depreciation and amortization, decreased $41.7 million to $89.2 million for the year ended December 31, 2008 as compared to the same period of 2007.

 

International Drilling Segment

 

International drilling revenues increased $111.5 million to $325.1 million for the year ended December 31, 2008 as compared to the same period in 2007.

 

Revenues in Mexico, Algeria and Turkmenistan increased by $69.0 million, $11.1 million and $3.6 million, respectively, as there were minimal drilling operations in these countries during 2007 and a dayrate increase for our barge rig operating in Mexico. Revenues in the CIS region increased by $63.7 million primarily attributable to a $19.5 million increase in the Karachaganak area of Kazakhstan as a result of the addition of Rigs 249 and 258 to existing operations of Rigs 107 and 216, an increase in the dayrate for our barge rig operating in the Caspian Sea and the above mentioned Turkmenistan revenues. These increases were offset by lower utilization of our two rigs in Colombia in 2008, resulting in a decrease of $22.2 million as compared to 2007.

 

In our Asia Pacific region, revenues decreased $8.2 million due mainly to completion of our contract within Bangladesh for Rig 225 in March 2007 ($3.5 million), lower utilization (50%) in Papua New Guinea ($15.6 million) being partially offset by a $4.8 million increase in New Zealand due to increased dayrates and operating days and a $6.2 million increase in our Indonesia operations.

 

International operating gross margin, excluding depreciation and amortization, increased $34.5 million to $93.7 million during the year ended 2008 compared to the year ended 2007, due primarily to favorable increases in our operations in Mexico ($25.5 million) and the CIS region ($21.4 million), offset by decreases in Colombia ($14.3 million) and our Asia Pacific region ($2.2 million). The increase in Mexico is attributable to five rigs operating the entire period in 2008 and two rigs commencing operations in February in 2008 as we were in the start up phase for these operations in the third quarter of 2007. In the CIS region, the primary driver was the increased dayrates for our barge rig operating in the Caspian Sea, increased utilization in the

RESULTS OF OPERATIONS (continued)

 

International Drilling Segment (continued)

 

Karachaganak area of Kazakhstan and operation of Rig 230 in Turkmenistan were the main drivers of the $24.1 million increase. In Colombia, the completion of our contracts in late 2007 and late February 2008 were the cause of the decrease, although Rig 268 began a one year contract in mid-May 2008. Our Asia Pacific region decline of $2.2 million was a result of Rig 225 in Bangladesh not operating in 2008 as compared to 2007 and Papua New Guinea incurring lower utilization when compared to the same period of 2007, with these declines being partially offset by increases in our New Zealand and Indonesia operations.

 

Project Management and Engineering Services Segment

 

Revenues for this segment increased $32.4 million during 2008 as compared to 2007. This increase was the result of higher revenues for our operations in Sakhalin Island ($20.9 million) and Kuwait ($13.1 million). For Sakhalin operations, $9.1 million was due to higher dayrates and $11.8 million due to reimbursable expenses on which we earn a fixed fee. For our Kuwait contract $11.0 million of the increase was due to reimbursables and $2.1 million was due to additional services provided. These increases were partially offset by a decrease of $1.9 million in our Papua New Guinea project management contracts that ceased operations during 2007. Project management and engineering services do not incur depreciation and amortization, and as such, gross margin for this segment increased $5.7 million in the current period as compared to the prior period. Labor rate increases effective in November 2008 which were retroactive to June 2008, positively impacted gross margin.

 

Construction Contract Segment

 

Revenues from the construction of the extended-reach drilling rig for use in the Alaskan Beaufort Sea were $49.4 million for 2008. This project is a cost plus fixed fee contract. Gross margin for the EPCI project was $2.6 million based on the percentage of completion of the contract in which costs-to-date compared to projected total costs are used to determine the percent complete (cost to cost method).

 

Rental Tools Segment

 

Rental tools revenues increased $33.5 million to $171.6 million during the year ended December 31, 2008 as compared to 2007. The increase was due primarily to an increase in rental revenues of $13.6 million at our Texarkana, Texas facility, $2.8 million at our New Iberia, Louisiana facility, $20.2 million from our newest location in Williston, North Dakota and $1.3 million from our Victoria, Texas location, partially offset by declines of $0.9 million from our Evanston, Wyoming facility, $1.7 million at our Odessa, Texas location and $1.8 million at our international operations. Revenues increased as a result of our expansion efforts in Texarkana, Texas and Williston, North Dakota.

 

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

 

Other Financial Data

 

Gain on asset dispositions was $2.7 million, a decrease of $13.7 million as a result of minor asset sales in 2008 as compared to gains of $16.4 million during the same period in 2007 as we sold two workover barge rigs in January 2007 for a recognized gain of $15.1 million. Interest expense for 2008 was relatively unchanged as compared to the same period of 2007. Interest income for 2008 decreased $5.1 million due to lower cash balances available for investments as compared to 2007. General and administration expense increased $10.0 million as compared to the year ended 2007, due primarily to higher legal and professional fees associated with the ongoing DOJ and SEC investigations into the customs agent discussed in Note 13 in

RESULTS OF OPERATIONS (continued)

 

Other Financial Data (continued)

 

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

 

In 2004, we entered into two variable-to-fixed interest rate swap agreements. The swap agreements did not qualify for hedge accounting and accordingly, we reported the mark-to-market change in the fair value of the interest rate derivatives in earnings. During 2008, we had no swaps outstanding and therefore reported no charge or benefit related to swaps, as compared to the year ended December 31, 2007 where we recognized a $0.7 million decrease in the fair value of the derivative positions. For additional information see Note 6.

 

Income tax expense was $8.8 million for the year ended December 31, 2008, as compared to income tax expense of $37.7 million for the year ended December 31, 2007. Income tax expense for 2008 includes a benefit of $13.4 million of FIN 48 interest and foreign currency exchange rate fluctuations related to our settlement of interest related to our Kazakhstan tax case (see Note 13 — Kazakhstan Tax Case), the establishment of a valuation allowance of $4.1 million related to a Papua New Guinea deferred tax asset, the reversal of a $5.7 million valuation allowance relating to 2007 foreign tax credits, a charge of $4.5 million accounted for under FIN 48 related to certain intercompany transactions between our U.S. companies and foreign affiliates, a charge of $12.6 million related to non-deductible goodwill and a benefit of $12.2 million for the recovering of prior years foreign taxes as a credit in the U.S. versus a deduction. Based on the level of projected future taxable income over the periods for which the deferred tax asset is deductible in Papua New Guinea, management believes that it is more likely than not that our subsidiary will not realize the benefit of this deduction in Papua New Guinea.

 

Year Ended December 31, 2007 Compared with Year Ended December 31, 2006

 

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

RESULTS OF OPERATIONS (continued)

 

Other Financial Data (continued)

 

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

 

 

 

RESULTS OF OPERATIONS (continued)

 

Other Financial Data (continued)

 

 

 

 

U.S. Drilling Segment

 

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

 

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

 

International Drilling Segment

 

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

 

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

 

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

 

RESULTS OF OPERATIONS (continued)

 

International Drilling Segment (continued)

 

 

 

These decreases were partially offset by:

 

 

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

 

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

 

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

 

Project Management and Engineering Services Segment

 

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

RESULTS OF OPERATIONS (continued)

 

Rental Tools Segment

 

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

 

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

 

Other Financial Data

 

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

 

In 2004, we entered into two variable-to-fixed interest rate swap agreements. The swap agreements did not qualify for hedge accounting and accordingly, we reported the mark-to-market change in the fair value of the interest rate derivatives in earnings. For the year ended December 31, 2007, we recognized a $0.7 million decrease in the fair value of the derivative positions and for the year ended December 31, 2006, we recognized a minimal change in the fair value of the derivative positions. On July 17, 2007, we terminated one swap scheduled to expire in September 2008 and received $0.7 million. The second swap was not renewed and expired on September 4, 2007.

 

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

 

LIQUIDITY AND CAPITAL RESOURCES

 

Liquidity

 

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

 

LIQUIDITY AND CAPITAL RESOURCES (continued)

 

Liquidity (continued)

 

Operating Activities

 

Cash flows from operating activities were $220.3 million for 2008 compared to $74.3 million for 2007. The increase in cash provided from operating activities is due to decreased working capital requirements and the net effect of a decrease to net income, an increase in depreciation, and an impairment of goodwill. Lower working capital requirements of $118.8 million were principally driven by a smaller increase in accounts receivable, lower accrued taxes and higher accrued liabilities compared to changes in 2007. Depreciation in 2008 increased to $117.0 million compared to $85.8 million in 2007 due to additional rigs being placed into service and major upgrades to existing rigs. All of our remaining goodwill, $100.3 million, was impaired in 2008 compared to no impairment in 2007.

 

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

 

Investing Activities

 

Cash flows used in investing activities were $196.6 million for 2008. Our primary use of cash was $197.1 million for capital expenditures and a $5.0 million investment in our Saudi joint venture, which was sold in April 2008. Major capital expenditures for the period included $58.3 million on the construction of two new Alaska rigs, $41.5 million for tubulars and other rental tools for Quail Tools and $31.2 million on construction of new international land rigs. Sources of cash included $5.5 million from assets sales and insurance proceeds.

 

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

 

Our estimated expenditures for 2009 will primarily be directed to our two new Alaska rigs. Additional spending to maintain current operations will comprise the remaining portion of our expenditures and any discretionary spending will be evaluated based upon adequate return requirements and available liquidity. We believe that we have sufficient cash and available liquidity to sustain operations and fund our capital expenditures for 2009, though there can be no assurance that we will continue to generate cash flows at current levels or be able to obtain additional financing if necessary. See “Item 1A. Risk Factors” regarding additional risk related to our business.

 

Financing Activities

 

Cash flows from financing activities were $88.5 million for 2008. Our primary sources of cash include a net drawdown on our 2007 and 2008 credit facilities of $88.0 million and proceeds of $2.0 million from stock options exercised, offset by a payment of $1.8 million for debt issuance costs relating to our 2008 Credit Facility.

 

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

LIQUIDITY AND CAPITAL RESOURCES (continued)

 

Financing Activities (continued)

 

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

 

2008 Credit Facility

 

On May 15, 2008 we entered into a new Credit Agreement (“2008 Credit Facility”) with a five year senior secured $80.0 million revolving credit facility (“Revolving Credit Facility) and a senior secured term loan facility (“Term Loan Facility”) of up to $50.0 million. The obligations of the Company under the 2008 Credit Facility are guaranteed by substantially all of the Company’s domestic subsidiaries, except for domestic subsidiaries owned by foreign subsidiaries and certain immaterial subsidiaries, each of which has executed a guaranty. The 2008 Credit Facility contains customary affirmative and negative covenants regarding ratios for consolidated leverage, consolidated interest coverage and consolidated senior secured leverage. As of December 31, 2008 our Consolidated Leverage Ratio was 1.67 to 1 compared to the maximum permitted 4.00 to 1; our Consolidated Interest Coverage Ratio was 11.24 to 1 compared to the minimum permitted 2.50 to 1 and our Consolidated Senior Secured Leverage Ratio was 0.39 to 1 compared to the maximum permitted 1.50 to 1. At this time the company does not anticipate triggering any of these covenants during 2009.

 

The 2008 Credit Facility is available for general corporate purposes and to fund reimbursement obligations under letters of credit the banks issue on our behalf pursuant to this facility. Revolving loans are available under the 2008 Credit Facility subject to a borrowing base calculation based on a percentage of eligible accounts receivable, certain specified barge drilling rigs and eligible rental equipment of the Company and its subsidiary guarantors. As of December 31, 2008, there were $12.8 million in letters of credit outstanding, $50.0 million outstanding on the Term Loan Facility and $58.0 million outstanding on the Revolving Credit Facility. The Term Loan will begin amortizing on September 30, 2009 at equal installments of $3.0 million per quarter. As of December 31, 2008, the amount drawn represents 94 percent of the capacity of the Revolving Credit Facility (which also reflects a $4.4 million reduction in available borrowing resulting from the bankruptcy filing of Lehman Brothers Holdings, Inc., the parent corporation of Lehman Commercial Paper, Inc., which had a $6.2 million lending commitment). Subsequent to year end, Lehman Commercial Paper, Inc. assigned its obligations under the 2008 Credit Facility to Trustmark National Bank. On the closing date, January 30, 2009, Trustmark National Bank fully funded Lehman Commercial Paper, Inc.’s commitments, including an additional $4.0 million that Lehman Commercial Paper, Inc. did not fund in October 2008, therefore, increasing our borrowings under the Revolving Credit Facility to $62.0 million. The Company expects to use the drawn amounts over the next twelve months to fund construction of two new rigs for work in Alaska. Although the credit crisis may affect certain customers’ ability to pay, the Company anticipates it has sufficient liquidity to meet its expected capital expenditures and manage any delays in collection of receivables.

 

2.125 percent Convertible Senior Notes

 

On July 5, 2007, we issued $125.0 million aggregate principal amount of 2.125 percent Convertible Senior Notes (the Notes) due July 15, 2012. The Notes were issued at par and interest is payable semiannually on July 15th and January 15th.

 

The significant terms of the convertible notes are as follows:

 

LIQUIDITY AND CAPITAL RESOURCES (continued)

 

Financing Activities (continued)

 

 

 

Concurrently with the issuance of the Convertible Senior Notes, the Company purchased a convertible note hedge (the note hedge) and sold warrants in private transactions with counterparties that were different than the ultimate holders of the Notes. The note hedge included purchasing free-standing call options and selling free-standing warrants, both exercisable in the Company’s common shares. The convertible note hedge allows us to receive shares of our common stock from the counterparties to the transaction equal to the amount of common stock related to the excess conversion value that we would issue and/or pay to the holders of the Senior Convertible Notes upon conversion.

 

The terms of the call options mirror the Notes’ major terms whereby the call option strike price is the same as the initial conversion price as are the number of shares callable, $13.85 per share and 9,027,713 shares respectively. This feature prevents dilution of the Company’s outstanding shares. The warrants allow the Company to sell 9,027,713 common shares at a strike price of $18.29 per share. The conversion price of the Notes remains at $13.85 per share, and the existence of the call options and warrants serve to guard against dilution at share prices less than $18.29 per share, since we would be able to satisfy our obligations and deliver shares upon conversion of the Notes with shares that are obtained by exercising the call options.

 

We paid a premium of approximately $31.48 million for the call options, and we received proceeds for a premium of approximately $20.25 million for the sale of the warrants. This reduced the net cost of the note hedge to $11.23 million. The expiration date of the note hedge is the earlier of: 1) the last day on which the convertible notes remain outstanding, and 2) the maturity date of the convertible notes.

 

The convertible notes are a legal form debt and are classified as a liability in our consolidated financial statements. Because we have the choice of settling the call options and the warrants in cash or shares of our common stock, and these contracts meet all of the applicable criteria for equity classification as outlined in EITF No. 00-19, “Accounting for Derivative Financial Instruments Indexed to, and Potentially Settled in, a Company’s Own Stock,” the cost of the call options and proceeds from the sale of the warrants are classified in stockholders’ equity in the Consolidated Balance Sheets. In addition, because both of these contracts are

LIQUIDITY AND CAPITAL RESOURCES (continued)

 

Financing Activities (continued)

 

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

 

Debt issuance costs totaled approximately $3.6 million and are being amortized over the five year term of the Notes using the effective interest method. Proceeds from the transaction of $110.2 million were used to call our outstanding Senior Floating Rate notes, to pay the net cost of hedge and warrant transactions, and for general corporate purposes.

 

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

 

2007 Credit Facility

 

On September 20, 2007, we replaced our existing $40.0 million Credit Agreement with a new $60.0 million Amended and Restated Credit Agreement (“2007 Credit Facility”) which expires in September 2012. The 2007 Credit Facility is secured by rental tools equipment, accounts receivable and the stock of substantially all of our domestic subsidiaries, other than domestic subsidiaries owned by a foreign subsidiary and contains customary affirmative and negative covenants such as minimum ratios for consolidated leverage, consolidated interest coverage and consolidated senior secured leverage.

 

The 2007 Credit Facility was available for general corporate purposes and to fund reimbursement obligations under letters of credit the banks issue on our behalf pursuant to this facility. Revolving loans were available under the 2007 Credit Facility subject to a borrowing base limitation based on 85 percent of eligible receivables plus a value for eligible rental tools equipment. The 2007 Credit Facility called for a borrowing base calculation only when the 2007 Credit Facility had outstanding loans, including letters of credit, totaling at least $40.0 million. As of December 31, 2008, there were $12.8 million in letters of credit outstanding and $20.0 million of outstanding loans.

 

Other Liquidity

 

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

 

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

 

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

 

 

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

LIQUIDITY AND CAPITAL RESOURCES (continued)

 

Financing Activities (continued)

 

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

 

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

 

 

 

 

 

We used derivative instruments to manage risks associated with interest rate fluctuations in connection with our $100.0 million Senior Floating Rate Notes which were fully redeemed on September 27, 2007. These derivative instruments, which consisted of variable-to-fixed interest rate swaps, did not meet the hedge criteria in SFAS No. 133 and were therefore not designated as hedges. Accordingly, the change in the fair value of the interest rate swaps was recognized in earnings.

 

On July 17, 2007, we terminated one swap scheduled to expire on September 2, 2008 and received $0.7 million. On September 4, 2007, our one remaining swap expired.

 

OTHER MATTERS

 

Business Risks

 

Internationally, we specialize in drilling geologically challenging wells in locations that are difficult to access and/or involve harsh environmental conditions. Our international services are primarily utilized by major and national oil companies and integrated service providers in the exploration and development of reserves of oil and gas. In the United States, we primarily drill in the transition zones of the U.S. Gulf of Mexico for major and independent oil and gas companies. Business activity is primarily dependent on the

OTHER MATTERS (continued)

 

Business Risks (continued)

 

exploration and development activities of the companies that make up our customer base. See Item 1A, Risk Factors, for a detailed statement of Risk Factors related to our business.

 

Critical Accounting Policies

 

Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, we evaluate our estimates, including those related to bad debts, materials and supplies obsolescence, property and equipment, goodwill, income taxes, workers’ compensation and health insurance and contingent liabilities for which settlement is deemed to be probable. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. While we believe that such estimates are reasonable, actual results could differ from these estimates.

 

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

 

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

 

Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets and reflect management’s assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates and costs. The use of different estimates and assumptions could result in materially different carrying values of our assets. As a result of certain impairment indicators mentioned in “Impairment of Goodwill” below, we tested our long-lived assets for impairment as of December 31, 2008 and determined there was no asset impairment required.

 

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

 

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

OTHER MATTERS (continued)

 

Critical Accounting Policies (continued)

 

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

 

Insurance Reserves.  Our operations are subject to many hazards inherent to the drilling industry, including blowouts, explosions, fires, loss of well control, loss of hole, damaged or lost drilling equipment and damage or loss from inclement weather or natural disasters. Any of these hazards could result in personal injury or death, damage to or destruction of equipment and facilities, suspension of operations, environmental damage and damage to the property of others. Generally, drilling contracts provide for the division of responsibilities between a drilling company and its customer, and we seek to obtain indemnification from our customers by contract for certain of these risks. To the extent that we are unable to transfer such risks to customers by contract or indemnification agreements, we seek protection through insurance. However, there is no assurance that such insurance or indemnification agreements will adequately protect us against liability from all of the consequences of the hazards described above. Moreover, our insurance coverage generally provides that we assume a portion of the risk in the form of an insurance coverage deductible.

 

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

 

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

 

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

OTHER MATTERS (continued)

 

Critical Accounting Policies (continued)

 

Our ability to realize the benefit of our deferred tax assets requires that we achieve certain future earnings levels prior to the expiration of our NOL (“Net Operating Loss”) carryforwards. In the event that our earnings performance projections do not indicate that we will be able to benefit from our NOL carryforwards, valuation allowances are established. We periodically evaluate our ability to utilize our NOL carryforwards and, in accordance with SFAS No. 109 “Accounting for Income Taxes,” will record any resulting adjustments that may be required to deferred income tax expense.

 

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

 

Our accounting policy for income taxes is also affected by FIN 48, “Accounting for Uncertainty in Income Taxes,” which we adopted January 1, 2007. This interpretation requires management to make estimates and assumptions that affect amounts recorded as liabilities and related disclosures due to the uncertainty as to final resolution of certain tax matters. Because the recognition of liabilities under this Interpretation may require periodic adjustments and may not necessarily imply any change in management’s assessment of the ultimate outcome of these items, the amount recorded may not accurately anticipate actual outcome.

 

Revenue Recognition.  We recognize revenues and expenses on dayrate contracts as drilling progresses. For meterage contracts, which are rare, we recognize the revenues and expenses upon completion of the well. Revenues from rental activities are recognized ratably over the rental term which is generally less than six months. Mobilization fees received and related mobilization costs incurred are deferred and amortized over the term of the contract period. Construction contract revenues and costs are recognized on a percentage of completion basis using the cost-to-cost method.

 

Recent Accounting Pronouncements

 

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

 

Interest Rate Risk

 

In 2004, we entered into two variable-to-fixed interest rate swap agreements. The swap agreements did not qualify for hedge accounting and accordingly, we reported the mark-to-market change in the fair value of the interest rate derivatives in earnings. For the year ended December 31, 2007, we recognized a $0.7 million decrease in the fair value of the derivative positions and for the year ended December 31, 2006 we recognized a minimal change in the fair value of the derivative positions. On July 17, 2007, we terminated one swap scheduled to expire in September 2008 and received $0.7 million. The second swap was not renewed and expired on September 4, 2007.

 

Long-Term Debt

 

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

 

Note:  The information contained in this Item provides updates related to our addition of a new business segment effective January 1, 2008. Our new business segment is discussed further in Note 12: Business Segment. We revised the following Notes to the Consolidated Financial Statements:

 

 

Item 8 has not been updated for other changes since the filing of our 2007 Form 10-K.

 

The Board of Directors and Stockholders
Parker Drilling Company:

 

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

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

 

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

 

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

 

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

We also have audited the adjustments described in Note 1 and Note 12 that were applied to recast the 2006 consolidated financial statements for the segment adjustments. In our opinion, such adjustments are appropriate and have been properly applied. We were not engaged to audit, review or apply any procedures to the 2006 consolidated financial statements of the Company other than with respect to the adjustments and, accordingly, we do not express an opinion or any other form of assurance on the 2006 consolidated financial statements taken as a whole.

 

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

 

 

Houston, Texas

February 26, 2009

 

To the Board of Directors and Stockholders of

Parker Drilling Company:

 

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

 

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

 

PricewaterhouseCoopers LLP

 

Houston, Texas

February 28, 2007

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