Item 1. BUSINESS
GENERAL DEVELOPMENT
Parker Drilling Company was incorporated in the state of Oklahoma in 1954 after having been established in 1934 by its founder, Gifford C. Parker. The founder was the father of Robert L. Parker, chairman and a principal stockholder, and the grandfather of Robert L. Parker Jr., president and chief executive officer. In March 1976, the state of incorporation of the Company was changed to Delaware through the merger of the Oklahoma Corporation into its wholly owned subsidiary Parker Drilling Company, a Delaware corporation. Unless otherwise indicated, the term "Company" refers 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, or on the Securities and Exchange Commission website at www.sec.gov, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish to, the Securities and Exchange Commission.
The Company is a leading worldwide provider of contract drilling and drilling related services. Our primary operating areas include the transition zones of the Gulf of Mexico, Nigeria and the Caspian Sea; the offshore waters of the Gulf of Mexico and on land in international oil and gas producing regions. In addition to operating in the Gulf of Mexico, the Company's rental tool business operates in the U.S. land markets of Texas and the Rocky Mountain region.
The Company's current marketed rig fleet of 79 rigs, consisting of 27 barge drilling and workover rigs, seven offshore jackup rigs, four offshore platform rigs and 41 land rigs, enables the Company to provide a variety of drilling services to oil and gas operators in numerous locations around the world. The Company's barge drilling and workover rig fleet is dedicated to transition zone waters, which are generally defined as coastal waters having depths from five to 25 feet. The Company's offshore jackup rigs currently operate in the Gulf of Mexico market and are capable of drilling in water depths from nine to 215 feet. The Company's land rig fleet generally consists of premium and specialized deep drilling rigs, with 35 of its 41 marketed land rigs capable of drilling to depths of 10,000 feet or greater.
DRILLING OPERATIONS
General
The Company provides contract drilling services in the transition zones, which are coastal waters including lakes, bays, rivers and marshes, of the Gulf of Mexico, the Caspian Sea and Nigeria, where barge rigs are the primary source of drilling and workover services. Barge rigs are utilized because of their ability to carry drilling equipment on board and navigate in shallow waters up to 25 feet where conventional jackup rigs are unable to operate. Barge rigs are towed to a drilling location at which time the hull is submerged to the bottom to provide stability before operations begin.
The Company's land drilling operations specialize in the drilling of difficult wells, often in remote locations and/or harsh environments. Since beginning operations in 1934, the Company has operated in 53 foreign countries and throughout the United States, making it one of the most geographically diverse land drilling contractors in the world. All of the company's land rigs operate in international locations.
The Company's international land drilling operations have focused primarily in the Latin America region, the Asia Pacific region and the Commonwealth of Independent States (the former Soviet Union, referred to hereinafter as the "CIS"). The Company's reputation and operational expertise has led operators to look to the Company as a pioneer for the exploration of oil and gas in new "frontiers" around the world. The Company was the first to enter China in 1980 and has continued to provide drilling services to this market. The Company was also the first western drilling contractor to enter Russia in 1991 followed by Kazakhstan in 1993, now one of the Company's most active markets.
International markets differ from the U.S. market in terms of competition, nature of customers, equipment and experience requirements. The majority of international drilling markets have one or more of the following characteristics: (i) a small number of competitors; (ii) customers who typically are major, large independent or foreign national oil companies; (iii) drilling programs in remote locations with little infrastructure and/or harsh environments requiring drilling equipment with a large inventory of spare parts and other ancillary equipment; and (iv) difficult i.e. high pressure, deep or geologically challenging wells requiring considerable experience to drill.
The Company has been one of the pioneers in arctic drilling services and has considerable experience with the technology required to drill in these ecologically sensitive areas. Although originally developed for the North Slope of Alaska, this technological expertise in arctic drilling is an asset to the Company in marketing its services to operators in international markets with similar environmental considerations, such as the Caspian Sea, Western Siberia and Sakhalin Island.
The Company has been active in managing drilling rigs owned by third parties, generally oil companies that prefer to own the rig equipment but do not have the technical expertise or labor resources to operate the rig. During 2002, the Company operated project management contracts in five countries.
U.S. Barge Drilling and Workover
The Company's U.S. market for its barge drilling rigs is the transition zones of the Gulf of Mexico, primarily in Louisiana and, to a lesser extent, Alabama and Texas. This area historically has been the world's largest market for shallow water barge drilling. The Company, with 22 drilling and workover barges, is one of two companies with a significant presence in this market.
International Barge Drilling
The Company's international barge drilling operations are focused in the transition zones of Nigeria and the Caspian Sea. Although commodity prices also affect demand for international drilling, international markets typically are more attractive than U.S. markets because the increased capital and equipment requirements usually allow contractors to secure long-term contracts and higher dayrates when compared with domestic drilling operations.
The Company is the leading provider of barge rigs in Nigeria, with four of the eight rigs in this market. The Company has operated in Nigeria since 1996. In addition, the Company owns and operates the world's largest Arctic barge rig in the Caspian Sea.
Jackup Drilling
The Company has seven shallow water jackup rigs in the Gulf of Mexico. While overall jackup utilization was slightly higher in 2002 than in 2001, dayrates were significantly lower throughout the year.
Platform Drilling
The Company's fleet of platform rigs consists of four modular self-erecting rigs. These platform rigs consist of drilling equipment and machinery arranged in modular packages that are transported to and self-erected on fixed offshore platforms owned by oil companies.
Latin America
The Company has 17 land rigs located in Colombia, Peru and Bolivia, plus one rig that is stacked in Houston awaiting deployment. One of the Company's major customers reduced its drilling program in Colombia during the second quarter of 2002 and released three of the four Company rigs working for the customer. In addition, the market in Bolivia was depressed throughout the year as the Company had only one rig working during the early part of 2002. The declining market in Bolivia was due in part to reduced demand for Bolivian natural gas in Brazil. The Company had one rig working in Peru the last six months of 2002.
Asia Pacific/Middle East/Africa
The Company has 14 land rigs located in the Asia Pacific, Middle East and Africa drilling markets. Included are seven helicopter transportable rigs located in this region which facilitate exploration in areas of difficult access, like the mountainside and jungle terrain of Indonesia and Papua New Guinea. This market had flat activity throughout the year.
CIS
Ten of the Company's rigs are currently located in the oil and gas producing regions of the CIS. The Company was the first Western drilling contractor to enter this market, in 1991, and it continued to be a major area of operations in 2002. Two of the three rigs the Company leased to Saipar B.V., the Company's joint venture with Saipem, a drilling subsidiary of Eni S.p.A., in Kazakhstan's Karachaganak field, were released from contract in 2002. In the Tengiz field in Kazakhstan, the Company operates through AralParker, a joint venture with a local Kazakhstan company. In November 2002, the Company received a notification from its customer that operations would be suspended after completion of wells currently being drilled pending resolution of funding issues among its partners. The suspension was lifted in early 2003, resulting in minimal financial impact and negligible disruptions to the Company's drilling operations. In Russia, the Company had one rig under contract throughout 2002, and mobilized a new rig to Sakhalin Island. This rig was designed and built by the Company and sold to the customer. Drilling operations under an operations and maintenance contract with this customer are expected to commence in mid-2003.
RENTAL TOOLS
Quail Tools, based in New Iberia, Louisiana, is a provider of premium rental tools used for land and offshore oil and gas drilling and workover activities. Approximately 65 percent of Quail's equipment is utilized in offshore and coastal water operations. Since its inception in 1978, Quail's principal customers have been major and independent oil and gas exploration and production companies. Quail has facilities in New Iberia, Louisiana; Victoria, Texas; Odessa, Texas and Evanston, Wyoming.
COMPETITION
The contract drilling industry is a competitive and cyclical business characterized by high capital requirements and difficulty in finding and retaining qualified field personnel.
In the Gulf of Mexico barge drilling and workover markets, the Company competes with one major contractor. In the jackup and platform markets, there are numerous U.S. offshore contractors. In international land markets, the Company competes with a number of international drilling contractors but also with smaller local contractors in certain markets. However, due to the high capital costs of operating in international land markets as compared to the U.S. land market, the high cost of mobilizing land rigs from one country to another, and the technical expertise required, there are usually fewer competitors in international land markets. In international land and offshore markets, experience in operating in challenging environments and customer alliances have been factors in the selection of the Company in certain cases, as well as the Company's patented drilling equipment for remote drilling projects. The Company believes that the market for drilling contracts, both land and offshore, will continue to be highly competitive for the foreseeable future. Certain competitors have greater financial resources than the Company, which may enable them to better withstand industry downturns, compete more effectively on the basis of price, build new rigs or acquire existing rigs.
Management believes that Quail Tools is one of the leading rental tool companies in the offshore Gulf of Mexico and the Gulf Coast land markets. Some of Quail's competitors are substantially larger and have greater financial resources than Quail Tools.
CUSTOMERS
The Company believes it has developed a reputation for providing efficient, safe, environmentally conscious and innovative drilling services. An increasing trend indicates that a number of the Company's customers have been seeking to establish exploration or development drilling programs based on partnering relationships or alliances with a limited number of preferred drilling contractors. Such relationships or alliances can result in longer-term work and higher efficiencies that increase profitability for drilling contractors at a lower overall well cost for oil and gas operators. The Company is currently a preferred contractor for operators in certain United States and international locations, which management believes is a result of the Company's quality of equipment, personnel, safety records, service and experience.
The Company's drilling and rental tool customer base consists of major, independent and foreign-owned oil and gas companies. For fiscal year 2002 and 2001 respectively, ChevronTexaco was the Company's largest customer with approximately 17 percent of total revenues in 2002 and 15 percent in 2001. In 2002, Tengizchevroil ("TCO"), a joint venture with four oil companies, was the second largest customer with 13 percent of total revenues. Shell Petroleum Development Company of Nigeria was the Company's largest customer for 2000 with approximately 10 percent of total revenues.
CONTRACTS
The Company generally obtains contracts through competitive bidding. Under most contracts the Company is paid a daily fee, or dayrate. The dayrate received is based on several factors, including, type of equipment, services and personnel furnished, investment required to perform the contract, location of the well, term of the contract, and competition.
The Company generally receives a lump sum fee to move its equipment to the drilling site, which in most cases approximates the cost incurred by the Company. U.S. contracts are generally for one to three wells with options to drill additional wells, while international contracts are more likely to be for multi-well long-term programs.
Rental tool contracts are typically on a dayrate basis with rates based on type of equipment, investment and competition.
EMPLOYEES
At December 31, 2002, the Company employed 2,898 people, a decrease of 21 percent from the 3,654 employed at December 31, 2001. The following table sets forth the composition of the Company's employees.
RISKS AND ENVIRONMENTAL CONSIDERATIONS
The operations of the Company are subject to numerous federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency ("EPA"), issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or may result in injunctive relief for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require remedial action to prevent pollution from former operations, and impose substantial liabilities for pollution resulting from the Company's operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly compliance could adversely affect the Company's operations and financial position, as well as those of similarly situated entities operating in the Gulf Coast market. While management believes that the Company is in substantial compliance with current applicable environmental laws and regulations, there is no assurance that compliance can be maintained in the future.
The drilling of oil and gas wells is subject to various federal, state, local and foreign laws, rules and regulations. The Company, as an owner or operator of both onshore and offshore facilities including mobile offshore drilling rigs in or near waters of the United States, 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 Outer Continental Shelf Lands Act ("OCSLA"), the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), and the Resource Conservation and Recovery Act ("RCRA"), each as amended from time to time. In addition, the Company 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 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 $500,000, 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. To the extent damages and removal costs exceed this amount, the mobile offshore drilling rig will be treated as an offshore facility and the offshore lessee will be responsible up to higher liability limits for all removal costs plus $75.0 million. A party 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 (to cover at least some costs in a potential spill) and preparation of an oil spill contingency plan for offshore facilities and vessels in excess of 300 gross tons. Amendments to the OPA adopted in 1996 require 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 ("MMS") believes such a level is justified by the risks posed by the quantity or quality of oil that is handled by the facility. However, such OPA amendments did not reduce the amount of financial responsibility required for "tank vessels." Since the Company's offshore drilling rigs are typically classified as tank vessels, the recent amendments to the OPA are not expected to have a significant effect on the Company's operations. 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 the Company's operating U.S. barge drilling rigs have zero-discharge capabilities as required by law. In addition, in recognition of environmental concerns regarding dredging of inland waters and permitting requirements, the Company conducts negligible dredging operations, with approximately two-thirds of the Company's offshore drilling contracts involving directional drilling, which minimizes the need for dredging. However, the existence of such laws and regulations has had and will continue to have a restrictive effect on the Company and its customers.
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, the Company's 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. The Company believes that it is in compliance with CERCLA and currently is not aware of any events that, if brought to the attention of regulatory authorities, would lead to the imposition of CERCLA liability against the Company.
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, the Company does not expect to experience more burdensome costs than similarly situated companies involved in drilling operations in the Gulf Coast market.
The drilling industry is dependent on the demand for services from the oil and gas exploration and development industry, and accordingly, is affected by changes in laws relating to the energy business. The Company's 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 the Company's operations by limiting available drilling opportunities.
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
The Company operates in three segments, U.S. drilling operations, international drilling operations and rental tools. Information about the Company's business segments and operations by geographic areas for the years ended December 31, 2002, 2001 and 2000 is set forth in Note 11 in the notes to the consolidated financial statements.
Item 2.
Item 2. PROPERTIES
The Company leases office space in Houston for its corporate headquarters. Additionally, the Company owns and leases office space and operating facilities in various locations, but only to the extent necessary for administrative and operational support functions. The Company owns a ten-story building in Tulsa, Oklahoma, the previous corporate headquarters which is vacant and held for sale.
Land Rigs - The following table shows, as of December 31, 2002, the locations and drilling depth ratings of the Company's 41 actively marketed land rigs:
In addition, the Company has seven land rigs classified as cold stacked which would need to be refurbished at a significant cost before being placed back into service, with locations and drilling depth ratings as follows:
Barge Rigs - A schedule of the Company's deep, intermediate, and workover and shallow drilling barge rigs located in the Gulf of Mexico, as of December 31, 2002, is set forth below:
(1) "Active" denotes that the rig is currently under contract or available for contract.
(2) Workover rig.
A schedule of the Company's international drilling barges, as of December 31, 2002, is set forth below:
(1) "Active" denotes that the rig is currently under contract or available for contract.
Platform Rigs - The following table sets forth certain information, as of December 31, 2002, with respect to the Company's platform rigs:
(1) "Active" denotes that the rig is currently under contract or available for contract.
(2) Workover rig.
Jackup Rigs - The following table sets forth certain information as of December 31, 2002, with respect to the Company's jackup rigs:
(1) IC--independent leg, cantilevered; IS--independent leg, slot; MC--mat-supported, cantilevered.
(2) "Active" denotes that the rig is currently under contract or available for contract.
(3) Workover rig.
The following table presents the Company's utilization rates, rigs available for service and cold stacked rigs.
(1) The number of rigs is determined by calculating the number of days each rig was in the fleet, e.g., a rig under contract or available for contract for an entire year is 1.0 "rigs available for service" and a rig cold stacked for one quarter is 0.25 "cold stacked rigs." "Rigs available for service" includes rigs currently under contract or available for contract. "Cold stacked rigs" includes all rigs that are stacked and would require significant refurbishment cost before being placed back into service.
(2) Rig utilization rates are based on a weighted average basis assuming 365 days availability for all rigs available for service. Rigs acquired or disposed of have been treated as added to or removed from the rig fleet as of the date of acquisition or disposal. Rigs that are in operation or fully or partially staffed and on a revenue-producing standby status are considered to be utilized. Rigs under contract that generate revenues during moves between locations or during mobilization/demobilization are also considered to be utilized.
Item 3.
Item 3. LEGAL PROCEEDINGS
On July 6, 2001, the Ministry of State Revenues of Kazakhstan ("MSR") issued an Act of Audit to the Kazakhstan branch ("PKD Kazakhstan") of Parker Drilling Company International Limited ("PDCIL"), a wholly owned subsidiary of the Company, assessing additional taxes of approximately $29.0 million for the years 1998-2000. The assessment consisted primarily of adjustments in corporate income tax based on a determination by the Kazakhstan tax authorities that payments by Offshore Kazakhstan International Operating Company, ("OKIOC"), to PDCIL of $99.0 million, in reimbursement of costs for modifications to Rig 257, performed by PDCIL prior to the importation of the drilling rig into Kazakhstan, are income to PKD Kazakhstan, and therefore, taxable to PKD Kazakhstan. PKD Kazakhstan filed an Act of Non-Agreement that such reimbursements should not be taxable and requested that the Act of Audit be revised accordingly. In November 2001, the MSR rejected PKD Kazakhstan's Act of Non-Agreement, prompting PKD Kazakhstan to seek judicial review of the assessment. On December 28, 2001, the Astana City Court issued a judgment in favor of PKD Kazakhstan, finding that the reimbursements to PDCIL were not income to PKD Kazakhstan and not otherwise subject to tax based on the U.S.-Kazakhstan Tax Treaty. The MSR appealed the decision of the Astana City Court to the Civil Panel of the Supreme Court, which confirmed the decision of the Astana City Court that the reimbursements were not income to PKD Kazakhstan in March 2002. Although the court agreed with the MSR's position on certain minor issues, no additional taxes will be payable as a result of this assessment. The MSR has until the end of March 2003 to appeal the decision of the Civil Panel to the Supervisory Panel of the Supreme Court of Kazakhstan. It may also reopen the case thereafter if material new evidence is discovered. In addition, the Company has filed a petition with the U.S. Treasury Department for competent authority review, which is a tax treaty procedure to resolve disputes as to which country may tax income covered under the treaty. The U.S. Treasury Department has granted our petition and has initiated proceedings with the MSR which is ongoing.
The Company is a party to certain legal proceedings that have resulted from the ordinary conduct of its business. In the opinion of the Company's management, none of these proceedings is expected to have a material adverse effect on the Company.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to Parker Drilling Company security holders during the fourth quarter of 2002.
Item 4A. EXECUTIVE OFFICERS
Officers are elected each year by the board of directors following the annual meeting for a term of one year and until the election and qualification of their successors. The current executive officers of the Company and their ages, positions with the Company and business experience are presented below:
(1) Robert L. Parker, 79, chairman, joined the Company in 1948 and was elected vice president in 1950. He was elected president in 1954 and chief executive officer and chairman in 1969. Since 1991, he has held only the position of chairman.
(2) Robert L. Parker Jr., 54, president and chief executive officer, joined the Company 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 elected chief executive officer.
(3) Robert F. Nash, 59, senior vice president and chief operating officer, joined the Company in November 2001. Mr. Nash joined the Company following a 26-year career with Halliburton, during which time he held numerous senior management positions with responsibility for operations, technical development, manufacturing, procurement, inventory management and sales and marketing. He also has considerable experience with mergers, acquisitions, divestitures and reorganizations.
(4) James W. Whalen, 61, senior vice president and chief financial officer, joined the Company in October 2002. Mr. Whalen served as chief commercial officer for Coral Energy from February 1998 through January 2000. From August 1992 until February 1998, he served as chief financial officer for Tejas Gas Corporation. From August 1981 until August 1992, he held several executive positions at Coastal Corporation including senior vice president, finance.
(5) Thomas L. Wingerter, 50, vice president of operations, joined the Company in 1979. In 1983 he was named contract manager for the Rocky Mountain division. He was promoted to Rocky Mountain division manager in 1984, a position he held until September 1991 when he was elected vice president, North American region. In March 1999 he was appointed vice president and general manager - North American operations. In January 2001, he was appointed to his current position.
(6) W. Kirk Brassfield, 47, vice president and corporate controller, joined the Company in March 1998 as corporate controller and chief 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.
OTHER PARKER DRILLING COMPANY OFFICERS
(7) John R. Gass, 51, vice president of sales and contracts, joined the Company in 1977 and has served in various management positions in the Company's international divisions. In 1985, he became the division manager of Africa and the Middle East. In 1987, he directed the Company's core drilling operations in South Africa. In 1989, he was promoted to international contract manager. In January 1996, he was elected vice president, frontier areas and assumed his current position in March 1999.
(8) Denis Graham, 53, vice president of engineering, joined the Company in 2000. Mr. Graham was the senior vice president of technical services for Diamond Offshore Inc., an international offshore drilling contractor. His experience with Diamond Offshore ranged from 1978 through 1999 in the areas of offshore drilling rig design, new construction, conversions, marine operations, maintenance and regulatory compliance.
(9) David W. Tucker, 47, treasurer and director of investor relations, joined the Company 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 elected treasurer in 1999 and assumed the responsibilities of director of investor relations in 2002.
PART II
Item 5.
Item 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
Parker Drilling Company common stock is listed for trading on the New York Stock Exchange under the symbol "PKD". At the close of business on December 31, 2002, there were 2,790 holders of record of Parker Drilling common stock. Prices on Parker Drilling's common stock for the years ended December 31, 2002 and 2001, were as follows:
No dividends have been paid on common stock since February 1987. Restrictions contained in Parker Drilling's existing bank revolving loan facility prohibit the payment of dividends and the indenture for the Senior Notes restricts the payment of dividends. The Company has no present intention to pay dividends on its common stock in the foreseeable future because of the restrictions noted.
Item 6.
Item 6. SELECTED FINANCIAL DATA (Dollars in Thousands Except Per Share Data)
(1) Loss before extraordinary gain was $(22,981) or $(0.28) per share.
(2) Loss before the cumulative effect of change in accounting principle related to the impairment of goodwill was $(40,910) or $(0.44) per share.
Item 7.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS Outlook and Overview
The year 2002 was marked by an overall decline in rig activity and cash flow for the Company. The Company incurred a net loss of $40.9 million before the cumulative effect of the change in accounting principle, compared to net income of $11.1 million in 2001. Rig utilization, dayrates and rental activity decreased substantially in the Company's Gulf of Mexico drilling markets, continuing a trend that started in the fourth quarter of 2001. The Company's international markets began to improve late in 2001, experiencing significantly higher utilization in the fourth quarter, most notably in the Asia Pacific region and Kazakhstan; however, these gains were partially offset in 2002 by reduced drilling activity in Latin America, primarily Colombia and Bolivia, and downtime due to barge rig inspections and refurbishments in Nigeria.
After reaching, during 2001, the highest levels of dayrates and utilization since the fall of 1998, the Gulf of Mexico drilling market began to soften during the fourth quarter of 2001. The reduction in drilling activity by operators was in response to declining demand and prices for natural gas, due in part to the economic recession in the United States. This reduced level of activity continued through 2002 even as the price for crude oil and natural gas increased, due to the lack of acceptable well prospects and funding issues. Due to the reduction in drilling activity in 2002, barge rig utilization decreased from 76 percent in 2001 to 49 percent in 2002. Utilization for the jackup rigs increased during the second half of 2002 to 80 percent, slightly higher than the 78 percent in 2001. Negating the increase in utilization was a 44 percent decline in average dayrates for 2002 as compared to 2001. The Company's rental tool business experienced a similar reduction in activity beginning in late 2001 that continued throughout 2002. Rental tool revenues declined in 2002 by $18.1 million and profit margins decreased from 65 percent in 2001 to 54 percent in 2002.
Our drilling operations in the CIS, which includes Kazakhstan and Russia, are a significant part of our current international operations and the Company believes the region has potential for additional growth in the future. Since 1993, our operations in Kazakhstan have grown from providing labor to our principal customer to owning or managing 11 drilling rigs for several operators. In the last few years, the government of Kazakhstan has requested that vendors incorporate local content into their operations to stimulate the development of a local oil and gas service industry and the Kazakhstan economy. In order to take advantage of the growth potential and remain a preferred vendor in Kazakhstan, it was advantageous for us to partner with a local company. In June 2002, PDCIL entered into an agreement to sell two of its rigs in Kazakhstan, and assign the contract associated with said rigs, to AralParker, a Kazakhstan joint venture company owned 50 percent by PDCIL and 50 percent by a Kazakhstan company, Aralnedra CJSC. The sales price for the rigs was $42.7 million, which represented the fair market value according to an appraisal by an independent third party appraiser. The purchase of the rigs by AralParker was financed by Parker Drilling over a five-year period and is collateralized by a lien on the rigs and a security interest in the five-year drilling contract and its proceeds. The transaction closed on August 15, 2002. In addition, PDCIL will lease a third rig to AralParker, and will operate the joint venture company pursuant to a management and technical services contract. In light of the Company's significant influence over the business affairs of AralParker, its financial statements are consolidated with the Company's financial statements in accordance with generally accepted accounting principles. Although Aralnedra effectively owns 50 percent of the two rigs, PDCIL will receive approximately 90 percent of the cash flow generated by the current five-year drilling contract, effective February 2002, through the proceeds of repayment of the loan and the management and technical services contract.
OUTLOOK AND OVERVIEW (continued)
In November, 2002, the Company and AralParker received notification from TCO to suspend drilling operations upon completion of wells being drilled in Kazakhstan's Tengiz field pending agreement on funding issues facing the TCO partners. On January 27, 2003, the Company and AralParker received notification to resume normal drilling operations in the Tengiz field, except for a labor contract on a TCO-owned rig. While we received notification of the suspension in mid-November, the rigs and crews were instructed to continue drilling wells in progress as of the date of the suspension notice. As a result, operations continued at near normal operating rates throughout most of the suspension period, resulting in a minimal financial impact to the Company and AralParker.
During 2002, cash flow from operations declined $82.8 million to $33.2 million due primarily to the reduced drilling and rental tool activity. In response to the decrease in cash flow from operations, the Company significantly reduced capital expenditures for 2002 to $45.2 million as compared to $122.0 million in 2001. As a result, the Company's cash position remained substantially the same from 2001 to 2002. Management anticipates that working capital needs and funds required for capital spending in 2003 will be met with cash provided by operations. Based on anticipated cash requirements for capital spending of approximately $50.0 million in 2003, it is management's current intention to hold capital expenditures at this reduced level and to apply available free cash flow to repay long-term debt. The amount of debt that can be repaid is dependent on the results of operations and the proceeds from the sale of assets in 2003. Should new opportunities requiring additional capital arise, that are not contemplated in management's current capital expenditure budget, the Company will utilize existing cash and short-term investments and, if necessary, borrowings under its revolving credit facility. In addition, the Company may seek project financing or equity participation from outside alliance partners or customers. The Company cannot predict whether such financing or equity participation would be available on terms acceptable to the Company.
During the Company's fourth quarter conference call with investors, management confirmed its previously announced guidance for 2003 of a net loss range of $0.14 to $0.18 per share. This estimate is based on management's belief that both dayrates and utilization will increase modestly during the last three quarters of the year on the basis that current prices and expected demand for oil and gas will stimulate an increase in drilling activity. Also, during the conference call the Company announced a plan to sell assets by mid-year. Though the exact assets targeted for sale were not identified, management believes that these assets targeted for sale will generate $200 million in net proceeds after transaction fees and taxes, which will be used to reduce long-term debt. The Company has retained an investment banker to assist with the sale of assets, but has not entered into any sales agreements at this time. The guidance for 2003 does not reflect the impact of any asset sales.
RESULTS OF OPERATIONS (continued)
Year Ended December 31, 2002 Compared to Year Ended December 31, 2001 - ---------------------------------------------------------------------
The Company recorded a net loss of $40.9 million, for the year ended December 31, 2002 before the cumulative effect of a change in accounting principle, compared to net income of $11.1 million for the year ended December 31, 2001. The change in accounting principle related to the Company's adoption of Statement of Financial Accounting Standards ("SFAS") No. 142 "Goodwill and Other Intangible Assets" resulted in recording the impairment of goodwill, effective the first quarter of 2002 in the amount of $73.1 million.
The Company's revenues decreased $98.0 million from $488.0 million in 2001 to $389.9 million for the year ended December 31, 2002. This reduction in revenues was attributed to reduced drilling activity world-wide, most notably in the Gulf of Mexico, due to the economic downturn in the United States and increased inventories of oil and natural gas.
U.S drilling revenues decreased $77.3 million in 2002 to $113.5 million due primarily to decreased dayrates for all U.S. offshore drilling rigs and reduced utilization for the barge drilling rigs. The Gulf of Mexico market declined significantly during the fourth quarter of 2001 and continued throughout 2002 due primarily to a reduction in drilling activity by operators. This reduction in drilling activity was in response to declining demand and prices for natural gas and the economic recession in the United States that began during mid-2001. Although prices for natural gas have risen, uncertainty regarding the economy and international issues has caused operators to be hesitant to significantly increase drilling at this time. Revenues for the barge rigs and jackup rigs decreased $40.1 million and $27.8 million, respectively, during the current year as compared to 2001. Utilization for the barge rigs decreased from 76 percent in 2001 to 49 percent in 2002 with a 10 percent decrease in dayrates. The seven jackup rigs experienced a 44 percent decrease in average dayrates during 2002 as compared to 2001; utilization for the jackups remained relatively constant in year-to-year comparisons. Revenues for the platform rigs decreased $9.4 million to $1.6 million, as all four platform rigs were stacked the last three quarters of 2002.
International drilling revenues decreased $2.6 million to $229.0 million in the current year as compared to December 31, 2001. International land drilling revenues increased $4.1 million to $155.6 million during 2002 as compared to 2001. The CIS and Asia Pacific region both increased revenues during 2002.
RESULTS OF OPERATIONS (continued)
Revenues in the CIS region increased $10.3 million in 2002. Revenues increased $7.4 million in the Company's Tengiz operations in 2002 as compared to 2001 primarily due to increased utilization. Revenues from the Company's interest in Saipar, B.V., the Company's joint venture with Saipem, a drilling subsidiary of Eni S.p.A., operating in the Karachaganak field of Kazakhstan, increased $6.2 million due to increased rig lease rates in 2002 and from early termination fees for rigs released by the operator in July and December. The early termination fees totaled $3.7 million. Currently the Company has one rig working in the Karachaganak field. Revenues increased in the Asia Pacific region by $7.4 million related primarily to increased utilization and dayrates in Papua New Guinea. Additionally, the Company increased the number of labor contracts in Kuwait from two rigs in 2001 to six rigs in 2002.
Latin America revenues decreased by $13.6 million in 2002 as compared to 2001. The decreases are primarily related to low utilization in Colombia and Bolivia. During the fourth quarter of 2001, Colombia and Bolivia had six rigs and one rig working, respectively. At December 31, 2002, Colombia had three rigs working and Bolivia had no rig activity. In Colombia, we had four drilling rigs working for a customer when the operator terminated all drilling activity in May of 2002. Since then one rig has gone back to work for this particular customer. We are currently marketing the rigs in Colombia and elsewhere in the world to replace the terminated contracts. The drilling market in Bolivia, which diminished significantly in mid-2001, showed no signs of recovery throughout 2002, primarily due to reduced demand for natural gas from Brazil. Contributing to the reduced demand in 2002 are delays in receiving the Bolivian government's commitment to a new gas pipeline to the west coast of South America to enable the exporting of natural gas to Mexico and the United States. Revenues in Bolivia decreased $9.7 million to $1.0 million in 2002.
International offshore drilling revenues decreased $6.7 million to $73.4 million when compared to 2001, primarily attributable to Nigeria. During the second and third quarters, two of the Company's four barge rigs operating in Nigeria incurred downtime for required American Bureau of Shipping ("ABS") inspections and repairs that resulted in a combined total of five months with no revenues. Shortly after returning to work the drilling contracts for these two barge rigs concluded and only one contract has subsequently been renewed. At December 31, 2002, three of the four barge rigs were drilling.
RESULTS OF OPERATIONS (continued)
Rental tool revenues decreased $18.1 million due to the decline in drilling activity in the Gulf of Mexico and decreased land drilling in West Texas, which reduced the demand for rental tools. Revenues decreased $9.1 million in the New Iberia operations, $6.6 million in the Victoria, Texas, operations and $3.2 million from the Odessa, Texas, operations. Quail Tools opened a new operation in Evanston, Wyoming, in July, 2002 which contributed $0.8 million in revenues in 2002.
(Drilling and rental profit margin - drilling and rental revenues less direct drilling and rental operating expenses; drilling and rental profit margin percentages - drilling and rental profit margin as a percent of drilling and rental revenues.)
Profit margin of $137.7 million in the current period reflects a decrease of $60.3 million from the $198.0 million recognized during the year ended December 31, 2001. The U.S. and international drilling segments recorded profit margin percentages of 24 percent and 37 percent, respectively, in 2002 as compared to 41 percent and 33 percent in 2001. U.S. profit margins decreased $50.7 million to $27.7 million for the year ended December 31, 2002 due to declining revenues as discussed above. In response to declining revenues, U.S. operations instituted cost controls for labor, materials and supplies. As a result, the profit margin percentage increased during the fourth quarter to 34 percent from 28 percent during the third quarter on comparable revenues.
RESULTS OF OPERATIONS (continued)
International drilling profit margin increased $7.3 million to $84.3 million during the current year ended December 31, 2002 as compared to 2001. International land drilling profit margin increased $11.2 million to $58.8 million. Profit margin in the CIS region increased $11.3 million with Kazakhstan and Russia operations each increasing profit margin by approximately $5.7 million. The Kazakhstan increase is primarily attributable to increased utilization in the Tengiz field and the early termination fees received for the two rigs released that were previously operating in the Karachaganak field. The profit margin increase in Russia is due to higher than anticipated mobilization and start up costs incurred in 2001 that resulted in a significant loss. Asia Pacific region's profit margin increased $2.6 million to $17.5 million during the current year. Improvement in Asia Pacific is primarily related to increased revenues in Papua New Guinea that resulted in increased profit margin of $2.3 million. Latin America's profit margin declined $2.7 million primarily due to decreased drilling activity in Colombia and Bolivia. As noted previously, revenues in Colombia and Bolivia decreased $14.0 million and $9.7 million, respectively, for the year ended December 31, 2002 as compared to 2001. The decreased profit margins in Colombia and Bolivia were partially offset by increased profit margins in Ecuador and Peru. The contract in Ecuador was completed in the third quarter of 2002 and the rig is currently stacked in Houston. The contract in Peru will continue through 2003.
International offshore drilling profit margins decreased $4.0 million to $25.5 million during the current year. This decrease in profit margin is primarily attributed to Nigeria where two of the four barge rigs incurred a combined total of five months downtime during the second and third quarters due to ABS inspections and repairs. In addition, these two rigs both completed their respective contracts toward the end of the third quarter and only one contract was renewed in the fourth quarter. Currently the Company is operating three of four barge rigs in Nigeria.
Rental tool profit margin decreased $16.9 million to $25.7 million during 2002 as compared to the year ended December 31, 2001. Profit margin decreased primarily due to the $18.1 million decline in revenues during the current year. The profit margin percentage decreased during the current year to 54 percent from 65 percent for 2001 due to the significant fixed costs related to the rental tool operation.
During the first quarter of 2002, the Company announced a new contract to build and operate a rig to drill extended reach wells to offshore targets from a land-based location on Sakhalin Island, Russia for an international consortium. The revenue and expense for the project are recognized as construction contract revenue and expense. The estimated profit from the engineering, construction, mobilization and rig-up fees is calculated on a percentage of completion basis, of which $2.5 million was recognized during the year ended December 31, 2002.
General and administrative expense increased $3.0 million to $24.7 million for the year ended December 31, 2002. The increase is primarily due to severance costs related to reductions in corporate personnel, significant increase in the vacation accrual, professional fees and required maintenance on the former corporate headquarters in Tulsa currently held for sale. With regards to the vacation accrual the Company adopted a paid time off policy in 2002, significantly increasing the required vacation accrual.
The $1.5 million provision for reduction in carrying value of certain assets is to increase the allowance for doubtful accounts for a U.S. customer who filed for bankruptcy protection during the second quarter of 2002. The $7.5 million of reorganization costs recorded in 2001 includes employee moving expenses and severance costs related to the consolidation and relocation of the Company's corporate and international drilling management to Houston, Texas, from Tulsa, Oklahoma. The reorganization of certain senior management positions and management of drilling operations accompanied the relocation.
RESULTS OF OPERATIONS (continued)
Interest expense decreased $0.6 million in 2002 compared to 2001. Savings of $2.9 million associated with the three $50.0 million interest rate swap agreements including $0.3 million from the amortization of gain on the termination of the interest rate swap agreements were offset by $1.5 million less interest capitalized and $0.6 million higher interest due to the higher interest rate on the exchange notes. Other expense of $4.2 million for the year ended December 31, 2002 includes $3.6 million related to the exchange offer (see Note 6 of the notes to the consolidated financial statements) and $0.4 million of costs incurred for the attempted purchase of Australia Oil and Gas.
Income tax expense for the year ended December 31, 2002 consists of foreign tax expense of $21.3 million and a deferred tax benefit of $17.0 million. Foreign taxes increased $7.4 million due primarily to $3.1 million paid during the first quarter in Colombia related to a change in allowable depreciation in the 2001 tax return and increased taxes in the Kazakhstan and the Asia Pacific regions. The deferred tax benefit was recognized due to the loss generated during the current year.
Year Ended December 31, 2001 Compared to Year Ended December 31, 2000 - ---------------------------------------------------------------------
The Company recorded net income of $11.1 million, for the year ended December 31, 2001, compared to a net loss of $23.0 million, before extraordinary gain, recorded for the year ended December 31, 2000.
The Company's revenues increased $111.6 million to $488.0 million in 2001 as compared to 2000. U.S. offshore drilling revenues increased $44.1 million to $190.8 million due primarily to increased dayrates for the drilling barge rigs and the jackup rigs. Dayrates increased 32 percent and 40 percent for the barge rigs and jackup rigs, respectively, as compared to the previous year. The increase in dayrates was partially offset by decreased utilization from 86 percent in 2000 to 78 percent in 2001 for the jackup rigs. The decrease in utilization was due primarily to the slowdown in the Gulf of Mexico jackup market during the fourth quarter of 2001. Jackup utilization during the fourth quarter was 52 percent as compared to approximately 87 percent during the first three quarters of 2001. U.S. land drilling revenues decreased $1.7 million due to the sale of the Company's last remaining U.S. land rig, Rig 245, in November 2000.
RESULTS OF OPERATIONS (continued)
International drilling revenues increased $46.4 million to $231.5 million in 2001 as compared to the year ended December 31, 2000. International land drilling revenues increased $38.5 million to $151.5 million during 2001. Revenues in the CIS region, which includes Kazakhstan and Russia, increased $32.3 million to $63.1 million during 2001 as compared to the previous year. Kazakhstan increased $30.0 million in 2001 as one rig was added to the Tengiz operation and three rigs were added to the Karachaganak joint venture with Saipem. Russia increased by $2.3 million as one rig commenced operations during 2001. Revenues increased $10.7 million in the Asia Pacific region due primarily to increased rig utilization in Indonesia, Papua New Guinea and New Zealand. Offsetting these increases were decreases in revenues from Madagascar and Nigeria's land rig due to completion of drilling contracts in these countries in 2000. Revenues in the Latin America region decreased $4.4 million to $54.1 million during 2001. Revenues in Bolivia decreased $12.1 million during 2001 due primarily to an oversupply of natural gas in Bolivia due to reduced demand for Bolivian natural gas from Brazil, resulting in a significant decrease in rig utilization. Partially offsetting the decrease in Bolivia was an increase in revenues of $8.7 million in Colombia. During 2001 rig utilization increased in Colombia to 92 percent from 83 percent in 2000.
International offshore drilling revenues increased $7.9 million to $80.0 million during 2001 as compared to 2000. Revenues in the Caspian Sea (barge Rig 257) decreased by $1.6 million while revenues in Nigeria increased $9.5 million. Barge Rig 257 revenues decreased primarily due to reduced rates received during the lengthy rig move after completion of the first well. Revenues for the four barge rigs in Nigeria improved due to increased drilling operations on full dayrates. In 2000 the rigs were on reduced standby rates for approximately six months due to several episodes of community unrest.
Rental tool revenues increased $22.8 million in 2001 as compared to 2000 due to the increased level of drilling activity in the Gulf of Mexico. Contributing to this increase was the New Iberia, Louisiana, operation in the amount of $10.3 million, $6.3 million from the Victoria, Texas, operation and $6.2 million from the Odessa, Texas, operation which commenced operations in May 2000.
(Drilling and rental profit margin - drilling and rental revenues less direct drilling and rental operating expenses; drilling and rental profit margin percentages - drilling and rental profit margin as a percent of drilling and rental revenues.)
RESULTS OF OPERATIONS (continued)
Profit margin of $198.0 million in 2001 reflected an increase of $69.7 million from the $128.3 million recognized during the year ended December 31, 2000. The U.S. and international drilling segments recorded profit margin percentages during 2001 of 41 percent and 33 percent, respectively, as compared to 33 percent and 28 percent in 2000. U.S. profit margins increased $29.1 million. U.S. drilling profit margin was positively impacted during 2001 by increasing dayrates in the Gulf of Mexico from the barge and jackup rigs. Average dayrates for the barge rigs and jackup rigs increased approximately 31 percent and 42 percent, respectively, in 2001 as compared to the prior year. Jackup rig utilization decreased from 86 percent in 2000 to 78 percent in 2001 due primarily to a slowdown in the Gulf of Mexico jackup market during the fourth quarter, which resulted in jackup rig utilization of 52 percent. This slowdown negatively impacted jackup rig dayrates, which declined approximately 23 percent from the first three quarters of 2001.
International drilling profit margin increased $24.8 million to $77.0 million during the year ended December 31, 2001 as compared to 2000. International land drilling profit margin increased $18.1 million to $47.6 million. Profit margin for the international land drilling operations increased in Kazakhstan from 33 percent to 45 percent, Papua New Guinea from 27 percent to 48 percent, and New Zealand from 20 percent to 39 percent, primarily due to higher utilization during 2001. Profit margin in Russia decreased $5.4 million due to higher than anticipated mobilization and start up costs. The international offshore drilling profit margin increased $6.7 million to $29.5 million, with profit margin increasing from 32 percent to 37 percent during 2001 as compared to 2000.
Rental tool profit margin increased $15.8 million to $42.6 million during 2001 as compared to the year ended December 31, 2000. Profit margin increased primarily due to the $22.8 million increase in revenues during 2001. The profit margin percentage increased during 2001 to 65 percent from 63 percent for the previous year due principally to higher revenues without a corresponding increase in fixed cost.
Depreciation and amortization expense increased $12.2 million to $97.3 million in 2001. Depreciation expense recorded in connection with capital additions for the years 1999, 2000 and 2001, was the primary reason for the increase. General and administrative expenses increased $1.3 million in 2001 as compared to 2000. This increase was primarily attributed to increased travel costs, professional fees, information technology projects and higher occupancy costs associated with the new corporate office in Houston.
The Company recognized $7.5 million in reorganization costs, which includes employee-moving expenses and severance costs, during 2001. In September 2001, the Company opened its new corporate office in Houston. The reorganization included the consolidation of its corporate and international drilling activities from Tulsa, Oklahoma, with its U.S. offshore drilling operations already domiciled in Houston. The reorganization of certain senior management positions and the management of drilling operations accompanied the relocation.
Interest expense decreased $4.0 million due to the $50.5 million repayment of convertible notes during the fourth quarter of 2000 and $1.6 million of interest being capitalized to construction projects during the year ended December 31, 2001, as compared to $0.5 million capitalized during 2000. Gain on disposition of assets decreased $15.6 million to $2.3 million for the year ended December 31, 2001. During the year 2000, the Company sold its one million shares of Unit Corporation common stock and recognized a pre-tax gain of $7.4 million and the Company sold Rig 245 in Alaska for $20.0 million and recognized a pre-tax gain of $14.9 million.
RESULTS OF OPERATIONS (continued)
Income tax expense for 2001 consists of foreign tax expense of $14.0 million and deferred tax benefit of $1.4 million. The deferred tax benefit is due to the reduction in the valuation allowance of $9.6 million offsetting deferred tax expense of $8.2 million. The reduction was the result of a change in estimate relating to the realization of net operating loss carryforwards (NOL's). At December 31, 2000, the Company carried a valuation account reserving part of the NOL's set to expire during the tax year ended August 31, 2001. Due to higher than projected taxable income for the 2001 tax year, the Company utilized more NOL's than originally anticipated resulting in the deferred tax benefit. As of December 31, 2001, the remaining valuation allowance is $9.9 million. For additional information, see Note 7 in the notes to the consolidated financial statements.
LIQUIDITY AND CAPITAL RESOURCES
As of December 31, 2002, the Company had cash and cash equivalents of $52.0 million, a decrease of $8.4 million from December 31, 2001. The net cash provided by operating activities as reflected on the Consolidated Statement of Cash Flows was $33.2 million for 2002. Due to reduced revenues during 2002, accounts and notes receivable decreased $8.9 million. Lower utilization and reduced capital spending resulted in a decrease of $19.8 million to accounts payable and accrued liabilities.
Net cash used in investing activities was $38.7 million. This included $45.2 million for capital expenditures net of proceeds from the sale of assets of $6.5 million. Net cash used in financing activities was $2.9 million. This included $5.5 million repayment of debt net of $2.6 million proceeds from the settlement of three interest rate swap agreements.
As of December 31, 2001, the Company had cash and cash equivalents of $60.4 million, a decrease of $2.9 million from December 31, 2000. The primary sources of cash in 2001, as reflected on the Consolidated Statement of Cash Flows, were $116.0 million provided by operating activities and $7.6 million from the disposition of assets. Proceeds from the disposition of assets included the sale of various non-marketable rigs and components and reimbursements from customers for equipment lost in the hole.
The primary uses of cash in 2001 were $122.0 million for capital expenditures and $5.0 million for repayment of debt. Major projects during the year included modifications to jackup Rig 22 as a result of its scheduled five-year Coast Guard inspection, completion of Rig 216 to work in the Karachaganak field in Kazakhstan, and purchase of drill pipe and other rental tools for Quail. Repayment of debt included $4.5 million on a five-year note with Boeing Capital Corporation for barge Rig 75 in Nigeria.
The Company has total long-term debt, including the current portion, of $589.9 million at December 31, 2002. The Company has a $50.0 million revolving credit facility with a group of banks led by Bank of America. This facility is available for working capital requirements, general corporate purposes and to support letters of credit. The revolver is collateralized by accounts receivable, inventory and certain barge rigs located in the Gulf of Mexico. The facility contains customary affirmative and negative covenants. Availability under the revolving credit facility is subject to certain borrowing base limitations based on 80 percent of eligible receivables plus 50 percent of supplies in inventory, less the amount utilized in support of letters of credit. Currently, the borrowing base of $41.2 million is reduced by $15.7 million in outstanding letters of credit, resulting in available revolving credit of $25.5 million. As of December 31, 2002 no amounts have been drawn down against the revolving credit facility. The revolver terminates on October 22, 2003. The Company expects to renew or replace the revolving loan facility by the end of the third quarter of 2003.
LIQUIDITY AND CAPITAL RESOURCES (continued)
The Company anticipates that funds required for capital spending in 2003 will be met from existing cash and cash provided by operations. It is management's present intention to limit capital spending, net of reimbursements from customers, to approximately $50 million in 2003. Should new drilling projects or other opportunities requiring additional capital arise, or should revenues not meet management's expectations, the Company may utilize the revolving credit facility. In addition, the Company may seek project financing or equity participation from outside alliance partners or customers to fund certain capital projects. The Company cannot predict whether such financing or equity participation would be available on terms acceptable to the Company.
The Company is exposed to interest rate risk from its fixed-rate debt. The Company had hedged against the risk of changes in the fair value associated with its 9.75% Senior Notes by entering into three fixed-to-variable interest rate swap agreements with a total notional amount of $150.0 million. For the year ended December 31, 2002, the interest rate swap agreements reduced interest expense by $2.9 million.
On July 24, 2002, the Company terminated all the interest rate swap agreements and received $3.5 million. A gain totaling $2.6 million will be recognized as a reduction to interest expense over the remaining term (ending November 2006) of the debt instrument, of which $0.3 million was recognized during 2002.
See Note 4 of the notes to the consolidated financial statements for information regarding the Company's exchange offer which was completed May 2, 2002.
LIQUIDITY AND CAPITAL RESOURCES (continued)
The following tables summarize the Company's future contractual obligations and other commercial commitments as of December 31, 2002.
(1) Long-term debt includes the 9.75% Senior Notes, the 10.125% Senior Notes, the 5.5% Convertible Subordinated Notes, the secured 10.1278% promissory note and the capital lease. For additional information, see Note 4 in the notes to the consolidated financial statements.
(2) Operating leases consist of lease agreements in excess of one year for office space, equipment, vehicles and personal property. For additional information, see Note 12 in the notes to the consolidated financial statements.
(3) The Company has available a $50.0 million revolving credit facility. As of December 31, 2002, none has been drawn down, but $15.7 million of availability has been used to support letters of credit that have been issued. The revolving credit facility expires in October 2003.
The Company does not have any unconsolidated special-purpose entities, off-balance-sheet financing arrangements or guarantees of third-party financial obligations. The Company has no energy or commodity contracts.
OTHER MATTERS
Business Risks
Internationally, the Company specializes in drilling geologically challenging wells in locations that are difficult to access and/or involve harsh environmental conditions. The Company's international services are primarily utilized by major and national oil companies in the exploration and development of reserves of oil. In the United States, the Company primarily drills offshore in the Gulf of Mexico with barge, jackup and platform rigs for major and independent oil and gas companies. Business activity is dependent on the exploration and development activities of the major, independent and national oil and gas companies that make up the Company's customer base. Generally, temporary fluctuations in oil and gas prices do not materially affect these companies' exploration and development activities, and consequently do not materially affect the operations of the Company, except for the Gulf of Mexico, where drilling contracts are generally for a shorter term, and oil and gas companies tend to respond more quickly to upward or downward changes in prices. Many international contracts are of longer duration and oil and gas companies have committed to longer-term projects to develop reserves and thus our international operations are not as susceptible to short term fluctuations in prices. However, sustained increases or decreases in oil and natural gas prices could have an impact on customers' long-term exploration and development activities, which in turn could materially affect the Company's operations. Generally, a sustained change in the price of oil would have a greater impact on the Company's international operations while a sustained change in the price of natural gas would have a greater effect on U.S. operations. Due to the locations in which the Company drills, the Company's operations are subject to interruption, prolonged suspension and possible expropriation due to political instability and local community unrest. Further, the Company is exposed to liability issues from pollution arising out of its operations and to loss of revenues in the event of a blowout. The majority of the political and environmental risks are transferred to the operator by contract or otherwise insured.
Critical Accounting Policies
The Company considers certain accounting policies related to impairment of property, plant and equipment, impairment of goodwill, the valuation of deferred tax assets and revenue recognition to be critical accounting policies due to the estimation processes involved in each. Other significant accounting policies are summarized in Note 1 in the notes to the consolidated financial statements.
Impairment of property, plant and equipment - Management periodically evaluates the Company's property, plant and equipment to determine that their net carrying value is not in excess of their net realizable value. These evaluations are performed when the Company has realized sustained significant declines in utilization and dayrates and recovery is not contemplated in the near future. Management considers a number of factors such as estimated future cash flows, appraisals and current market value analysis in determining net realizable value. Assets are written down to their fair value if it is below its net carrying value.
Impairment of goodwill - Management periodically assesses whether the excess of cost over net assets acquired is impaired based on the estimated fair value of the operation to which it relates, which value is generally determined based on estimated future cash flows of that operation. If the estimated fair value is in excess of the carrying value of the operation, no further analysis is performed. If the fair value of each operation, to which goodwill has been assigned, is less than the carrying value, we will 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 an impairment should be recorded.
OTHER MATTERS (continued)
In 2002, SFAS No. 142, "Goodwill and Other Intangible Assets," became effective and as a result, the Company discontinued the amortization of $189.1 million of goodwill. The Company recorded $7.5 million of goodwill amortization in 2001 and 2000 and would have recorded $7.5 million of goodwill amortization during 2002. In lieu of amortization, the Company performed an initial impairment review of goodwill and as a result impaired goodwill by $73.1 million. The Company will perform an annual impairment review, in December, hereafter. The impairment was recognized as a cumulative effect of a change in accounting principle. See Note 3 of the notes to the consolidated financial statements for additional information.
Accounting for income taxes - As part of the process of preparing the consolidated financial statements, the Company is required to estimate the income taxes in each of the jurisdictions in which the Company operates. 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. These differences and the net operating loss carryforwards result in deferred tax assets and liabilities, which are included within the Company's consolidated balance sheet. The Company must then assess the likelihood that the deferred tax assets will be recovered from future taxable income, and to the extent the Company believes that recovery is not likely, the Company must establish a valuation allowance. To the extent the Company establishes a valuation allowance or increases or decreases this allowance in a period, the Company must include an expense or reduction of expense within the tax provision in the statement of operations.
Revenue recognition - The Company recognizes revenues and expenses on dayrate contracts as the drilling progresses (percentage-of-completion method) because the Company does not bear the risk of completion of the well. For meterage contracts, the Company recognizes the revenues and expenses upon completion of the well (completed-contract method). Revenues from rental activities are recognized ratably over the rental term which is generally less than six months.
Recent Accounting Pronouncements
In June 2001, the Financial Accounting Standard Board ("FASB") issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 is effective for fiscal years beginning after June 15, 2002 and establishes an accounting standard requiring the recording of the fair value of liabilities associated with the retirement of long-term assets in the period in which the liability is incurred. Accordingly, we adopted this standard in the first quarter of 2003. We do not expect this standard to have a material impact on our financial position or results of operations.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 was effective January 1, 2002. This statement supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," and amends Accounting Principles Board Opinion ("APB") No. 30 for the accounting and reporting of discontinued operations, as it relates to long-lived assets. Our adoption of SFAS No. 144 did not affect our financial position or results of operations.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, No. 44, and No. 64, Amendment of FASB Statement No. 13, and Technical Corrections." SFAS No. 145 is effective for fiscal years beginning after May 15, 2002. We will adopt this standard in 2003 and do not expect it to have a significant effect on our results of operations or our financial position.
In July 2002, the FASB issued SFAS No. 146, "Accounting For Costs Associated with Exit or Disposal Activities." SFAS No. 146 is effective for exit or disposal activities initiated after December 31, 2002. We do not expect the adoption of this standard to have any impact on our financial position or results of operations.
OTHER MATTERS (continued)
On December 31, 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure-An Amendment of SFAS No. 123." The standard provides additional transition guidance for companies that elect to voluntarily adopt the accounting provisions of SFAS No. 123, "Accounting for Stock-Based Compensation." SFAS No. 148 does not change the provisions of SFAS No. 123 that permit entities to continue to apply the intrinsic value method of APB No. 25, "Accounting for Stock Issued to Employees." As we continue to follow APB No. 25, our accounting for stock-based compensation will not change as a result of SFAS No. 148. SFAS No. 148 does require certain new disclosures in both annual and interim financial statements. The required annual disclosures are effective immediately and have been included in Note 1 of the notes to the consolidated financial statements included in Item 8. The new interim disclosure provisions will be effective in the first quarter of 2003.
In November 2002, the FASB issued FASB Interpretation ("FIN") 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantee of Indebtedness of Others." FIN 45 requires that upon issuance of a guarantee, the guarantor must recognize a liability for the fair value of the obligation it assumes under that guarantee. FIN 45's provisions for initial recognition and measurement should be applied on a prospective basis to guarantees issued or modified after December 31, 2002. The guarantor's previous accounting for guarantees that were issued before the date of FIN 45's initial application may not be revised or restated to reflect the effect of the recognition and measurement provisions of the interpretation. The disclosure requirements are effective for financial statements of both interim and annual periods that end after December 15, 2002. The Company is not a guarantor under any significant guarantees and thus this interpretation will not have a significant effect on the Company's financial position or results of operations.
On January 17, 2003, the FASB issued FIN 46, "Consolidation of Variable Interest Entities, An Interpretation of Accounting Research Bulletin No. 51." The primary objectives of FIN 46 are to provide guidance on how to identify entities for which control is achieved through means other than through voting rights (variable interest entities ("VIE")) and how to determine when and which business enterprise should consolidate the VIE. This new model for consolidation applies to an entity in which either (1) the equity investors do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity's activities without receiving additional subordinated financial support from other parties. See Note 1 of the notes to the consolidated financial statements regarding our consolidation of AralParker, a company in which we own a 50 percent equity interest. We are consolidating this company because we exert significant influence and have a financial interest in the form of a loan, in addition to our equity interest.
Item 7A.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk
In December 2001, the Company began to utilize hedging strategies to manage fixed-rate interest exposure by entering into one interest rate swap agreement. In January 2002, the Company entered into two additional interest rate swap agreements. The terms of the interest rate swap agreements are as follows:
The Company assumed no ineffectiveness as each interest rate swap agreement met the short-cut method requirements under SFAS No. 133 for fair value hedges of debt instruments. As a result, changes in the fair value of the interest rate swap agreements were offset by changes in the fair value of the debt and no net gain or loss was recognized in earnings. During the year ended December 31, 2002, the interest rate swap agreements reduced interest expense by $2.9 million.
On July 24, 2002, the Company terminated all the interest rate swap agreements and received $3.5 million. A gain totaling $2.6 million will be recognized as a reduction to interest expense over the remaining term (ending November 2006) of the debt instrument, of which $0.3 million was recognized during 2002.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Stockholders Parker Drilling Company
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) of the Form 10-K, present fairly, in all material respects, the financial position of Parker Drilling Company and its subsidiaries at December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) of the Form 10-K, presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these financial statements in accordance with auditing standards generally accepted in the United States of America which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 3 to the financial statements, in 2002, the Company changed its method of accounting for goodwill as a result of adopting the provisions of Statement of Financial Accounting Standards No. 142 "Goodwill and Other Intangible Assets."
/s/ PricewaterhouseCoopers LLP PricewaterhouseCoopers LLP
Tulsa, Oklahoma January 29, 2003
PARKER DRILLING COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENT OF OPERATIONS (Dollars in Thousands Except Per Share and Weighted Average Shares Outstanding)
See accompanying notes to the consolidated financial statements.
PARKER DRILLING COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (Dollars in Thousands)
See accompanying notes to the consolidated financial statements.
PARKER DRILLING COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEET (Continued) (Dollars in Thousands)
See accompanying notes to the consolidated financial statements.
PARKER DRILLING COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS (Dollars in Thousands)
See accompanying notes to the consolidated financial statements.
PARKER DRILLING COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENT OF CASH FLOWS (Continued) (Dollars in Thousands)
See accompanying notes to the consolidated financial statements.
PARKER DRILLING COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (Dollars and Shares in Thousands)
See accompanying notes to the consolidated financial statements.
PARKER DRILLING COMPANY AND SUBSIDIARIES NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
Note 1 - Summary of Significant Accounting Policies
Consolidation - The consolidated financial statements include the accounts of Parker Drilling Company ("Parker Drilling") and all of its majority-owned subsidiaries and a company in which a subsidiary of Parker Drilling has a 50 percent stock ownership but exerts significant influence over its operation. A subsidiary of Parker Drilling also has a 50 percent interest in another company, which is accounted for under the equity method (collectively, the "Company").
Operations - The Company provides land and offshore contract drilling services and rental tools on a worldwide basis to major, independent and foreign-owned oil and gas companies. At December 31, 2002, the Company's rig fleet consists of 27 barge drilling and workover rigs, seven offshore jackup rigs, four offshore platform rigs and 41 land rigs. The Company specializes in the drilling of deep and difficult wells, drilling in remote and harsh environments, drilling in transition zones and offshore waters, and in providing specialized rental tools. The Company also provides a range of services that are ancillary to its principal drilling services, including engineering and logistics, as well as project management activities.
Drilling Contracts and Rental Revenues - The Company recognizes revenues and expenses on dayrate contracts as the drilling progresses (percentage-of-completion method) because the Company does not bear the risk of completion of the well. For meterage contracts, the Company recognizes the revenues and expenses upon completion of the well (completed-contract method). Revenues from rental activities are recognized ratably over the rental term which is generally less than six months.
Construction Contract - The Company has historically only constructed drilling rigs for its own use. At the request of one of its significant customers, the Company entered into a contract to design, construct, mobilize and sell ("construction contract") a specialized drilling rig to drill extended reach wells to offshore targets from a land-based location on Sakhalin Island, Russia, for an international consortium of oil and gas companies. The Company also entered into a contract to subsequently operate the rig on behalf of the consortium. Generally Accepted Accounting Principles ("GAAP") requires that revenues received and costs incurred related to the construction contract be accounted for and reported on a gross basis and income for the related fees should be recognized on a percentage of completion basis. Because this construction contract is not a part of the Company's historical or normal operations, the revenues and costs related to this contract have been shown as a separate component in the statement of operations. Construction costs in excess of funds received from the customer are accumulated and reported as part of other current assets. At December 31, 2002 and 2001, a net receivable (construction costs less progress payments) of $5.3 million and $6.0 million, respectively, are included in other current assets.
Cash and Cash Equivalents - For purposes of the balance sheet and the statement of cash flows, the Company considers cash equivalents to be all highly liquid debt instruments that have a remaining maturity of three months or less at the date of purchase.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 1 - Summary of Significant Accounting Policies (continued)
Property, Plant and Equipment - The Company provides for depreciation of property, plant and equipment primarily on the straight-line method over the estimated useful lives of the assets after provision for salvage value. The depreciable lives for land drilling equipment approximate 15 years. The depreciable lives for offshore drilling equipment generally range from 15 to 20 years. The depreciable lives for certain other equipment, including drill pipe and rental tools, range from three to seven years. Depreciable lives for buildings and improvements range from 10 to 30 years. Interest totaling approximately $0.1 million, $1.6 million and $0.5 million was capitalized during the years ended December 31, 2002, 2001 and 2000, respectively. When properties are retired or otherwise disposed of, the related cost and accumulated depreciation are removed from the accounts and any gain or loss is included in operations. Management periodically evaluates the Company's assets to determine that their net carrying value is not in excess of their net realizable value. Management considers a number of factors such as estimated future cash flows, appraisals and current market value analysis in determining net realizable value. Assets are written down to their fair value if it is below its net carrying value.
Goodwill - Effective January 1, 2002, the Company adopted Statement of Financial Accounting Standards ("SFAS") No. 142, "Goodwill and Other Intangible Assets." In accordance with this accounting principle, goodwill is no longer amortized but will be assessed for impairment on at least an annual basis (see Note 3 for additional details regarding goodwill).
Rig Materials and Supplies - Since the Company's international drilling generally occurs in remote locations, making timely outside delivery of spare parts uncertain, a complement of parts and supplies is maintained either at the drilling site or in warehouses close to the operations. During periods of high rig utilization, these parts are generally consumed and replenished within a one-year period. During a period of lower rig utilization in a particular location, the parts, like the related idle rigs, are generally not transferred to other international locations until new contracts are obtained because of the significant transportation costs, which would result from such transfers. The Company classifies those parts which are not expected to be utilized in the following year as long-term assets. Rig materials and supplies are valued at the lower of cost or market value.
Other Assets - Other assets include the Company's investment in marketable equity securities. Equity securities that are classified as available for sale are stated at fair value as determined by quoted market prices. Unrealized holding gains and losses are excluded from current earnings and are included in comprehensive income, net of taxes, in a separate component of stockholders' equity until realized. At December 31, 2002 and 2001, the fair value of equity securities totaled $1.3 million and $1.8 million, respectively.
In computing realized gains and losses on the sale of equity securities, the cost of the equity securities sold is determined using the specific cost of the security when originally purchased.
Other Long-Term Obligations - Included in this account is the accrual of workers' compensation liability, which is not expected to be paid within the next year.
Income Taxes - Deferred tax liabilities and assets are determined based on the difference between the financial statement and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 1 - Summary of Significant Accounting Policies (continued)
Earnings (Loss) Per Share (EPS) - Basic earnings (loss) per share is computed by dividing net income (loss), by the weighted average number of common shares outstanding during the period. The effects of dilutive securities, stock options and convertible debt are included in the diluted EPS calculation, when applicable.
Concentrations of Credit Risk - Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of trade receivables with a variety of national and international oil and gas companies. The Company generally does not require collateral on its trade receivables.
At December 31, 2002 and 2001, the Company had deposits in domestic banks in excess of federally insured limits of approximately $51.6 million and $57.6 million, respectively. In addition, the Company had deposits in foreign banks at December 31, 2002 and 2001 of $4.8 million and $3.5 million, respectively, which are not federally insured.
The Company's drilling customer base consists of major, independent and foreign-owned oil and gas companies. For fiscal year 2002 and 2001 respectively, ChevronTexaco was the Company's largest customer with approximately 17 percent of total revenues in 2002 and 15 percent in 2001. In 2002, Tengizchevroil, a joint venture with four oil companies, was the second largest customer with 13 percent of total revenues. Shell Petroleum Development Company of Nigeria was the Company's largest customer for 2000 with approximately 10 percent of total revenues.
Derivative Financial Instruments - The Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS Nos. 137 and 138. These statements require that every derivative instrument be recorded on the balance sheet as either an asset or liability measured by its fair value. These statements also establish new accounting rules for hedge transactions, which depend on the nature of the hedge relationship.
The Company uses derivative instruments to hedge exposure to interest rate risk. For hedges which meet the SFAS No. 133 criteria, the Company formally designates and documents the instrument as a hedge of a specific underlying exposure, as well as the risk management objective and strategy for undertaking each hedge transaction.
Fair Value of Financial Instruments - The carrying amount of the Company's cash and cash equivalents and short-term and long-term debt had fair values that approximated their carrying amounts, except for the Company's 5.5% Convertible Subordinated Notes which had a carrying value of $124.5 million and a fair market value of $115.3 million at December 31, 2002.
Stock-Based Compensation - The Company has elected the disclosure-only provisions of SFAS No. 123, "Accounting for Stock-Based Compensation." Accordingly, no compensation cost has been recognized for the Company's stock option plans when the option price is equal to or greater than the fair market value of a share of the Company's common stock on the date of grant. Pro forma net income and earnings per share are reflected in the following tables as if compensation cost had been determined based on the fair value of the options at their applicable grant date, according to the provisions of SFAS No. 123.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 1 - Summary of Significant Accounting Policies (continued)
The fair value of each option grant is estimated using the Black-Scholes option pricing model with the following assumptions:
Options granted in 2002, 2001 and 2000 under the 1997 Stock Plan had an estimated fair value of $1,759,000, $4,326,000 and $203,000 respectively.
Accounting Estimates - The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 2 - Disposition of Assets
On November 20, 2000, the Company sold its last remaining U.S. land rig, Rig 245 in Alaska, for $20.0 million. The Company recognized a pre-tax gain of $14.9 million during the fourth quarter of 2000.
Note 3 - Goodwill
Effective January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other Intangible Assets." In accordance with this accounting principle, goodwill is no longer amortized but will be assessed for impairment on at least an annual basis.
As an initial step in the implementation process, the Company identified four reporting units that would be tested for impairment. The four units qualify as reporting units in that they are one level below an operating segment, or an individual operating segment and discrete financial information exists for each unit. The four reporting units identified by segment are as follows:
U.S. drilling segment: Barge rigs Jackup and Platform rigs (1)
International drilling segment: Nigeria barge rigs
Rental tools segment: Rental tools business
(1) The jackup and platform rigs were aggregated due to the similarities in the markets served.
As required under the transitional accounting provisions of SFAS No. 142, the Company completed both steps required to identify and measure goodwill impairment at each reporting unit. The first step involved identifying all reporting units with carrying values (including goodwill) in excess of fair value, which was estimated by an independent business valuation consultant using the present value of estimated future cash flows. The reporting units for which the carrying value exceeded fair value were then measured for impairment by comparing the implied fair value of the reporting unit goodwill, determined in the same manner as in a business combination, with the carrying amount of goodwill. The jackup and platform rigs reporting unit was the only unit where impairment was identified. As a result, goodwill related to the jackup and platform rigs was impaired by $73.1 million and was recognized as a cumulative effect of a change in accounting principle retroactive to the first quarter. The Company will perform its annual impairment review during the fourth quarter of each year. The review in the fourth quarter of 2002, resulted in no additional impairment.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 3 - Goodwill (continued)
The following is a summary of the change in goodwill by reporting unit for the years ended December 31, 2000, 2001 and 2002 (dollars in thousands):
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 3 - Goodwill (continued)
The following is a summary of pro forma net income (loss) and earnings (loss) per share as adjusted to remove the amortization of goodwill (dollars in thousands, except per share amounts):
(1) Certain goodwill amounts are non-deductible for tax purposes; therefore, the income tax impact reflects only the deductible goodwill amortization.
(2) Loss before extraordinary gain - as reported - $(22,981) Loss before extraordinary gain - as adjusted - $(16,630)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 4 - Long-Term Debt
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 4 - Long-Term Debt (continued)
The aggregate maturities of long-term debt for the five years ending December 31, 2007 are as follows (000's): 2003 - $6,486; 2004 - $129,565; 2005 - $0; 2006 - $214,192; 2007 - $0.
The Senior Notes were initially issued in November 1996 and in March 1998 in amounts of $300 million (Series B) and $150 million (Series C) at 9.75%. The $300 million issue was sold at a $2.4 million discount while the $150 million issue was sold at a premium of $5.7 million. In May 1998, a registration statement was filed by the Company which offered to exchange the Series B and C Notes for new Series D Notes. The form and terms of the Series D Notes are identical in all material respects to the form and terms of the Series B and C Notes, except for certain transfer restrictions and registration rights relating to the Series C Notes. All of the Series B Notes except $189 thousand and all of the Series C Notes were exchanged for new Series D Notes per this offering. As discussed in Note 6, the Company entered into various interest rate swap agreements to modify the interest characteristics of the Senior Notes.
On May 2, 2002, the Company announced it had successfully completed the exchange of $235.6 million in principal amount of new 10.125% Senior Notes due 2009 ("New Notes") for a like amount of its 9.75% Senior Notes due 2006 ("Outstanding Notes"), pursuant to an exchange offer described in the Offering Circular dated April 1, 2002 (the "Exchange Offer"). The consummation of the Exchange Offer was effected without registration, in reliance on the registration exemption provided by Section 4(2) of the Securities Act of 1933, as amended, which applies to offers and sales of securities that do not involve a public offering, and Regulation D promulgated under that act. On July 1, 2002, the Company filed a registration statement on Form S-4 offering to exchange the New Notes for notes of the Company having substantially identical terms in all material respects as the Outstanding Notes (the "Exchange Notes"). The offer to exchange the New Notes for Exchange Notes was consummated on September 17, 2002. The New Notes and Exchange Notes will be governed by the terms of the indenture executed by the Company, the Subsidiary Guarantors and the trustee dated May 2, 2002, the terms of which are substantially the same as the terms of the 1998 Indenture, as amended by the Fourth Supplemental Indenture, as described below.
In connection with the Exchange Offer, the Company solicited consents to certain amendments to the definitions and covenants in the indenture under which the Outstanding Notes were issued, which all participants in the Exchange Offer were deemed to have accepted. As a result of the participation in the Exchange Offer of more than 50 percent of the holders of the Outstanding Notes, the amendments to the 1998 Indenture were agreed, and which amendments have been effected by the execution of the Fourth Supplemental Indenture by the Company, the Subsidiary Guarantors and the trustee (as amended, the "1998 Indenture"). As a result of the Exchange Offer, the Company incurred and expensed fees of approximately $4.0 million.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 4 - Long-Term Debt (continued)
In July 1997, the Company issued $175 million of Convertible Subordinated Notes due 2004. The Notes bear interest at 5.5% payable semi-annually in February and August. The Notes are convertible at the option of the holder into shares of common stock of Parker Drilling at $15.39 per share at any time prior to maturity. The Notes are currently redeemable at the option of the Company at certain stipulated prices. During the fourth quarter of 2000, the Company repurchased on the open market $50.5 million principal amount of the 5.5% Notes at an average price of 86.11 percent of face value, recognizing an extraordinary gain of $3.9 million, net of $2.2 million of tax. The Note repurchases were funded with proceeds from an equity offering in September 2000, whereby the Company sold 13.8 million shares of common stock for net proceeds of approximately $87.3 million. The amount of outstanding Notes at December 31, 2002 was $124.5 million.
On October 22, 1999, the Company entered into a $50.0 million revolving loan facility with a group of banks led by Bank of America. The facility is available for working capital requirements, general corporate purposes and to support letters of credit and bears interest at prime plus 0.50% or LIBOR plus 2.50%. At December 31, 2002, no amounts have been drawn down against the facility but $15.7 million of availability of $41.2 million (borrowing base at December 31, 2002) has been used to support letters of credit that have been issued. The revolver is collateralized by accounts receivable, inventory and certain barge rigs located in the Gulf of Mexico. The facility will terminate on October 22, 2003. The Company plans to renew or replace the revolving loan facility by the end of the third quarter of 2003.
On October 7, 1999, a wholly owned subsidiary of the Company entered into a loan agreement with Boeing Capital Corporation for the refinancing of a portion of the capital cost of barge Rig 75. The loan principal of approximately $24.8 million plus interest is being repaid in 60 monthly payments of approximately $0.5 million. The loan is collateralized by barge Rig 75 and is guaranteed by Parker Drilling. The amount of principal outstanding at the end of 2002 was $10.6 million.
Each of the 10.125% and the 9.75% Senior Notes, 5.5% Convertible Subordinated Notes and the revolving loan facility contains customary affirmative and negative covenants, including restrictions on incurrence of debt and sales of assets. The revolving loan facility contains covenants which require minimum adjusted tangible net worth, fixed charge coverage ratio and limits annual capital expenditures. The revolving loan facility prohibits payment of dividends and the indenture for the Senior Notes restricts the payment of dividends.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 5 - Guarantor/Non-Guarantor Consolidating Condensed Financial Statements
Set forth on the following pages are the consolidating condensed financial statements of the restricted subsidiaries and our subsidiaries which are not restricted by the Senior Notes. All of the Company's Senior Notes are guaranteed by substantially all wholly owned subsidiaries of Parker Drilling. There are currently no restrictions on the ability of the subsidiaries to transfer funds to Parker Drilling in the form of cash dividends, loans or advances. Parker Drilling is a holding company with no operations, other than through its subsidiaries. In prior years, the non-guarantors were inconsequential, individually and in the aggregate, to the consolidated financial statements and separate financial statements of the guarantors were not presented because management had determined that they would not be material to investors.
In August, 2002, Parker Drilling Company International Limited ("PDCIL") entered into an agreement to sell two of its rigs in Kazakhstan to AralParker, a Kazakhstan joint venture company owned 50 percent by PDCIL and 50 percent by a Kazakhstan company. Because PDCIL has significant influence over the business affairs of AralParker, its financial statements are consolidated with those of the Company.
AralParker, Casuarina Limited (a wholly owned captive insurance company) and Parker Drilling Investment Company are all non-guarantor subsidiaries whose aggregate financial position and results of operations are no longer deemed to be inconsequential and, accordingly the Company is providing consolidating condensed financial information of the parent, Parker Drilling, the guarantor subsidiaries, and the non-guarantor subsidiaries for the year ended December 31, 2002.
PARKER DRILLING COMPANY AND SUBSIDIARIES CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS (Dollars in Thousands)
(1) All field operations general and administrative expenses are included in operating expenses.
PARKER DRILLING COMPANY AND SUBSIDIARIES CONSOLIDATING CONDENSED BALANCE SHEET (Dollars in Thousands)
PARKER DRILLING COMPANY AND SUBSIDIARIES CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS (Dollars in Thousands)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 6 - Derivative Financial Instruments
The Company is exposed to interest rate risk from its fixed-rate debt. The Company has hedged against a portion of the risk of changes in fair value associated with its $214.2 million 9.75% Senior Notes by entering into three fixed-to-variable interest rate swap agreements with a total notional amount of $150.0 million. The terms of the interest rate swap agreements are as follows:
The Company assumes no ineffectiveness as each interest rate swap agreement meets the short-cut method requirements under SFAS No. 133 for fair value hedges of debt instruments. As a result, changes in the fair value of the interest rate swap agreements are offset by changes in the fair value of the debt and no net gain or loss is recognized in earnings. During the year ended December 31, 2002, the interest rate swap agreements reduced interest expense by $2.9 million.
On July 24, 2002, the Company terminated all the interest rate swap agreements and received $3.5 million. A gain totaling $2.6 million will be recognized as a reduction to interest expense over the remaining term (ending November 2006) of the debt instrument, of which $0.3 million was recognized during 2002.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 7 - Income Taxes
Income (loss) before income taxes, cumulative effect of change in accounting principle and extraordinary gain is summarized as follows (dollars in thousands):
Income tax expense (benefit) is summarized as follows (dollars in thousands):
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 7 - Income Taxes (continued)
Total income tax expense (benefit) differs from the amount computed by multiplying income (loss) before income taxes by the U.S. federal income tax statutory rate. The reasons for this difference are as follows (dollars in thousands):
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 7 - Income Taxes (continued)
The components of the Company's tax assets and (liabilities) as of December 31, 2002 and 2001 are shown below (dollars in thousands):
The change in the valuation allowance in 2002 is the result of higher utilization of net operating loss carryforwards previously reserved because they were expected to expire unused. The Company has a remaining valuation allowance of $7,009,000 with respect to its net deferred tax asset for the amount of net operating loss carryforwards expected to expire unused. However, the amount of the asset considered realizable could be different in the near term if estimates of future taxable income change.
At December 31, 2002, the Company had $141,510,000 of net operating loss carryforwards. For tax purposes the net operating loss carryforwards expire over a 20-year period ending December 31 as follows: 2007 - $10,141,000; 2008 - $11,968,000; 2009 - $6,700,000; thereafter - $112,701,000.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders' Equity
In September 2000, the Company sold 13.8 million common shares in a public offering, resulting in net proceeds (after deducting issuance costs) of $87.3 million. The proceeds were used to acquire, upgrade and refurbish certain offshore and land drilling rigs and for general corporate purposes, including the repayment of debt.
Stock Plans
The Company's employee and non-employee director stock plans are summarized as follows:
The 1994 Non-Employee Director Stock Option Plan ("Director Plan") provides for the issuance of options to purchase up to 200,000 shares of Parker Drilling's common stock. The option price per share is equal to the fair market value of a Parker Drilling share on the date of grant. The term of each option is 10 years, and an option first becomes exercisable six months after the date of grant. All shares available for issuance under this plan have been granted.
The 1994 Executive Stock Option Plan provides that the directors may grant a maximum of 2,400,000 shares to key employees of the Company and its subsidiaries through the granting of stock options, stock appreciation rights and restricted and deferred stock awards. The option price per share may not be less than 50 percent of the fair market value of a share on the date the option is granted, and the maximum term of a non-qualified option may not exceed 15 years and the maximum term of an incentive option is 10 years. All shares available for issuance under this plan have been granted.
The 1997 Stock Plan initially authorized 4,000,000 shares to be available for granting to officers and key employees who, in the opinion of the board of directors, were in a position to contribute to the growth, management and success of the Company. This plan was approved by the board of directors as a "broad-based" plan under the interim rules of the New York Stock Exchange and, as a result, more than 50 percent of the awards under this plan have been made to non-executive employees. The option price per share may not be less than the fair market value on the date the option is granted for incentive options and not less than par value of a share of common stock for non-qualified options. The maximum term of an incentive option is 10 years and the maximum term of a non-qualified option is 15 years. The plan was amended in July 1999, April 2001 and September 2002, to grant authority to the compensation committee to issue awards and to authorize 2,000,000; 1,000,000; and 1,800,000 additional shares, respectively, for issuance, which shares were registered with the SEC. As of December 31, 2002, there were 1,227,700 shares available for granting.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders' Equity (continued)
Information regarding the Company's stock option plans is summarized below:
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders' Equity (continued)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders' Equity (continued)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders' Equity (continued)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders' Equity (continued)
The Company has three additional stock plans which provide for the issuance of stock for no cash consideration to officers and key non-officer employees. Under two of the plans, each employee receiving a grant of shares may dispose of 15 percent of the grant on each annual anniversary date from the date of grant for the first four years and the remaining 40 percent on the fifth-year anniversary. These two plans have a total of 11,375 shares reserved and available for granting. Shares granted under the third plan are fully vested no earlier than 24 months from the effective date of the grant and not later than 36 months. The third plan has a total of 1,562,195 shares reserved and available for granting. No shares were granted under these plans in 2002, 2001 and 2000.
In prior years the Company purchased shares from certain of its employees, who received stock through its stock option plan, at fair market value. At December 31, 2001, 604,870 shares were held in Treasury which includes 98,293 shares purchased by the Company at the fair market value of $289,479. These shares were issued to the Stock Bonus Plan as the Company's matching contribution. The Plan was funded in January 2002. At December 31, 2002, 506,577 shares were held in Treasury.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders' Equity (continued)
Stock Reserved For Issuance
The following is a summary of common stock reserved for issuance:
Stockholder Rights Plan
The Company adopted a stockholder rights plan on June 25, 1998, to assure that the Company's stockholders receive fair and equal treatment in the event of any proposed takeover of the Company and to guard against partial tender offers and other abusive takeover tactics to gain control of the Company without paying all stockholders a fair price. The rights plan was not adopted in response to any specific takeover proposal. Under the rights plan, the Company's board of directors declared a dividend of one right to purchase one one-thousandth of a share of a new series of junior participating preferred stock for each outstanding share of common stock. The plan was amended on September 22, 1998, to eliminate the restriction on the board of directors' ability to redeem the shares for two years in the event the majority of the board of directors does not consist of the same directors that were in office as of June 25, 1998 ("Continuing Directors"), or directors that were recommended to succeed Continuing Directors by a majority of the Continuing Directors.
The rights may only be exercised 10 days following a public announcement that a third party has acquired 15 percent or more of the outstanding common shares of the Company or 10 days following the commencement of, or announcement of an intention to make a tender offer or exchange offer, the consummation of which would result in the beneficial ownership by a third party of 15 percent or more of the common shares. When exercisable, each right will entitle the holder to purchase one one-thousandth share of the new series of junior participating preferred stock at an exercise price of $30, subject to adjustment. If a person or group acquires 15 percent or more of the outstanding common shares of the Company, each right, in the absence of timely redemption of the rights by the Company, will entitle the holder, other than the acquiring party, to purchase for $30, common shares of the Company having a market value of twice that amount.
The rights, which do not have voting privileges, expire June 30, 2008, and at the Company's option, may be redeemed by the Company in whole, but not in part, prior to expiration for $0.01 per right. Until the rights become exercisable, they have no dilutive effect on earnings per share.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 9 - Reconciliation of Income and Number of Shares Used to Calculate Basic and Diluted Earnings Per Share (EPS)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 9 - Reconciliation of Income and Number of Shares Used to Calculate Basic and Diluted Earnings Per Share (EPS) (continued)
The Company has outstanding $124,509,000 of 5.5% Convertible Subordinated Notes, which are convertible into 8,090,254 shares of common stock at $15.39 per share. The Notes have been outstanding since their issuance in July 1997, but were not included in the computation of diluted EPS because the assumed conversion of the Notes would have had an anti-dilutive effect on EPS. For the year ended December 31, 2002, options to purchase 9,639,810 shares of common stock at prices ranging from $2.24 to $12.1875, which were outstanding during the period, were not included in the computation of diluted EPS because the assumed exercise of the options would have had an anti-dilutive effect on EPS due to the net loss incurred for 2002. For the fiscal year ended December 31, 2001, options to purchase 6,049,000 shares of common stock at prices ranging from $5.00 to $12.1875, which were outstanding during the period, were not included in the computation of diluted EPS because the options' exercise price was greater than the average market price of the common shares during the period. For the year ended December 31, 2000, options to purchase 7,166,036 shares of common stock, respectively, at prices ranging from $2.25 to $12.1875, were outstanding but not included in the computation of diluted EPS because the assumed exercise of the options would have had an anti-dilutive effect on EPS due to the net loss during 2000.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 10 - Employee Benefit Plans
The Parker Drilling Company Stock Bonus Plan ("Plan") was adopted effective September 1980 for eligible employees of Parker Drilling and its subsidiaries who have completed three months of service with the Company. It was amended in 1983 to qualify as a 401(k) plan under the Internal Revenue Code which permits a specified percentage of an employee's salary to be voluntarily contributed on a pre-tax basis and to provide for a Company matching feature. The Plan was amended and restated generally effective January 1, 2001, to comply with certain tax laws. The Plan was further amended effective January 1, 2002 to reflect certain provisions of the Economic Growth and Tax Relief Reconciliation Act of 2001 ("EGTRRA"). Participants may contribute from one percent to 15 percent of eligible earnings and direct contributions to one or more of 13 investment funds. The Plan provides for dollar-for-dollar matching contributions by the Company up to three percent of a participant's compensation and $0.50 for every dollar contributed from three percent to five percent. The Company's matching contribution is made in Parker Drilling common stock and vests immediately. Each Plan year, additional Company contributions can be made, at the discretion of the board of directors, in amounts not exceeding the permissible deductions under the Internal Revenue Code. The Company issued 544,844; 343,289; and 361,855 shares to the Plan in 2002, 2001, and 2000 with the Company recognizing expense of $1,472,437; $1,927,100; and $1,742,193 in each of the periods, respectively.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 11 - Business Segments
The Company is organized into three primary business segments: U.S. drilling operations, international drilling operations, and rental tools. This is the basis management uses for making operating decisions and assessing performance.
(1) Operating income by segment is calculated by excluding net construction contract operating income, general and administrative expense, provision for reduction in carrying value of certain assets and reorganization expense from operating income, as reported in the consolidated statement of operations.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 11 - Business Segments (continued)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 11- Business Segments (continued)
(1) Operating income by segment is calculated by excluding net construction contract operating income, general and administrative expense, provision for reduction of carrying value of certain assets and reorganization expense from operating income, as reported in the consolidated statement of operations.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 12 - Commitments and Contingencies
At December 31, 2002, the Company had a $50.0 million revolving credit facility available for general corporate purposes and to support letters of credit. As of December 31, 2002, $15.7 million of availability has been reserved to support letters of credit that have been issued. At December 31, 2002, no amounts had been drawn under the revolving credit facility.
The Company has various lease agreements for office space, equipment, vehicles and personal property. These obligations extend through 2009 and are typically non-cancelable. Most leases contain renewal options and certain of the leases contain escalation clauses. Future minimum lease payments at December 31, 2002, under operating leases with non-cancelable terms in excess of one year, are as follows:
Total rent expense for all operating leases amounted to $10.9 million for 2002, $5.5 million for 2001, and $3.7 million for 2000.
Each of the executive officers entered into an employment agreement with the Company that became effective during 2002. The term of each agreement is for three years and each provide for automatic extensions of two years, with the exception of Mr. Brassfield and Mr. Wingerter, whose agreements are for two years, and Mr. Robert L. Parker whose agreement is for one year. The employment agreements provide for the following benefits:
*payment of current salary, which may be increased upon review by CEO (or the Board of Directors in case of CEO and Chairman) on an annual basis but cannot be reduced except with consent of the executive, *for payment of target bonuses of up to 100 percent of salary based on meeting certain incentives (75 percent for Mr. Nash and Mr. Whalen and 50 percent for Mr. Wingerter and Mr. Brassfield), and *to be eligible to receive stock options and to participate in other benefits, including without limitation, paid vacation, 401(k) plan, health insurance and life insurance.
If the executive's employment is terminated, including by reason of death or disability or retirement, but excluding termination for cause or termination as a result of the resignation of the executive, unless for good reason (based on definitions of cause and good reason in the agreements), the executive is entitled to receive:
*salary for remainder of month of the termination, *bonus for the prior year if earned and yet unpaid, *remainder of vacation pay for the year, *a severance payment equal to two times the sum of the highest salary and bonus over the previous three years, except for Mr. Brassfield and Mr. Wingerter whose payment will be based on a 1.5 times multiplier ("Additional Benefit"), and *continued health benefits for two years, except for Mr. Brassfield and Mr. Wingerter who will receive these benefits for 1.5 years ("Other Benefits").
In consideration for these benefits the executive agrees to perform his customary duties set forth in the employment agreement, and further covenants not to solicit business except on behalf of the Company during his employment and to refrain from hiring employees of the Company or to compete against the Company for a period of one year following his termination.
In addition to the above benefits, each employment agreement provides that in the event of a change in control, as defined in the agreement, the term of the employment agreement will be extended for three years. If the executive is terminated during this three year period for any reason except for cause or the executive resigns during the first two years after the change in control for good reason, the Additional Benefit payable shall be based on three times salary and bonus, payable in a lump sum, and the Other Benefits shall also be provided for three years. In certain circumstances, the Company has agreed to make the executive whole for excise taxes that may apply with respect to payments made after a change in control. The benefits provided under the employment agreements executed by the executive officers are in lieu of and replace the benefits under the Severance Compensation and Consulting Agreements previously executed by the executive officers, which Severance Compensation and Consulting Agreements have been terminated.
In addition to the executive officers, six other officers and key employees entered into employment agreements that were effective on November 1, 2002, with three agreements with officers providing for similar severance benefits, including change in control provisions, and the remaining agreements providing similar benefits at lower levels without change in control provisions.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 12 - Commitments and Contingencies (continued)
The drilling of oil and gas wells is subject to various federal, state, local and foreign laws, rules and regulations. The Company, as an owner or operator of both onshore and offshore facilities operating in or near waters of the United States, 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") and the Outer Continental Shelf Lands Act. In addition, the Company may also be subject to applicable state law and other civil claims arising out of any such incident. Certain of the Company's facilities are also subject to regulations of the Environmental Protection Agency ("EPA") that require the preparation and implementation of spill prevention, control and countermeasure plans relating to possible discharge of oil into navigable waters. Other regulations of the EPA may require certain precautions in storing, handling and transporting hazardous wastes. State statutory provisions relating to oil and natural gas generally include requirements as to well spacing, waste prevention, production limitations, pollution prevention and cleanup, obtaining drilling and dredging permits and similar matters.
On July 6, 2001, the Ministry of State Revenues of Kazakhstan ("MSR") issued an Act of Audit to the Kazakhstan branch ("PKD Kazakhstan") of Parker Drilling Company International Limited ("PDCIL"), a wholly owned subsidiary of the Company, assessing additional taxes of approximately $29.0 million for the years 1998-2000. The assessment consisted primarily of adjustments in corporate income tax based on a determination by the Kazakhstan tax authorities that payments by Offshore Kazakhstan International Operating Company, ("OKIOC"), to PDCIL of $99.0 million, in reimbursement of costs for modifications to Rig 257, performed by PDCIL prior to the importation of the drilling rig into Kazakhstan, are income to PKD Kazakhstan, and therefore, taxable to PKD Kazakhstan. PKD Kazakhstan filed an Act of Non-Agreement that such reimbursements should not be taxable and requested that the Act of Audit be revised accordingly. In November 2001, the MSR rejected PKD Kazakhstan's Act of Non-Agreement, prompting PKD Kazakhstan to seek judicial review of the assessment. On December 28, 2001, the Astana City Court issued a judgment in favor of PKD Kazakhstan, finding that the reimbursements to PDCIL were not income to PKD Kazakhstan and not otherwise subject to tax based on the U.S.-Kazakhstan Tax Treaty. The MSR appealed the decision of the Astana City Court to the Civil Panel of the Supreme Court, which confirmed the decision of the Astana City Court that the reimbursements were not income to PKD Kazakhstan in March 2002. Although the court agreed with the MSR's position on certain minor issues, no additional taxes will be payable as a result of this assessment. The MSR has until the end of March 2003 to appeal the decision of the Civil Panel to the Supervisory Panel of the Supreme Court of Kazakhstan. It may also reopen the case thereafter if material new evidence is discovered. In addition, the Company has filed a petition with the U.S. Treasury Department for competent authority review, which is a tax treaty procedure to resolve disputes as to which country may tax income covered under the treaty. The U.S. Treasury Department has granted our petition and has initiated proceedings with the MSR which is ongoing.
The Company is a party to various other lawsuits and claims arising out of the ordinary course of business. Management, after review and consultation with legal counsel, considers that any liability resulting from these matters would not materially affect the results of operations, the financial position or the net cash flows of the Company.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 13 - Related Party Transactions
On February 27, 1995, the Company entered into a Split Dollar Life Insurance Agreement with Robert L. Parker and the Robert L. Parker and Catherine M. Parker Family Trust under Indenture dated 23rd day of July 1993 ("Trust") pursuant to which the Company agreed to provide life insurance protection for Mr. and Mrs. Robert L. Parker in the event of the death of Mr. and Mrs. Parker (the "Agreement"). The Agreement provided that the Trust would acquire and own a life insurance policy with face amount of $13.2 million and that the Company would pay the premiums subject to reimbursement by the Trust out of the proceeds of the policy, with interest to accrue on the premium payments made by the Company from and after January 1, 2000, at the one-year Treasury bill rate. The repayment of the premiums was secured by an Assignment of Life Insurance Policy as Collateral of same date as the Agreement. On October 14, 1996, the Agreement was amended to provide that interest accrual would be deferred until February 28, 2003, in consideration for the Company's termination of a separate life insurance policy on the life of Robert L. Parker. On April 19, 2000, the Agreement was amended and restated to replace the previous policy with two policies, one for $8.0 million on the life of Robert L. Parker and one for $7.7 million on the lives of both Mr. and Mrs. Robert L. Parker. Mr. Robert L. Parker Jr., the Company's CEO and son of Robert L. Parker will receive one third of the net proceeds of the policies.
As of December 31, 2002, the accrued amount of premiums paid by the Company on the policies and to be reimbursed by the Trust to the Company was $4.7 million. Due to the adoption of the Sarbanes-Oxley Act of 2002 ("SOX"), additional loans to executive officers and directors may be prohibited, although continuance of loans in existence as of July 30, 2002, are allowed; provided there is no modification to such loans. Because the advancement of additional annual premiums by the Company may be considered a prohibited loan under SOX, the Company elected to not advance the $0.6 million premium that was due in December 2002 pending further clarification from the SEC as to how the Company's obligation to advance these premiums under the Agreement can be honored without violating SOX.
Note 14 - Supplementary Information
At December 31, 2002, accrued liabilities included $8.5 million of accrued interest expense, $4.4 million of workers' compensation and health plan liabilities and $7.0 million of accrued payroll and payroll taxes. At December 31, 2001, accrued liabilities included $8.2 million of accrued interest expense, $5.3 million of workers' compensation and health plan liabilities and $10.4 million of accrued payroll and payroll taxes. Other long-term obligations included $4.7 million and $3.8 million of workers' compensation liabilities as of December 31, 2002 and 2001, respectively.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 15 - Selected Quarterly Financial Data (Unaudited)
(1) Gross profit is calculated by excluding net construction contract, operating income, general and administrative expense, reorganization expense and provision for reduction in carrying value of certain assets from operating income, as reported in the consolidated statement of operations.
(2) As a result of shares issued during the year, earnings per share for the year's four quarters, which are based on weighted average shares outstanding during each quarter, do not equal the annual earnings per share, which is based on the weighted average shares outstanding during the year.
(3) The first quarter includes recognition of $73.1 million goodwill impairment related to the jackup and platform rigs resulting from the adoption of SFAS No. 142. The impairment provision was included in the second quarter Form 10-Q, retroactive to January 1, 2002.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 15 - Selected Quarterly Financial Data (continued) (Unaudited)
(1) Gross profit is calculated by excluding general and administrative expense, reorganization expense and provision for reduction in carrying value of certain assets from operating income, as reported in the Consolidated Statement of Operations.
(2) As a result of shares issued during the year, earnings per share for the year's four quarters, which are based on weighted average shares outstanding during each quarter, do not equal the annual earnings per share, which is based on the weighted average shares outstanding during the year.
(3) The fourth quarter includes a $9.6 million deferred tax benefit resulting from a reversal of a valuation allowance. See Note 7.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 16 - Recent Accounting Pronouncements
In June 2001, the Financial Accounting Standard Board ("FASB") issued SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 is effective for fiscal years beginning after June 15, 2002 and establishes an accounting standard requiring the recording of the fair value of liabilities associated with the retirement of long-term assets in the period in which the liability is incurred. Accordingly, we adopted this standard in the first quarter of 2003. We do not expect this standard to have a material impact on our financial position or results of operations.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS No. 144 was effective January 1, 2002. This statement supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," and amends Accounting Principles Board Opinion ("APB") No. 30 for the accounting and reporting of discontinued operations, as it relates to long-lived assets. Our adoption of SFAS No. 144 did not affect our financial position or results of operations.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, No. 44, and No. 64, Amendment of FASB Statement No. 13, and Technical Corrections." SFAS No. 145 is effective for fiscal years beginning after May 15, 2002. We will adopt this standard in 2003 and do not expect it to have a significant effect on our results of operations or our financial position.
In July 2002, the FASB issued SFAS No. 146, "Accounting For Costs Associated with Exit or Disposal Activities." SFAS No. 146 is effective for exit or disposal activities initiated after December 31, 2002. We do not expect the adoption of this standard to have any impact on our financial position or results of operations.
On December 31, 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation-Transition and Disclosure-An Amendment of SFAS No. 123." The standard provides additional transition guidance for companies that elect to voluntarily adopt the accounting provisions of SFAS No. 123, "Accounting for Stock-Based Compensation." SFAS No. 148 does not change the provisions of SFAS No. 123 that permit entities to continue to apply the intrinsic value method of APB No. 25, "Accounting for Stock Issued to Employees." As we continue to follow APB No. 25, our accounting for stock-based compensation will not change as a result of SFAS No. 148. SFAS No. 148 does require certain new disclosures in both annual and interim financial statements. The required annual disclosures are effective immediately and have been included in Note 1 of the notes to the consolidated financial statements. The new interim disclosure provisions will be effective in the first quarter of 2003.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 16 - Recent Accounting Pronouncements (continued)
In November 2002, the FASB issued FASB Interpretation ("FIN") 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantee of Indebtedness of Others." FIN 45 requires that upon issuance of a guarantee, the guarantor must recognize a liability for the fair value of the obligation it assumes under that guarantee. FIN 45's provisions for initial recognition and measurement should be applied on a prospective basis to guarantees issued or modified after December 31, 2002. The guarantor's previous accounting for guarantees that were issued before the date of FIN 45's initial application may not be revised or restated to reflect the effect of the recognition and measurement provisions of the interpretation. The disclosure requirements are effective for financial statements of both interim and annual periods that end after December 15, 2002. The Company is not a guarantor under any significant guarantees and thus this interpretation is not expected to have a significant effect on the Company's financial position or results of operations.
On January 17, 2003, the FASB issued FIN 46, "Consolidation of Variable Interest Entities, An Interpretation of Accounting Research Bulletin No. 51." The primary objectives of FIN 46 are to provide guidance on how to identify entities for which control is achieved through means other than through voting rights (variable interest entities or ("VIE")) and how to determine when and which business enterprise should consolidate the VIE. This new model for consolidation applies to an entity in which either (1) the equity investors do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity's activities without receiving additional subordinated financial support from other parties. See Note 1 of the notes to the consolidated financial statements regarding our consolidation of AralParker, a company in which we own a 50 percent equity interest. We are consolidating this company because we exert significant influence and have a financial interest in the form of a loan, in addition to our equity interest.
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
This item is not applicable to the Company in that disclosure is required under Regulation S-X by the Securities and Exchange Commission only if the Company had changed independent auditors and, if it had, only under certain circumstances.
PART III
Item 10.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required by this item is shown in Item 4A "Executive Officers" and hereby incorporated by reference from the information appearing under the captions "Proposal One - Election of Directors" in the Company's definitive proxy statement for the Annual Meeting of Stockholders to be held April 30, 2003, to be filed with the Securities and Exchange Commission ("Commission") within 120 days of the end of the Company's year ended December 31, 2002.
PART III (continued)
Item 11.
Item 11. EXECUTIVE COMPENSATION
Notwithstanding the foregoing, in accordance with the instructions to Item 402 of Regulations S-K, the information contained in the Company's proxy statement under the sub-heading "Compensation Committee Report on Executive Compensation" and "Performance Graph" shall not be deemed to be filed as part of or incorporated by reference into this Form 10-K.
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND EQUITY COMPENSATION PLAN INFORMATION
The information required by this item is hereby incorporated by reference from the information appearing under the captions "Principal Stockholders and Security Ownership of Management" and "Equity Compensation Plan Information" in the Company's definitive proxy statement for the Annual Meeting of Stockholders to be held April 30, 2003, to be filed with the Commission within 120 days of the end of the Company's year ended December 31, 2002.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this item is hereby incorporated by reference to such information appearing under the caption "Other Information" and "Related Transactions" in the Company's definitive proxy statement for the Annual Meeting of Stockholders to be held April 30, 2003, to be filed with the Commission within 120 days of the end of the Company's year ended December 31, 2002.
Item 14.
Item 14. CONTROLS AND PROCEDURES
Within the 90-day period prior to the filing of this report, the Company carried out an evaluation, under the supervision and with the participation of the Company's management, including the chief executive officer and chief financial officer, of the effectiveness of the design and operation of the Company's disclosure controls and procedures (as defined in Rule 13a-14 (c) under the Securities Exchange Act of 1934). Based upon that evaluation, the chief executive officer and chief financial officer concluded that the Company's disclosure controls and procedures are effective in timely alerting them to material information relating to the Company (including its consolidated subsidiaries) required to be included in the Company's periodic SEC filings.
There have been no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.
PART IV
Item 15.
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
(1) Financial Statements of Parker Drilling Company and subsidiaries which are included in Part II, Item 8:
Page
Report of Independent Accountants 35
Consolidated Statement of Operations for the years ended December 31, 2002, 2001 and 2000 36
Consolidated Balance Sheet as of December 31, 2002 and 2001 37
Consolidated Statement of Cash Flows for the years ended December 31, 2002, 2001 and 2000 39
Consolidated Statement of Stockholders' Equity for the years ended December 31, 2002, 2001 and 2000 41
Notes to the Consolidated Financial Statements 42
PART IV (continued)
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K (continued)
Page ---- (2) Financial Statement Schedule: Schedule II - Valuation and qualifying accounts 87
(3) Exhibits:
Exhibit Number Description - -------------- -----------
3(a) - Corrected Restated Certificate of Incorporation of the Company, as amended on September 21, 1998 (incorporated by reference to Exhibit 3(c) to the Company's Annual Report on Form 10-K for the fiscal year ended August 31, 1998).
3(b) - Rights Agreement dated as of July 14, 1998 between the Company and Norwest Bank Minnesota, N.A., as rights agent (incorporated by reference to Form 8-A filed July 15, 1998.)
3(c) - Amendment No. 1 to the Rights Agreement dated as of September 22, 1998 between the Company and Norwest Bank Minnesota, N.A., as rights agent.
3(d) - By-laws of the Company, as amended January 31, 2003.
PART IV (continued)
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K (continued)
(3) Exhibits: (continued)
Exhibit Number Description - -------------- -----------
4(a) - Indenture dated as of March 11, 1998 among the Company, as issuer, certain Subsidiary Guarantors (as defined therein) and Chase Bank of Texas, National Association, as Trustee (incorporated by reference to Exhibit 4.5 to the Company's S-4 Registration Statement No. 333-49089 dated April 1, 1998).
4(b) - Indenture dated as of July 25, 1997, between the Company and Chase B Bank of Texas, National Association, f/k/a Texas Commerce Bank National Association, as Trustee, respecting 5 1/2% Convertible Subordinated Notes due 2004 (incorporated by reference to Exhibit 4.7 to the Company's S-3 Registration Statement No. 333-30711).
4(c) - Loan and Security Agreement dated as of October 22, 1999, between the Company and Bank of America, National Association, as agent for the lenders, regarding the $50.0 million revolving line of credit for loans and letters of credit due October 22, 2003 (incorporated by reference to Exhibit 4(c) to the Annual Report on Form 10-K for the year ended December 31, 2000).
4(d) - Indenture dated as of May 2, 2002 between the Company and JPMorgan Chase Bank, as Trustee, respecting the 10.125% Senior Notes due 2009 (incorporated by reference to Exhibit 4.1 to the Company's S-4 Registration Statement No. 333-91708).
PART IV (continued)
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K (continued)
(3) Exhibits: (continued)
Exhibit Number Description - -------------- -----------
10(a) - Amended and Restated Parker Drilling Company Stock Bonus Plan, effective as of January 1, 1999 (incorporated herein by reference to Exhibit 10(a) to the Company's Quarterly Report on Form 10-Q for the three months ended March 31, 1999).*
10(b) - 1994 Parker Drilling Company Deferred Compensation Plan (incorporated herein by reference to Exhibit 10(h) to Annual Report on Form 10-K for the year ended August 31, 1995).*
10(c) - 1994 Non-Employee Director Stock Option Plan (incorporated herein by reference to Exhibit 10(i) to Annual Report on Form 10-K for the year ended August 31, 1995).*
10(d) - 1994 Executive Stock Option Plan (incorporated herein by reference to Exhibit 10(j) to Annual Report on Form 10-K for the year ended August 31, 1995).*
10(e) - Third amended and restated 1997 Stock Plan effective July 24, 2002.*
10(f) - Waiver, Release and Confidentiality Agreement entered into between James W. Linn and Parker Drilling Company dated July 17, 2001 (incorporated by reference to Exhibit 10(f) to Annual Report on Form 10-K for the year ended December 31, 2001).*
10(g) - Form of Indemnification Agreement entered into between Parker Drilling Company and each director and executive officer of Parker Drilling Company, dated on or about October 15, 2002.*
PART IV (continued)
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K (continued)
(3) Exhibits: (continued)
10(h) - Form of Employment Agreement entered into between Parker Drilling Company and each executive officer of Parker Drilling Company, effective as of November 2, 2002.*
10(i) - Separation Agreement and Release entered into between James Davis and Parker Drilling Company effective September 26, 2002.*
21 - Subsidiaries of the Registrant.
23 - Consent of Independent Accountants.
99.1 - Section 906 Certification
99.2 - Section 906 Certification
* Management Contract, Compensatory Plan or Agreement
(b) Reports on Form 8-K: None.
PARKER DRILLING COMPANY AND SUBSIDIARIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS (Dollars in Thousands)
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PARKER DRILLING COMPANY
By /s/ Robert L. Parker Jr. Date: March 17, 2003 ------------------------------ Robert L. Parker Jr. President and Chief Executive Officer and Director
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
PARKER DRILLING COMPANY OFFICER CERTIFICATION
I, Robert L. Parker Jr., certify that:
1. I have reviewed this annual report on Form 10-K of Parker Drilling Company ("the Company");
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this annual report;
4. The Company's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the Company and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the Company's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The Company's other certifying officer and I have disclosed, based on our most recent evaluation, to the Company's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and
6. The Company's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 10, 2003
/s/ Robert L. Parker Jr. ----------------------------- Robert L. Parker Jr. President and Chief Executive Officer and Director
PARKER DRILLING COMPANY OFFICER CERTIFICATION
I, James W. Whalen, certify that:
1. I have reviewed this annual report on Form 10-K of Parker Drilling Company ("the Company");
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this annual report;
4. The Company's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the Company and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;
b) evaluated the effectiveness of the Company's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;
5. The Company's other certifying officer and I have disclosed, based on our most recent evaluation, to the Company's auditors and the audit committee of Company's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the Company's ability to record, process, summarize and report financial data and have identified for the Company's auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the Company's internal controls; and
6. The Company's other certifying officer and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: March 10, 2003
/s/ James W. Whalen ----------------------------- James W. Whalen Senior Vice President and Chief Financial Officer
INDEX TO EXHIBITS