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 terms “Company,” “we,” “us” and “our” refer to Parker Drilling Company together with its subsidiaries and “Parker Drilling” refers solely to the parent, Parker Drilling Company. We make available free of charge on our website at www.parkerdrilling.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish to, the Securities and Exchange Commission (“SEC”). Additionally, these reports are available on an Internet website maintained by the SEC. The address of that site is http://www.sec.gov.
Our Company
We are a leading worldwide provider of contract drilling and drilling-related services. Since beginning operations in 1934, we have operated in 51 foreign countries and the United States, making us among the most geographically diverse drilling contractors in the world. Due to our extensive experience and expertise in drilling difficult wells and operating in remote, harsh and ecologically sensitive areas, operators look to us to provide oil and gas exploration and development drilling around the world.
Our revenues are derived from three segments: international drilling, U.S. drilling and rental tools.
•
Our international land drilling operations are focused primarily in the Commonwealth of Independent States (former Soviet Union referred to herein as “CIS”), the Asia Pacific region and Latin America including Mexico. Our international offshore drilling operations are focused in the transition zones, which are coastal waters that include lakes, bays, rivers and marshes of Nigeria and Mexico, and the shallow waters of the Caspian Sea.
•
Our U.S. drilling operations consist of barge drilling in the transition zones of the U.S. Gulf of Mexico.
•
Through our subsidiary Quail Tools, we provide premium rental tools that are used for land and offshore oil and gas drilling and workover activities, serving major and independent oil and gas exploration and production companies operating primarily in the Gulf of Mexico and other major U.S. producing markets.
We also manage and provide labor resources for drilling rigs owned by third parties, which are generally oil companies that prefer to own rig equipment but choose to rely upon our technical expertise or labor resources to operate rigs.
Our Rig Fleet
The diversity of our rig fleet, both in terms of geographic location and asset class, enables us to provide a broad range of services to oil and gas operators worldwide. As of December 31, 2004, our fleet of rigs available for service consisted of:
•
eight land rigs in the CIS, two of which are owned by AralParker, a joint venture in which we own a 50 percent interest, which include premium and specialized deep drilling rigs capable of drilling to depths from 10,000 feet to in excess of 25,000 feet;
ITEM 1. BUSINESS (continued)
Our Rig Fleet (continued)
•
10 land rigs in the Asia Pacific region and two land rigs in Africa;
•
14 land rigs in the Latin America region which includes seven rigs in Mexico, three rigs in Colombia and four rigs in Peru;
•
two barge drilling rigs in the transition zone waters of Nigeria;
•
one barge drilling rig in the inland waters of Mexico;
•
the world’s largest arctic-class barge rig in the Caspian Sea; and
•
19 barge drilling and workover rigs in the transition zones of the U.S. Gulf of Mexico, consisting of nine deep drilling barge rigs, four intermediate drilling barge rigs and six workover and shallow drilling barge rigs. Included in the deep drilling barge rigs are barge rig 72 which relocated to the U.S. Gulf of Mexico market from Nigeria and one barge rig which has recently been upgraded to provide ultra-deep drilling capabilities.
Our Rental Tools Business
Quail Tools, our rental tools business based in New Iberia, Louisiana, is a provider of premium rental tools used for land and offshore oil and gas drilling and workover activities. Quail Tools offers a full line of drill pipe, drill collars, tubing, high and low-pressure blowout preventers, choke manifolds, casing scrapers, and junk and cement mills. Approximately two-thirds of Quail Tools’ equipment is utilized in offshore and coastal water operations. Founded in 1978, Quail Tools was acquired by Parker Drilling in 1996. Quail Tools’ base of operations is an 88,000 square foot facility on a 15-acre complex in New Iberia, Louisiana. Since we acquired Quail Tools, we have expanded operations with the addition of a 48,000 square foot facility on an 11-acre complex in Victoria, Texas, an 8,000 square foot facility on nearly 10-acres in Odessa, Texas and a 19,000 square foot facility on just over 6-acres in Evanston, Wyoming. Quail Tools’ principal customers are major and independent oil and gas exploration and production companies operating in the Gulf of Mexico and other major U.S. producing markets. In 2004, Quail Tools began providing rental tools internationally in Mexico and Sakhalin Island, Russia.
Our Market Areas
Our core drilling operations are subject to different market factors and industry trends depending on the location. International markets differ from the U.S. market in terms of competition, nature of customers, equipment and experience requirements. The contract drilling industry is a competitive and cyclical business characterized by high capital requirements and difficulty in finding and retaining qualified field personnel. However, participants in this industry typically generate substantial cash flows and economic returns during cyclical peaks.
International Markets. The majority of the international drilling markets in which we operate have one or more of the following characteristics: (i) a small number of competitors; (ii) customers who typically are major, large independent or national oil companies and integrated service providers; (iii) drilling programs in remote locations with little infrastructure and/or harsh environments requiring specialized drilling equipment with a large inventory of spare parts and other ancillary equipment; and (iv) difficult (i.e., high pressure, deep, hazardous or geologically challenging) wells requiring specialized drilling equipment and considerable experience to drill. Due to the long lead time in the development and implementation of international drilling projects, international markets are attractive to us because they usually allow us to secure longer-term contracts and higher dayrates when compared with drilling operations in the U.S. Gulf of Mexico.
U.S. Gulf of Mexico. The drilling industry in the U.S. Gulf of Mexico is highly cyclical and is typically driven by general economic activity and changes in actual or anticipated oil and gas prices.
ITEM 1. BUSINESS (continued)
Our Market Areas (continued)
Utilization and dayrates typically move in conjunction with oil and gas prices. The increase in gas prices since 2003 has resulted in increased exploration and development drilling activity in the U.S. Gulf of Mexico. In addition, the United States government has provided incentives for operators to develop deeper gas reserves. We believe that these incentives will continue to benefit our barge rigs that are capable of drilling deep gas wells, as well as our rental tools business.
Our Strategy
Our strategy is to maintain our position as a leading worldwide provider of contract drilling, drilling-related services and rental tools and to position our company operationally and financially for long-term and consistent profitability. Key elements in implementing our strategy include:
Significantly Reducing Our Debt and Enhancing Our Liquidity. One of our primary goals has been to reduce debt from the $589.9 million outstanding at December 31, 2002 by approximately $200 million. Since establishing this goal, we have reduced total long-term debt by $134.0 million to $455.9 million as of March 1, 2005. We accomplished this reduction by utilizing proceeds from the sale of assets, insurance proceeds received for damaged rigs and cash generated from operations. We intend to continue our debt reduction program in 2005 through proceeds from the sale of additional assets and cash generated from operations.
Increasing the Utilization of Our Barge and Land Rigs. One of our strategic objectives is the increased utilization of our barge and land rigs. Rig utilization has already increased from 40 percent in 2003 to 74 percent as of March 1, 2005 due partly to improved market conditions, restructuring of our various operating regions, including revisions to our compensation structure to provide incentives directly related to profitability.
Controlling Our Costs and Minimizing Our Capital Expenditures. We continue to be vigilant in our efforts to conserve cash by controlling general and administrative expenses and limiting capital expenditures. We will continue to make adjustments as appropriate for our level of operations. Our capital expenditure program calls for limiting expenditures to scheduled ongoing maintenance projects, expenditures required under our preventive maintenance program and for capital projects that we believe have the potential to yield an attractive rate of return and support our goal of increased utilization. Our capital expenditures were $47.3 million and $35.0 million in 2004 and 2003, respectively, and are budgeted for approximately $60.0 million in 2005.
Pursuing Strategic Growth Opportunities. We continue to pursue selective strategic growth opportunities in our drilling and rental tools operations that will not only provide an attractive rate of return but will also promote consistent profitability.
Our Competitive Strengths
Our competitive strengths have historically contributed to our operating performance and we believe the following strengths should enable us to capitalize on future opportunities:
Geographically Diverse Operations and Assets. We currently operate in 15 countries and have operated in 51 foreign countries and the United States since our founding in 1934, making us among the most geographically diverse drilling contractors in the world. Our international drilling revenues constituted approximately 59 percent of our total revenues in the twelve months ended December 31, 2004. Our core international land drilling operations focus primarily on the CIS, where we have eight land rigs, the Asia Pacific region, where we have 10 land rigs, including seven helicopter transportable rigs, and Mexico, where we have recently moved seven land rigs. Our international offshore drilling operations focus on the Caspian Sea, where we own and operate the world’s largest arctic-class barge rig, Mexico, where we
ITEM 1. BUSINESS (continued)
Our Competitive Strengths (continued)
recently initiated barge operations with one barge rig, and Nigeria, where we have two barge rigs. We also have 19 drilling and workover barges in the transition zones of the U.S. Gulf of Mexico.
Significant Experience in Our Core International Markets. Our reputation and experience have led operators to look to us as a pioneer for the exploration of oil and gas in new frontiers around the world as well as to manage environmentally and operationally challenging and multi-rig projects. We have been one of the pioneers in arctic drilling services and have 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 us in marketing our services to operators in international markets with similar environmental considerations, such as the Caspian Sea, Western Siberia and Sakhalin Island. Our expertise in drilling deep, difficult wells, in addition to our arctic experience, helped us become the first western drilling contractor to enter Russia, in 1991, and Kazakhstan, which is now one of our most active markets, in 1993. We were the first western contract driller to enter China, in 1980, and we continue to provide drilling services to the Asia Pacific market. In 2004, we began operating eight rigs in Mexico, which we believe will be an important market for the foreseeable future.
Outstanding Safety Record. We have an outstanding safety record in the operation of our barge and land rigs. Our safety record, as evidenced by our low total recordable incidence rate, has been better than the industry average in each of the last eight years. This has contributed to our success in obtaining drilling contracts, as well as contracts to manage and provide labor resources to drilling rigs owned by third parties.
Rental Tools Business. Quail Tools, our rental tools business headquartered in New Iberia, Louisiana, is a provider of premium rental tools used for land and offshore oil and gas drilling and workover activities. Quail Tools’ principal customers include both major and independent oil and gas exploration and production companies. Quail Tools has facilities in New Iberia, Louisiana; Victoria, Texas; Odessa, Texas and Evanston, Wyoming. Quail Tools generated gross margins of approximately 58 percent in 2004 and 2003.
Strong Market Position in the Transition Zones of the U.S. Gulf of Mexico. We are one of only two drilling companies with a significant presence in the transition zones of the U.S. Gulf of Mexico. This area historically has been the world’s largest market for shallow-water barge drilling, and in recent months barge utilization and dayrates have been increasing due to strong natural gas prices. We currently have 19 drilling and workover barges, including the recent addition of barge rig 72 from Nigeria, and are positioned to take advantage of recent drilling opportunities in this market.
Strong and Experienced Senior Management Team. Our management team has extensive experience in the contract drilling industry. Our chairman, Robert L. Parker, joined Parker Drilling in 1948 and served as our chief executive officer from 1969 to 1991. Robert L. Parker Jr. joined Parker Drilling in 1973 and has served as our president and chief executive officer since 1991. Under the leadership of Mr. Parker and Mr. Parker Jr., we have developed a reputation as a leading worldwide provider of contract drilling services. James W. Whalen joined Parker Drilling in October 2002 as senior vice president and chief financial officer. Prior to joining Parker Drilling, Mr. Whalen served as chief commercial officer for Coral Energy and as chief financial officer for Tejas Gas Corporation. He has also held several executive positions at Coastal Corporation including senior vice president, finance. Mr. Whalen has considerable experience with mergers, acquisitions, and divestitures in the oil and gas industry. David C. Mannon recently joined our senior management team as senior vice president and chief operating officer. Mr. Mannon has served in various managerial positions, culminating with his appointment as president and chief executive officer for Triton Engineering Services Company, a subsidiary of Noble Corporation. He brings a broad range of over 24 years of experience to our drilling operations which will enhance our ability to achieve our goals of increased utilization and profitable growth.
ITEM 1. BUSINESS (continued)
DRILLING OPERATIONS
CIS
Eight of our land rigs are currently located in the oil and gas producing regions of the CIS. We were the first western drilling contractor to enter this market in 1991, and it continues to be a major area of operations. We currently have five rigs located in Kazakhstan (two operate under the AralParker joint venture), one rig in Russia and two rigs in Turkmenistan. We are currently negotiating to move a third rig to Turkmenistan, which is currently located in Russia. Drilling operations under this new contract are expected to commence in the third quarter of 2005.
Asia Pacific/Africa
As of December 31, 2004, we have 10 land rigs located in the Asia Pacific region and two land rigs in Africa. Included are seven helicopter transportable rigs which facilitate exploration in areas of difficult access, such as the mountainside and jungle terrains of Indonesia and Papua New Guinea. We are currently negotiating to sell one of the land rigs in Africa and during the second quarter of 2005 we expect this transaction to close.
International Barge Drilling
Our international barge drilling operations are located in the transition zones of Nigeria and Mexico, and the shallow water of the Caspian Sea. Barge rigs are utilized in these areas because of their ability to carry drilling equipment on board and navigate in shallow waters where conventional jackup rigs are unable to operate.
Since 1996, we have been a major provider of barge rigs in Nigeria and currently have two of the six rigs in this market. In 2003, Nigeria experienced significant community unrest which resulted in two of our four barge rigs being evacuated. As a result of the community unrest, barge rig 74 received substantial damage and was removed from our marketable rig count and one other barge rig was moved to the U.S. Gulf of Mexico. We also own and operate the world’s largest arctic-class barge rig in the Caspian Sea. This barge rig completed its initial four-year contract in November 2003 and was stacked until late December 2004 when it began drilling under a new two-well contract with options for an additional four wells. In May 2004, barge rig 53 was transferred from the U.S. Gulf of Mexico region to Mexico to begin operating under a two-year contract with Petroleos Mexicanos S.A. (“Pemex”).
U.S. Barge Drilling and Workover
The U.S. market for our barge drilling rigs is the transition zones of the U.S. Gulf of Mexico, primarily in Louisiana and, to a lesser extent, Alabama, Mississippi and Texas. This area historically has been the world’s largest market for shallow-water barge drilling. With 19 drilling and workover barges, we are one of two companies with a significant presence in this market. We recently moved barge rig 72 from Nigeria to the U.S. Gulf of Mexico to take advantage of this active market. We have also recently upgraded barge rig 76 to provide ultra-deep drilling services to our customers, for which we are primarily receiving a significantly enhanced dayrate.
Project Management
We are active in managing and providing labor resources for drilling rigs owned by third parties. In Russia, we mobilized a new rig to Sakhalin Island which we designed, constructed and sold to Exxon Neftegas Limited (“ENL”). Drilling operations under a five-year operations and maintenance contract with this customer began in June 2003. We also recently signed a second operations and maintenance contract with ENL to provide labor services on their offshore platform off the coast of Sakhalin Island, which is expected to begin drilling during the third quarter of 2005. As of December 31, 2004, we were
ITEM 1. BUSINESS (continued)
Project Management (continued)
actively managing third party-owned drilling rigs in Russia, Kazakhstan, Papua New Guinea, Kuwait and China.
Competition
The contract drilling industry is a competitive, cyclical business characterized by high capital requirements and challenges in securing and retaining qualified field personnel.
In the U.S. Gulf of Mexico barge drilling market, we compete with one major contractor. In international land markets, we compete with a number of international drilling contractors as well as smaller local contractors. 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 than in domestic markets. In international land and offshore markets, our experience in operating in challenging environments and our customer alliances have both been factors in securing contracts for remote drilling projects. We believe that the market for drilling contracts, both land and offshore, will continue to be highly competitive for the foreseeable future. Certain competitors may have greater financial resources than we do, which may better enable them to withstand industry downturns, compete more effectively on the basis of price, build new rigs or acquire existing rigs.
Our management believes that Quail Tools is one of the leading rental tools companies in the offshore Gulf of Mexico and other major U.S. producing markets. Nonetheless, some of Quail Tools’ competitors are substantially larger and have greater financial resources than Quail Tools.
Customers
We believe that we have developed a reputation for providing efficient, safe, environmentally conscious and innovative drilling services. An increasing trend indicates that a number of our customers have been seeking to establish exploration or development drilling programs based on partnering relationships or alliances with a limited number of preferred drilling contractors. Such relationships or alliances can result in longer-term work and higher efficiencies that increase profitability for drilling contractors at a lower overall well cost for oil and gas operators. We are currently a preferred contractor for operators in certain U.S. and international locations which our management believes is a result of our quality of equipment, personnel, safety program, service and experience.
Our drilling and rental tools customer base consists of major, independent and national-owned oil and gas companies and integrated service providers. In 2004, Tengizchevroil (“TCO”), a consortium led by ChevronTexaco accounted for approximately 13 percent of our total revenues, including discontinued operations. Our ten most significant customers collectively accounted for approximately 57 percent of our total revenues in 2004, including discontinued operations.
Contracts
Most drilling contracts are awarded based on competitive bidding. The rates specified in drilling contracts are generally on a dayrate basis, and vary depending upon the type of rig employed, equipment and services supplied, geographic location, term of the contract, competitive conditions and other variables. Our contracts generally provide for a basic dayrate during drilling operations, with lower rates or no payment for periods of equipment breakdown, adverse weather or other conditions, which may be beyond our reasonable control. When a rig mobilizes to or demobilizes from an operating area, a contract may provide for different dayrates, specified fixed payments or no payment during the mobilization or demobilization. Contracts to employ our drilling rigs have a term based on a specified period of time or the time required to drill a specified well or number of wells. The contract term in some instances may be
ITEM 1. BUSINESS (continued)
Contracts (continued)
extended by the customer exercising options for the drilling of additional wells or for an additional term, or by exercising a right of first refusal. Most drilling contracts permit the customer to terminate the contract at the customer’s option without paying a termination fee. Due to various reasons, including a change in market conditions, our customers may seek renegotiation of drilling contracts to reduce their obligations or may seek to suspend or terminate their contracts. Some contracts may be terminated by the customer under various circumstances such as the loss or destruction of the drilling unit or the suspension of drilling operations for a specified period of time as a result of a breakdown of major equipment.
We generally receive a lump sum fee to move our equipment to the drilling site, which in most cases approximates the cost incurred by us. 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, longer-term programs.
Rental tools contracts are typically on a dayrate basis with rates based on type of equipment, investment and competition.
Insurance and Indemnification
In our drilling contracts, we generally seek to obtain indemnification from our customers for some of the risks related to our drilling services. To the extent that we are unable to transfer such risks to customers by contract or indemnification agreements, we generally seek protection through insurance. To address the hazards inherent in our business, we maintain insurance coverage that includes physical damage coverage, third party general liability coverage, employer’s liability, environmental and pollution coverage and other coverage. We believe that our insurance coverage is customary for the industry and adequate for our business. However, there are risks that such insurance will not adequately protect us against or not be available to cover all the liability from all of the consequences and hazards we may encounter in our drilling operations.
Employees
The following table sets forth the composition of our employees.
Environmental Considerations
Our operations are subject to numerous federal, state, local and foreign laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental agencies, such as the U.S. Environmental Protection Agency (“EPA”), issue regulations to implement and enforce such laws, which often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties or may result in injunctive relief for failure to comply. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the 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
ITEM 1. BUSINESS (continued)
Environmental Considerations (continued)
drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require remedial action to prevent pollution from former operations, and impose substantial liabilities for pollution resulting from our operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly compliance could adversely affect our operations and financial position, as well as those of similarly situated entities operating in the Gulf Coast market. While our management believes that we are in substantial compliance with current applicable environmental laws and regulations, there is no assurance that compliance can be maintained in the future.
The drilling of oil and gas wells is subject to various federal, state, local and foreign laws, rules and regulations. As an owner or operator of both onshore and offshore facilities, including mobile offshore drilling rigs in or near waters of the United States, we may be liable for the costs of removal and damages arising out of a pollution incident to the extent set forth in the Federal Water Pollution Control Act, as amended by the Oil Pollution Act of 1990 (“OPA”), the 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 may be amended from time to time. In addition, we may also be subject to applicable state law and other civil claims arising out of any such incident.
The OPA and regulations promulgated pursuant thereto impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills. A “responsible party” includes the owner or operator of a vessel, pipeline or onshore facility, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability of oil removal costs and a variety of public and private damages to each responsible party.
The liability for a mobile offshore drilling rig is determined by whether the unit is functioning as a vessel or is in place and functioning as an offshore facility. If operating as a vessel, liability limits of $600 per gross ton or $0.5 million, whichever is greater, apply. If functioning as an offshore facility, the mobile offshore drilling rig is considered a “tank vessel” for spills of oil on or above the water surface, with liability limits of $1,200 per gross ton or $10.0 million, whichever is greater. To the extent damages and removal costs exceed this amount, the mobile offshore drilling rig will be treated as an offshore facility and the offshore lessee will be responsible up to higher liability limits for all removal costs plus $75.0 million. The party must reimburse all removal costs actually incurred by a governmental entity for actual or threatened oil discharges associated with any Outer Continental Shelf facilities, without regard to the limits described above. A party also cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply.
Few defenses exist to the liability imposed by the OPA. The OPA also imposes ongoing requirements on a responsible party, including proof of financial responsibility for offshore facilities and vessels in excess of 300 gross tons (to cover at least some costs in a potential spill) and preparation of an oil spill contingency plan for offshore facilities and vessels. The OPA requires owners and operators of offshore facilities that have a worst case oil spill potential of more than 1,000 barrels to demonstrate financial responsibility in amounts ranging from $10.0 million in specified state waters to $35.0 million in federal Outer Continental Shelf waters, with higher amounts, up to $150.0 million, in certain limited circumstances where the U.S. Minerals Management Service believes such a level is justified by the risks posed by the quantity or quality of oil that is handled by the facility. For “tank vessels,” as our offshore drilling rigs are typically classified, the OPA requires owners and operators to demonstrate financial responsibility in the amount of their largest vessel’s liability limit, as those limits are described in the
ITEM 1. BUSINESS (continued)
Environmental Considerations (continued)
preceding paragraph. A failure to comply with ongoing requirements or inadequate cooperation in a spill may even subject a responsible party to civil or criminal enforcement actions.
In addition, the OCSLA authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the Outer Continental Shelf. Specific design and operational standards may apply to Outer Continental Shelf vessels, rigs, platforms, vehicles and structures. Violations of environmentally related lease conditions or regulations issued pursuant to the OCSLA can result in substantial civil and criminal penalties as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities can result from either governmental or citizen prosecution.
All of our operating U.S. barge drilling rigs have zero-discharge capabilities as required by law. In addition, in recognition of environmental concerns regarding dredging of inland waters and permitting requirements, we conduct negligible dredging operations, with approximately two-thirds of our offshore drilling contracts involving directional drilling, which minimizes the need for dredging. However, the existence of such laws and regulations has had and will continue to have a restrictive effect on us and our 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, our operations may involve the use or handling of other materials that may be classified as hazardous substances. CERCLA assigns strict liability to each responsible party for all response and remediation costs, as well as natural resource damages. Few defenses exist to the liability imposed by CERCLA. We have received an information request under CERCLA designating a subsidiary of Parker Drilling as a potentially responsible party with respect to a Superfund site in Freeport, Texas. We are currently evaluating our relationship to the site and have not yet estimated the amount or impact on our operations, financial position or cash flows of any costs related to the site.
RCRA generally does not regulate most wastes generated by the exploration and production of oil and gas. RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters, and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy.” However, these wastes may be regulated by EPA or state agencies as solid waste. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes, and waste oils, may be regulated as hazardous waste. Although the costs of managing solid and hazardous wastes may be significant, we do not expect to experience more burdensome costs than similarly situated companies involved in drilling operations in the Gulf Coast market.
The drilling industry is dependent on the demand for services from the oil and gas exploration and development industry, and accordingly, is affected by changes in laws relating to the energy business. Our business is affected generally by political developments and by federal, state, local and foreign regulations that may relate directly to the oil and gas industry. The adoption of laws and regulations, both U.S. and foreign, that curtail exploration and development drilling for oil and gas for economic, environmental and other policy reasons may adversely affect our operations by limiting available drilling opportunities.
FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS AND GEOGRAPHIC AREAS
We operate in three segments, U.S. drilling operations, international drilling operations and rental tools. Information about our business segments and operations by geographic areas for the years ended December 31, 2004, 2003 and 2002 is set forth in Note 11 in the notes to the consolidated financial statements.
ITEM 2.
ITEM 2.
PROPERTIES
We lease office space in Houston for our corporate headquarters. Additionally, we own and lease office space and operating facilities in various locations, but only to the extent necessary for administrative and operational support functions. We own a ten-story building in Tulsa, Oklahoma, our previous corporate headquarters, which is vacant and classified in assets held for sale. Our bank accounts, accounts receivable, rig materials and supplies, rental tools equipment of Quail Tools, L.P., and the stock of substantially all of our domestic subsidiaries are pledged as collateral to the banks under the 2004 Credit Agreement described in the “Liquidity and Capital Resources” section.
Land Rigs
The following table shows, as of December 31, 2004, the locations and drilling depth ratings of our 34 land rigs available for service. Twenty-two of these rigs were under contract and the remainder were available for contract as of December 31, 2004.
(1)
Two rigs were removed from the marketable rig count as of December 31, 2004.
(2)
Two rigs are owned by AralParker.
(3)
Latin America includes rigs located in South America and Mexico. Two rigs in Bolivia were removed from the marketable rig count as of December 31, 2004.
(4)
We have entered into an agreement to sell a land rig in Nigeria and have received partial payment. We expect to consummate the sale during the second quarter of 2005.
Barge Rigs
The following table shows our four international deep drilling barges as of December 31, 2004. All of these rigs were under contract at December 31, 2004.
(1)
Barge rig 74 was removed from the marketable rig count as of December 31, 2004. The rig sustained substantial damage due to community unrest in Nigeria. Barge rig 72 was transferred to the U.S. Gulf of Mexico market as of December 31, 2004.
ITEM 2.
PROPERTIES (continued)
Barge Rigs (continued)
The following table shows our 19 deep, intermediate, and workover and shallow drilling barge rigs located in the U.S. Gulf of Mexico. Fifteen of these barge rigs were under contract and the remainder were available for contract as of December 31, 2004.
(1)
At December 31, 2004, barge rig 72 relocated from Nigeria to the U.S. Gulf of Mexico.
(2)
Two rigs were removed from the marketable rig count as of December 31, 2004. One rig was reclassified from intermediate to workover and shallow drilling in 2004.
(3)
Workover rig.
ITEM 2.
PROPERTIES (continued)
The following table presents our utilization rates and rigs available for service for the years ended December 31, 2004 and 2003.
(1)
The number of rigs available for service is determined by calculating the number of days each rig was in our fleet and was under contract or available for contract. For example, a rig under contract or available for contract for six months of a year is 0.5 rigs available for service for such year. Rigs available for service exclude rigs classified as assets held for sale. Our method of computation of rigs available for service may or may not be comparable to other similarly titled measures of other companies.
(2)
Rig utilization rates are based on a weighted average basis assuming 365 days availability for all rigs available for service. Rigs acquired or disposed of are treated as added to or removed from the rig fleet as of the date of acquisition or disposal. Rigs that are in operation or fully or partially staffed and on a revenue-producing standby status are considered to be utilized. Rigs under contract that generate revenues during moves between locations or during mobilization or demobilization are also considered to be utilized. Our method of computation of rig utilization may or may not be comparable to other similarly titled measures of other companies.
As of December 31, 2004, we removed seven idle rigs from our marketable rig count. The following table reflects, on a pro forma basis, our rig utilization for 2004 as if the seven rigs had been removed on January 1, 2004.
ITEM 2.
PROPERTIES (continued)
Rig Related to Discontinued Operations
As of December 31, 2004, we had one rig in discontinued operations, which was jackup rig 25, a Le Tourneau Class 150-44 (IC). The rig was sold on January 3, 2005.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
We are a party to certain legal proceedings that have resulted from the ordinary conduct of our business. In the opinion of our management, none of these proceedings is expected to have a material adverse effect on our financial position, results of operations or cash flows.
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 2004.
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, 81, chairman, joined Parker Drilling in 1948 and was elected vice president in 1950. He was elected president in 1954 and chief executive officer and chairman in 1969. Since 1991, he has held only the position of chairman.
(2)
Robert L. Parker Jr., 56, president and chief executive officer, joined Parker Drilling in 1973 as a contract representative and was named manager of U.S. operations later in 1973. He was elected a vice president in 1973, executive vice president in 1976 and was named president and chief operating officer in October 1977. In December 1991, he was named chief executive officer. He has been a director since 1973.
(3)
David C. Mannon, 47, senior vice president and chief operating officer, joined Parker Drilling in December 2004. From 1988 through 2003, Mr. Mannon held various positions, including president and chief executive officer of Triton Engineering Services Company, a subsidiary of Noble Corporation. From 1980 through 1988, Mr. Mannon served SEDCO-FOREX, formerly SEDCO as a drilling engineer.
(4)
James W. Whalen, 63, senior vice president and chief financial officer, joined Parker Drilling 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)
W. Kirk Brassfield, 49, vice president, controller and principal accounting officer, joined Parker Drilling in March 1998 as controller and principal accounting officer. From 1991 through March 1998, Mr. Brassfield served in various positions, including subsidiary controller and director of financial planning of MAPCO Inc., a diversified energy company. From 1979 through 1991, Mr. Brassfield served at the public accounting firm, KPMG.
(6)
Denis J. Graham, 55, vice president of engineering, joined Parker Drilling in 2000. Mr. Graham was previously the senior vice president of technical services for Diamond Offshore Inc., an international offshore drilling contractor. His experience with Diamond Offshore ranged from 1978 through 1999 in the areas of offshore drilling rig design, new construction, conversions, marine operations, maintenance and regulatory compliance.
ITEM 4A.
EXECUTIVE OFFICERS (continued)
(7)
Ronald C. Potter, 51, vice president and general counsel, re-joined Parker Drilling in June 2003. From 2001 through May 2003, Mr. Potter was our outside legal counsel as a shareholder of Conner & Winters, P.C. in Tulsa, Oklahoma. From 1980 to 2001, he served Parker Drilling in various positions, most recently as chief legal counsel and corporate secretary.
Other Parker Drilling Company Officer
(8)
David W. Tucker, 49, treasurer and director of investor relations, joined Parker Drilling in 1978 as a financial analyst and served in various financial and accounting positions before being named chief financial officer of the Company’s wholly-owned subsidiary, Hercules Offshore Corporation, in February 1998. Mr. Tucker was named treasurer in 1999 and assumed the responsibilities of director of investor relations in 2002.
PART II
ITEM 5.
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
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, 2004, there were 2,525 holders of record of Parker Drilling common stock. The following table sets forth the high and low closing prices per share of Parker Drilling’s common stock, as reported on the New York Stock Exchange composite tape, for the periods indicated:
Substantially all of our stockholders maintain their shares in “street name” accounts and are not individually, stockholders of record. As of January 31, 2005, our common stock was held by 2,511 holders of record and an estimated 23,500 beneficial owners.
No dividends have been paid on common stock since February 1987. Restrictions contained in Parker Drilling’s existing credit agreement and the indentures for the Senior Notes restrict the payment of dividends. The Company has no present intention to pay dividends on its common stock in the foreseeable future because of the restrictions noted.
The information under the caption “Equity Compensation Plan Information” in Parker Drilling’s definitive Proxy Statement for the Annual Meeting of Shareholders to be held on April 27, 2005, to be filed with the SEC (the “2005 Proxy Statement”), is incorporated herein by reference.
The Company purchased 89,725 shares at a price per share of $4.20 on March 4, 2004 and 1,587 shares at a price of $3.07 from executives resulting from the vesting of a portion of a restricted stock grant issued in July 2003 and August 2002, respectively. Upon vesting of the restricted shares a tax withholding obligation to the Company from the executive was satisfied by delivering back to the Company some of the shares on which the restrictions had lapsed.
ITEM 6.
ITEM 6.
SELECTED FINANCIAL DATA
The following table presents selected historical consolidated financial data derived from the audited financial statements of Parker Drilling for each of the four years in the period ended December 31, 2004, and from our unaudited financial statements for the year ended December 31, 2000. The following financial data should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes appearing elsewhere in this Form 10-K.
(1)
In June 2003, the Company recognized a $53.8 million impairment charge related to its plan to sell its U.S. Gulf of Mexico offshore assets. See Note 2 in the notes to the consolidated financial statements.
(2)
In 2002, the Company adopted Statement Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets” and recorded a goodwill impairment as a cumulative effect of a change in accounting principle. See Note 3 in the notes to the consolidated financial statements.
ITEM 7.
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
Outlook and Overview
The financial results for 2004 reflect the improvement in market conditions that we reported in the first quarter of 2004. These market conditions are to a great extent due to the continuation of strong demand combined with uncertainty over disruptions in supply of oil and gas, which have fostered record high oil and gas prices over the past year. We have experienced substantial increases in utilization and dayrates in most of our drilling segments during 2004 and anticipate that these market conditions will continue during 2005. We expect our rental tools business to continue to benefit from these market conditions during 2005.
Although we anticipated in our 2003 annual report that we would be reporting positive earnings by the fourth quarter of 2004, the improvements in utilization and dayrates have been more than offset by non-routine matters that have delayed our return to profitability. We are not currently aware of any additional matters of this nature that would adversely affect our operating and financial results in a material way for the foreseeable future and we expect to be profitable in 2005.
Our positive outlook on operations is due in certain respects to the continuation of projects that either commenced or were committed to during the latter part of 2004. Our eight rig operation in Mexico reached 100 percent operating status late in the third quarter of 2004 and should continue at this level for the next two years, with options for extensions beyond that period. We also began receiving dayrates under our new contract for barge rig 257 in the Caspian Sea during the last few days of 2004. This contract is a two-well contract with options for an additional four wells. In Turkmenistan we are negotiating to move a third rig into the country, which had previously operated in Russia. In addition, we have entered into a contract to provide operations and maintenance support to a second offshore rig in Sakhalin Island, Russia. These last two operations are significant contributions to our existing operations in the Commonwealth of Independent States (“CIS”) which are anchored by our drilling operations in Kazakhstan and have the potential for additional growth in the near future. In Nigeria, two barge rigs have returned to work under long-term contracts. Barge rig 75 began a three-year contract in September 2004 and barge rig 73 began a two-year contract with a one-year option in late December 2004.
Our domestic utilization rate as of March 1, 2005 was 79 percent. Our upgraded barge rig 76 began operating in October 2004 at a significantly higher dayrate due to its ultra-deep drilling capacity, for which we anticipate continued demand due to the high level of natural gas prices. We have moved barge rig 72 from Nigeria to the U.S. Gulf of Mexico to take advantage of the strong demand for deep barge drilling in this segment of our operations. We expect barge rig 72 to begin work in the U.S. Gulf of Mexico early in the second quarter of 2005. Based on the current trend, we anticipate dayrates and utilization to show modest improvement throughout 2005.
Our rental tools segment, Quail Tools, continues to expand its market share in the U.S. The fourth quarter margin for Quail Tools was one of its best in history. Quail Tools also established an international presence in 2004 by providing rental tools to operations in Mexico and Sakhalin Island, Russia. We anticipate Quail Tools’ financial results will remain strong throughout 2005.
We have also made substantial progress toward our goal of $200 million in debt reduction, primarily through the sale of assets. As previously reported, we sold our jackup and platform rigs in August 2004, which, together with insurance proceeds of $41.6 million from the damage to barge rig 74 and jackup rig 14, allowed us to further reduce our debt by $134.0 million, through February 15, 2005. This results in achieving 67 percent of the debt reduction goal we established at the end of 2002. We also restructured $150.0 million in debt by issuing new Senior Floating Rate Notes due 2010. In addition, although the interest rate on the majority of the debt paid off during 2004 was 5.5%, the restructuring allowed us to
RESULTS OF OPERATIONS (continued)
Outlook and Overview (continued)
reduce the average stated interest rate on our remaining debt from 9.0% to 8.9%. We are continuing our efforts to sell additional assets to reach our debt reduction goal and to reduce our overall interest cost.
As we have reported during our recent conference calls, profitable growth and completion of our debt reduction goal are primary objectives for 2005. Even though we anticipate higher levels of activity in 2005, we will continue to conserve cash by closely monitoring our capital expenditures, working capital, inventory and general and administrative expenses. We are positioned to show improved results for 2005 and we expect earnings to be in line with previously announced guidance of net income per share in the $0.05 to $0.14 range.
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
We recorded a net loss of $47.1 million for the year ended December 31, 2004 as compared to a net loss of $109.7 million for the year ended December 31, 2003. The loss from continuing operations was $50.6 million and $52.4 million for the years ended December 31, 2004 and 2003, respectively. The income (loss) from discontinued operations was $3.5 million and ($57.3) million for 2004 and 2003, respectively. An impairment of $53.8 million is included in 2003 discontinued operations related primarily to the sale of U.S. jackup and platform rigs that were completed in 2004, except for jackup rig 25 which was sold in January 2005.
Revenues increased $37.9 million to $376.5 million in 2004 as compared to 2003. The increase is attributed to higher utilization in the U.S. barge operations, international land operations and our rental tools operations, Quail Tools.
(1)
Drilling and rental gross margins are computed as drilling and rental revenues less direct drilling and rental operating expenses, excluding depreciation and amortization expense; drilling and rental gross margin percentages are computed as drilling and rental
RESULTS OF OPERATIONS (continued)
gross margin as a percent of drilling and rental revenues. The gross margin amounts and gross margin percentages should not be used as a substitute for those amounts reported under accounting principles generally accepted in the United States (“GAAP”). However, we monitor our business segments based on several criteria, including drilling and rental gross margin. Management believes that this information is useful to our investors because it more closely tracks cash generated by segment. Such gross margin amounts are reconciled to our most comparable GAAP measure as follows:
(2)
Drilling and rental operating income - drilling and rental revenues less direct drilling and rental operating expenses, including depreciation and amortization expense.
U.S. Drilling Segment
U.S. drilling revenues increased $21.1 million in 2004 to $88.5 million due to higher utilization and dayrates. As of December 31, 2004 the U.S. drilling segment consisted of 19 barge rigs; nine deep drilling barge rigs, four intermediate drilling barge rigs and six workover barge rigs. During the fourth quarter of 2004, two workover barge rigs were impaired and removed from the marketable rig fleet. In addition, during the second quarter of 2004, deep drilling barge rig 53 was moved to Mexico to begin work on a two-year contract for Pemex. Average 2004 utilization for the barge rigs increased to 63 percent from an average utilization during 2003 of 50 percent. The increase in utilization accounted for approximately $10.8 million of the increase in revenues. Average 2004 dayrates increased approximately $2,200 per day as compared to 2003 accounting for the remaining $10.2 million of the revenue increase. During the third quarter of 2004 we upgraded barge rig 76 enabling it to drill effectively in ultra-deep shelf drilling. The rig began drilling under a multi-well program in late October at a significantly higher dayrate of approximately $37,000 per day, compared to the previous dayrate of approximately $21,000 per day. In addition, we have relocated barge rig 72 from Nigeria to the U.S. Gulf of Mexico to take advantage of the increased utilization and dayrates. The rig will undergo maintenance and refurbishment and will be available for contract in April 2005. As a result of higher dayrates and utilization, gross margins in the U.S. drilling segment increased $14.7 million to $34.4 million. Gross margins during the fourth quarter of 2004 were negatively impacted by $1.5 million for the move of barge rig 72 from Nigeria to the U.S. Gulf of Mexico.
International Drilling Segment
International drilling revenues increased $4.3 million to $220.8 million in 2004 as compared to 2003. International land drilling revenues increased $48.7 million to $188.0 million offset by a reduction in international offshore drilling revenues of $44.4 million to $32.8 million. International drilling gross margins decreased by $12.0 million to $52.4 million due almost entirely to reduced activity in the international offshore barge rigs.
International land operations experienced increased utilization in all regions except the Latin America countries of Colombia, Bolivia and Peru. During the second and third quarters of 2004 we moved seven land rigs which had been located in Colombia, Bolivia and Argentina to Mexico to begin a two-year
RESULTS OF OPERATIONS (continued)
International Drilling Segment (continued)
drilling contract for Halliburton de Mexico (“Halliburton”) contributing $19.8 million in revenues. In our Asia Pacific region, we increased revenues by $14.0 million as a result of new drilling contracts in Bangladesh, New Zealand and Papua New Guinea when compared to 2003. In our CIS region we increased revenues by $25.6 million by adding a second rig in Turkmenistan in March 2004 and from the full year impact of our five-year labor agreement on Sakhalin Island. The Sakhalin Island contract commenced operations in June 2003. Rig 236 which had been operating in northern Russia completed its drilling activities in June 2004 and was stacked for the remainder of the year. We are currently negotiating a contract to operate this rig in Turkmenistan which would commence in the third quarter of 2005. Utilization in Colombia, Bolivia and Peru decreased significantly during most of 2004, resulting in $10.3 million less revenues when compared to 2003. In Peru, operations under the contract utilizing rig 228 were suspended, at the request of the customer, effective April 1, 2004. Since April we have been receiving a reduced standby rate. We expect this rig to return to a full operating dayrate during the third quarter of 2005. In Bolivia no rigs worked during 2004. Because we do not anticipate any change in this market for the foreseeable future, we decided to close the operation and recognized a $2.4 million impairment charge during the fourth quarter of 2004, reducing the net carrying value of the Bolivia assets to net realizable value. Three land rigs remain in Colombia and, as of the end of 2004 and into the first quarter of 2005, all three are operating.
International land gross margins increased $16.0 million in 2004 when compared to 2003. The increase is primarily the result of increased activity as noted above in the CIS and Asia Pacific regions. In addition, gross margins increased in the last half of 2004 as our seven land rigs began operations in Mexico, even with increased costs related to the amortization of a loss on mobilization and startup costs. The quarterly amortization approximates $1.0 million and will be fully amortized by the end of the first quarter 2006. In 2004 when compared to 2003, international land gross margins were negatively impacted by a $4.0 million decrease in Latin America operations, excluding Mexico. The decrease is primarily attributed to the standby situation in Peru and the reduced activity in Colombia.
International offshore drilling revenues decreased $44.4 million to $32.8 million in 2004 as compared to 2003. The decrease in revenues was attributable to a $24.6 million decrease in the Caspian Sea operation and a $24.8 million decrease in our Nigerian operations, partially offset by increased revenues of $5.0 million from our barge rig in Mexico. In November 2003, our arctic-class barge rig 257 completed its initial four-year contract and was demobilized and stacked throughout most of 2004. During the fourth quarter of 2004, we signed a two-well contract with options for an additional four wells. Barge rig 257 began recognizing revenues under this new contract in late December 2004. In Nigeria, revenues decreased significantly due to reduced utilization. Barge rig 75 worked throughout 2003 but returned to port for repairs in June 2004 and its initial five-year contract expired mid-September 2004. A three-year contract extension was signed in September 2004 at a dayrate approximately 15 percent less than the initial five-year term. Barge rig 73 operated the first five months of 2004 and was stacked until mid-December 2004. In mid-December, barge rig 73 began mobilizing under a new two-year contract with a one-year option. Barge rig 74 remains evacuated since sustaining substantial damage due to community unrest in March 2003. In December 2004, we received insurance proceeds in the amount of $18.5 million, a portion of which was used in February 2005 to reduce long-term debt. During the fourth quarter of 2004, we made the decision to move barge rig 72 from Nigeria to the U.S. Gulf of Mexico region.
International offshore gross margins decreased $27.9 million in 2004 as compared to 2003. Costs to maintain barge rig 257 in a stacked condition approximated $1.0 million per quarter and we also settled an assessment of duties, taxes and penalties for barge rig 257 with the Customs Control in Mangistau, Kazakhstan, in the third quarter of 2004 for $2.1 million, resulting in a negative gross margin of $6.2 million. In Nigeria, lower utilization on the barge rigs caused reduced revenues in 2004. Ongoing costs to maintain the barges in stacked condition and increased insurance cost caused by losses incurred, both negatively impacted gross margin. In addition, Nigerian tax authorities assessed additional Value
RESULTS OF OPERATIONS (continued)
International Drilling Segment (continued)
Added Tax (“VAT”), resulting in a charge of $2.3 million in the second quarter of 2004. All of these factors combined to reduce the $11.7 million 2003 gross margin in Nigeria to breakeven in 2004. Barge rig 53 commenced operations in Mexico in May 2004 under a new two-year contract for Pemex. Prior to receiving this contract, the barge rig had operated in the U.S. Gulf of Mexico.
Rental Tools Segment
Rental tools revenues increased $12.5 million to $67.2 million in 2004. The increases in revenues were attributable to a $2.5 million increase from the New Iberia, Louisiana facility, $3.0 million from the Victoria, Texas facility, $4.8 million from the Odessa, Texas facility, and $2.2 million from the Evanston, Wyoming facility. Both the New Iberia, Louisiana and Victoria, Texas operations experienced an increase in customer demand due to increased deep water drilling in the Gulf of Mexico. All locations experienced increased customer demand and saw an expansion in customer base.
Other Financial Data
Depreciation and amortization expense decreased $4.4 million to $69.2 million in 2004. The decrease is primarily attributable to the continued commitment to our capital expenditure program that calls for limiting expenditures to scheduled ongoing maintenance projects, expenditures required under our preventive maintenance program and for capital projects with an attractive rate of return.
General and administrative expense increased $4.2 million to $23.4 million for the year ended December 31, 2004 as compared to 2003. During the first quarter of 2004 we incurred an expense of $1.0 million related to the accelerated vesting of certain restricted stock including our portion of the FICA expense. The restricted shares were granted in July 2003 and were scheduled to vest over seven years, but included an accelerated vesting feature based on stock performance goals. In accordance with the accelerated vesting feature, 377,500 shares of the grant vested in March 2004 based on meeting the initial stock performance goal of $3.50 per share for 30 consecutive days. Subsequent to December 31, 2004, the remaining 340,000 shares vested in March 2005 after the closing stock price of $5.00 was met for 30 consecutive days which will result in an expense of $0.7 million. This expense will be recognized during the first quarter of 2005. In the second quarter of 2004, we expensed $1.4 million related to severance costs associated with our former chief operating officer. In addition, during 2004, we incurred approximately $2.7 million related to the documentation and testing for compliance with section 404 of the Sarbanes-Oxley Act of 2002 (“SOX”).
During 2004, we recognized a provision for reduction in carrying value of certain assets of $13.1 million. During the fourth quarter of 2004, we determined that two workover barge rigs in the U.S. Gulf of Mexico fleet were not economically marketable. As a result, we recorded an impairment of $3.2 million and will dispose of the two barge rigs. In the Asia Pacific region, we reduced the carrying amount of two rigs to net realizable value, which resulted in recording an impairment charge of $0.7 million. Also, during the fourth quarter of 2004, we made the decision to dispose of all the assets in Bolivia, which included two land rigs, inventory and spare parts. We incurred an impairment charge of $2.4 million to reduce the cost basis of these assets to net realizable value. We expect to close the Bolivia office the second quarter of 2005. During the second quarter of 2004, we reclassified our Latin America assets from discontinued operations to continuing operations and recognized a $5.1 million charge to adjust the value of the Latin America assets to their fair value. GAAP requires that an operation reclassified from discontinued operations to continuing operations be measured at the lower of its (a) carrying amount before the asset was classified as held for sale, adjusted for any depreciation expense that would have been recognized had the asset been continuously classified as held and used, or (b) fair value at the date of the subsequent decision not to sell. The $5.1 million represents the depreciation that would have been recognized had the assets been continuously classified as held and used. In addition, during 2004 we
RESULTS OF OPERATIONS (continued)
Other Financial Data (continued)
reserved $1.7 million for an asset representing premiums paid in prior years on two split dollar life insurance policies for Robert L. Parker. The value of the asset was reduced to the cash surrender value of the insurance policies. See Note 13 in the notes to the consolidated financial statements.
In 2003, three non-marketable rigs in the Asia Pacific region and certain spare parts and equipment in New Iberia, Louisiana were impaired by $2.6 million to estimated salvage value. Subsequent to December 31, 2003, we signed an agreement to sell the New Iberia, Louisiana land and buildings for a net sales price of $6.4 million. This resulted in an impairment of $3.4 million at December 31, 2003, as the net book value of the property exceeded the net sales price. The transaction closed in August 2004 and no additional gain or loss was recognized upon disposition.
Interest expense decreased $3.4 million to $50.4 million for the year ended December 31, 2004 as compared to 2003. The decrease in interest expense is primarily attributable to the net reduction of $90.2 million to our outstanding debt balance in 2004. The majority of the debt reduction occurred in August 2004 with proceeds from the sale of our jackup and platform rigs.
In August and September of 2004, we entered into three variable-to-fixed interest rate swap agreements. The swap agreements did not qualify for hedge accounting and accordingly, we are reporting the mark-to-market change in the fair value of the interest rate derivatives currently in earnings. For the year ended December 31, 2004, we recognized a non-cash charge for a decrease in the fair value of the derivative positions of $0.8 million. This amount is included in other income (expense) in the selected financial data.
On September 2, 2004, we issued $150.0 million of Senior Floating Rate Notes and concurrently repurchased $80.0 million of our 10.125% Senior Notes at a premium and paid off $70.0 million of our delay draw term loan. Total charges of $8.8 million consisting of the 6.54 percent premium on the repurchase of the 10.125% Senior Notes, the write-off of the previously capitalized debt issuance costs associated with the repurchase of the 10.125% Senior Notes and the repayment of the delay draw term loan, and legal and other fees were recorded as loss on extinguishment of debt in the statement of operations. In 2003, in conjunction with the refinancing of a portion of our debt, we incurred $5.3 million expense related to the retirement of our 9.75% Senior Notes. These costs have been recorded as loss on extinguishment of debt and include costs of the call premium on the 9.75% Senior Notes, write-off of remaining capitalized debt issuance costs offset by the write-off of the remaining swap gain that was being amortized over the remaining life of the 9.75% Senior Notes. These amounts are included in other income (expenses) in the selected financial data.
We have a 50 percent interest in a joint venture in Kazakhstan, AralParker, which owns and operates two drilling rigs and other drilling equipment. AralParker is included in the consolidated financial statements of Parker Drilling Company. During 2004, AralParker generated net income of $2.2 million and accordingly, we have recognized an expense for minority interest of $1.1 million. During 2003, AralParker generated a loss of $0.9 million resulting in income from minority interest of $0.5 million.
Income tax expense from continuing operations consists of foreign tax expense of $15.0 million for the year ended December 31, 2004. For the year ended December 31, 2003, income tax expense from continuing operations consisted of foreign tax expense of $17.0 million. Foreign taxes decreased $2.0 million in 2004 due primarily to reduced activity in Nigeria in addition to barge rig 257 in Kazakhstan being stacked the majority of the year. Partially offsetting these reductions were increased taxes in Papua New Guinea related to current and prior year assessments and the startup of operations in Mexico. Although we incurred a net loss in the current year, no additional deferred tax benefit was recognized since the sum of our deferred tax assets, principally the net operating loss carryforwards, exceeded the deferred tax liabilities, principally the excess of tax depreciation over book depreciation. This additional deferred tax asset was fully reserved through a valuation allowance in both 2004 and 2003.
RESULTS OF OPERATIONS (continued)
Analysis of Discontinued Operations
(1)
Drilling gross margin is computed as drilling revenues less direct drilling operating expenses, excluding depreciation and amortization expense. The gross margin amounts and gross margin percentages should not be used as a substitute for those amounts reported under GAAP. However, we monitor our business segments based on several criteria, including drilling gross margin. Management believes that this information is useful to our investors because it more closely tracks cash generated by segment. Such gross margin amounts are reconciled to our most comparable GAAP measure as follows:
(2)
Depreciation and amortization - in accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” we stopped recording depreciation expense related to the discontinued operations effective June 30, 2003.
On August 2, 2004, we finalized the sale of five jackup and four platform rigs, realizing net proceeds of $39.3 million. No gain or loss was recorded on the sale and the proceeds were used to pay down debt. Jackup rig 25 was excluded from this sale, although the purchaser retained the exclusive right to purchase it. On January 3, 2005, we sold jackup rig 25 to such purchaser. We received proceeds of $21.5 million and recognized an additional impairment on the disposition of $4.1 million in December 2004. With the consummation of this transaction all the jackup and platform rigs have been sold. No other assets remain related to our discontinued operations and all proceeds were used to pay down debt.
Year Ended December 31, 2003 Compared to Year Ended December 31, 2002
We recorded a loss from continuing operations of $52.4 million for the year ended December 31, 2003 as compared to a loss from continuing operations of $21.2 million for the year ended December 31, 2002. We recorded a loss from discontinued operations of $57.3 million for the year ended December 31, 2003 as compared to a loss from discontinued operations of $19.7 million for the year ended December 31, 2002. The loss from discontinued operations in 2003 included an impairment of $53.8 million to recognize those assets held for sale at lower of cost or market. For the year ended December 31, 2002 we recognized a change in accounting principle related to our adoption of SFAS No. 142, “Goodwill and Other Intangible Assets” which resulted in recording an impairment of goodwill of $73.1 million in the first quarter of 2002.
RESULTS OF OPERATIONS (continued)
The reduction in revenues from $385.7 million to $338.7 million was attributed to reduced drilling activity worldwide as a result of the economic downturn in the United States and increased inventories of oil and natural gas.
(1)
Drilling and rental gross margins are computed as drilling and rental revenues less direct drilling and rental operating expenses, excluding depreciation and amortization expense; drilling and rental gross margin percentages are computed as drilling and rental gross margin as a percent of drilling and rental revenues. The gross margin amounts and gross margin percentages should not be used as a substitute for those amounts reported under accounting principles generally accepted in the United States (“GAAP”). However, we monitor our business segments based on several criteria, including drilling and rental gross margin. Management believes that this information is useful to our investors because it more closely tracks cash generated by segment. Such gross margin amounts are reconciled to our most comparable GAAP measure as follows:
(2)
Drilling and rental operating income - drilling and rental revenues less direct drilling and rental operating expenses, including depreciation and amortization expense.
RESULTS OF OPERATIONS (continued)
U.S. Drilling Segment
U.S. drilling revenues generated from 21 barge rigs in the U.S. Gulf of Mexico decreased $10.9 million in 2003 to $67.5 million due primarily to lower dayrates. The U.S. Gulf of Mexico market declined significantly during the fourth quarter of 2001 and continued throughout 2002 and 2003 due primarily to a reduction in drilling activity. Average dayrates declined nine percent during 2003 as compared to 2002. Utilization for the barge rigs remained comparable year to year at just over 50 percent. Although prices for natural gas rose during 2003, uncertainty regarding the economy and international issues caused operators to be hesitant to significantly increase drilling. The U.S. drilling operations gross margin decreased $6.1 million during 2003 as compared to 2002. The gross margin percentage decreased from 33 percent to 29 percent primarily attributed to the decrease in barge rig revenues.
International Drilling Segment
International drilling revenues decreased $43.3 million to $216.6 million in 2003 as compared to 2002, of which $26.2 million was attributed to a decrease in international land drilling revenues. International drilling gross margin decreased $20.0 million in 2003 as compared to the year ended December 31, 2002.
International land drilling revenues in the CIS region increased $2.8 million in 2003 primarily attributable to the commencement of drilling operations on Sakhalin Island, Russia. Drilling activity began in June 2003, on a five-year contract with five one-year options, contributing revenues of $13.3 million. This increase was partially offset by decreased revenues in Kazakhstan. In the Karachaganak field, we worked three rigs during 2002 while only one worked during 2003. In addition, in December 2002, one Tengizchevroil (“TCO”) owned rig for which we provided labor services was released, resulting in reduced revenues in 2003. This rig was reinstated and returned to active drilling in November 2003. Revenues decreased in the Asia Pacific region and the Middle East by $11.0 million related primarily to reduced utilization in Papua New Guinea and Indonesia. This decrease was partially offset by a new contract in Bangladesh that began drilling during the fourth quarter of 2003. Revenues decreased $18.0 million in the Latin America region due to a decrease in utilization. The region operated an average of 3.0 rigs during 2003 as compared to 7.0 rigs during the year ended December 31, 2002. The decline in utilization was primarily attributed to Colombia and Ecuador, partially offset by operations in Peru. In 2002, Ecuador had one rig operating; the contract was completed in late 2002 and the rig was mobilized to Bangladesh. Peru had one rig operating at full dayrate during 2003 as compared to a partial year for the year ended December 31, 2002. International land drilling gross margins decreased $17.6 million to $41.2 million in 2003 due primarily to the reduced revenues in our land drilling operations in Kazakhstan, Papua New Guinea, New Zealand and Latin America. The gross margin percentage for the international land drilling decreased from 36 percent for 2002 to 30 percent in 2003.
International offshore drilling revenues accounted for the remaining $17.1 million decrease in international drilling revenues and was attributable entirely to Nigeria. In March 2003, two of the three barge rigs suspended drilling and were evacuated due to community unrest. After evacuation both barge rigs were placed on force majeure rates at approximately 90 percent of the full dayrate. One of the barge rigs, rig 75, returned to full operations while the second barge rig remains evacuated. In April 2003, barge rig 74 was placed on a standby rate at approximately 45 percent of the full dayrate. This dayrate terminated in February 2004. The international offshore drilling gross margin decreased $2.4 million to $23.1 million for 2003. Gross margin in Nigeria decreased approximately $6.3 million during 2003 when compared to 2002, primarily due to loss of revenues caused by community unrest issues. This decrease was partially offset by an increase of $3.9 million in gross margin related to barge rig 257 in the Caspian Sea. The gross margin in 2003 was positively impacted by demobilization revenues that exceeded the costs to stack barge rig 257 upon completion of the contract in the fourth quarter of 2003. The 2002 gross margin was negatively impacted by an additional assessment for property taxes.
RESULTS OF OPERATIONS (continued)
Rental Tools Segment
Rental tools revenues increased $7.1 million to $54.6 million in 2003. Revenues increased $3.5 million from the New Iberia, Louisiana operation, increased $1.3 million from the Victoria, Texas operation, decreased $0.4 million from the Odessa, Texas operation, and generated an increase of $2.7 million from its operation in Evanston, Wyoming. Both the New Iberia, Louisiana and Victoria, Texas operations experienced an increase in customer demand due to increased deep water drilling in the Gulf of Mexico. Demand at the Odessa, Texas facility was down seven percent in 2003 as compared to 2002 due to a decrease in customer activity in the region and a highly competitive pricing environment. The Evanston, Wyoming operation that opened in May 2002 continues to expand its customer base. Rental tools gross margin increased $5.9 million to $31.6 million during 2003 as compared to 2002. Gross margin percentage increased to 58 percent during 2003 as compared to 54 percent for the year ended December 31, 2002, due to a 15 percent increase in revenues and only a six percent increase in operating expenses. The slight increase in operating expenses was driven primarily by increased direct costs and increased man hours worked.
Other Financial Data
Depreciation and amortization expense decreased $3.7 million to $73.7 million during 2003 as compared to 2002. Depreciation expense decreased due to the reclassification of Latin America assets to assets held for sale as of June 30, 2003. As a result, depreciation related to the assets held for sale was not recorded for the last six months of 2003.
During the first quarter of 2002, we 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 revenues and expenses for the construction phase of the project were recognized as construction contract revenues and expenses, with the profit calculated on a percentage-of-completion basis. The construction project was completed in June 2003. We recognized profit of $2.0 million and $2.5 million for the years ended December 31, 2003 and 2002, respectively.
General and administrative expense decreased $5.5 million to $19.3 million for the year ended December 31, 2003 as compared to 2002. This decrease was primarily attributed to the following: salaries and wages decreased $2.1 million as a result of the reduction in force in June 2002, a decrease in professional and legal fees of $0.8 million, a $1.3 million decrease in property and franchise tax expense, and unscheduled maintenance of $0.2 million on the former corporate headquarters in Tulsa, Oklahoma during 2002. The remaining decrease was a result of the cost reduction program implemented in 2002.
During 2003, we recognized a provision for reduction in carrying value of certain assets of $6.0 million. Three non-marketable rigs in the Asia Pacific region and certain spare parts and equipment in New Iberia, Louisiana were impaired by $2.6 million to estimated salvage value. Subsequent to December 31, 2003, we signed an agreement to sell the New Iberia, Louisiana land and buildings for a net sales price of $6.4 million. This sale was consummated in August 2004. This resulted in an impairment of $3.4 million at December 31, 2003, as the net book value of the property exceeded the net sales price.
Interest expense increased $1.4 million for the year ended December 31, 2003 as compared to 2002. During the first quarter of 2002, we entered into three $50.0 million swap agreements that resulted in $2.9 million in interest savings during 2002. The swap agreements were terminated during the third quarter of 2002. Effective July 1, 2002, interest expense increased due to the exchange of $235.6 million in principal amount of new 10.125% Senior Notes due 2009 for a like amount of 9.75% Senior Notes due 2006. Partially offsetting this increase was a reduction in interest from the purchase of $14.8 million of 5.5% Convertible Subordinated Notes on the open market in May 2003, reduced interest resulting from the principal reduction of the Boeing Capital Corporation note and the amortization of the swap gain recognized upon liquidation of the swap agreements.
RESULTS OF OPERATIONS (continued)
Other Financial Data (continued)
In conjunction with our refinancing of a portion of our debt, we incurred $5.3 million of costs related to the retirement of our 9.75% Senior Notes. These costs have been recorded as loss on extinguishment of debt and include costs of the premium to call the 9.75% Senior Notes, write-off of remaining capitalized debt issuance costs offset by the write-off of the remaining swap gain that was being amortized over the remaining life of the 9.75% Senior Notes. This amount is included in other income (expense) in the selected financial data.
Other income (expense) improved $3.4 million in 2003 as compared to the year ended December 31, 2002. The year ended 2002 included $3.6 million related to the debt exchange offer completed in the second quarter of 2002 and $0.4 million costs incurred for an attempted acquisition. This amount is included in other income (expense) in the selected financial data.
Income tax expense from continuing operations consisted of foreign tax expense of $17.0 million for the year ended December 31, 2003. For the year ended December 31, 2002 income tax expense from continuing operations consisted of foreign tax expense of $21.3 million and a U.S. deferred tax benefit of $17.1 million. In the year-to-year comparison, foreign taxes decreased $4.3 million. Foreign taxes decreased in 2003 due to a 2002 increase in Colombia related to a change in allowable depreciation and increased taxes in 2002 from Kazakhstan and the Asia Pacific region. For 2003 we incurred a net loss; however, no additional deferred tax benefit was recognized since the sum of our deferred tax assets, principally the net operating loss carryforwards, exceeded the deferred tax liabilities, principally the excess of tax depreciation over book depreciation. This additional deferred tax asset was fully reserved through a valuation allowance.
Analysis of Discontinued Operations
(1)
Drilling gross margin is computed as drilling revenues less direct drilling operating expenses, excluding depreciation and amortization expense. The gross margin amounts and gross margin percentages should not be used as a substitute for those amounts reported under GAAP. However, we monitor our business segments based on several criteria, including drilling gross margin. Management believes that this information is useful to our investors because it more closely tracks cash generated by segment. Such gross margin amounts are reconciled to our most comparable GAAP measure as follows:
(2)
Depreciation and amortization - in accordance with SFAS No. 144, we stopped recording depreciation expense related to the discontinued operations effective June 30, 2003.
RESULTS OF OPERATIONS (continued)
Analysis of Discontinued Operations (continued)
Revenues for the U.S. jackup and platform drilling operations increased $5.4 million to $47.2 million in 2003 as compared to 2002. The jackup rigs contributed to the increase with higher utilization and improved dayrates. Utilization for the jackup rigs increased from 80 percent to 82 percent and average dayrates improved 11 percent for 2003 as compared to the year ended December 31, 2002.
The U.S. jackup and platform drilling operations gross margin was $6.3 million in 2003, an increase of $4.5 million from 2002. The gross margin was positively impacted in 2003 by higher dayrates and utilization for the jackup rigs and platform rigs as discussed above.
LIQUIDITY AND CAPITAL RESOURCES
Operating Cash Flows
As of December 31, 2004, we had cash and cash equivalents of $44.3 million, a decrease of $23.5 million from December 31, 2003. The primary sources of cash for the twelve-month period as reflected on the consolidated statement of cash flows were $28.8 million provided by operating activities, $41.6 million of insurance proceeds, and $52.4 million of proceeds from the disposition of assets and marketable securities. The primary uses of cash for the twelve-month period ended December 31, 2004 were $47.3 million for capital expenditures and $99.0 million for financing activities. Major capital expenditures for the period included $11.9 million to refurbish rigs for work in Mexico, $7.5 million to refurbish barge rig 76 for ultra-deep drilling in the shallow waters of the U.S. Gulf of Mexico and $13.0 million for tubulars and other rental tools for Quail Tools. Our financing activities include a net reduction in debt of $90.2 million and are further detailed in a subsequent paragraph.
As of December 31, 2003, we had cash and cash equivalents of $67.8 million, an increase of $15.8 million from December 31, 2002. The primary sources of cash for the twelve-month period as reflected on the consolidated statement of cash flows were $62.5 million provided by operating activities, $6.0 million of insurance proceeds for barge rig 18 and $6.3 million of proceeds from the disposition of equipment. The primary uses of cash for the twelve month period ended December 31, 2003 were $35.0 million for capital expenditures and $15.2 million net reduction of debt. Major capital expenditures during 2003 included $18.1 million for Quail Tools (consisting mostly of purchases of drill pipe and tubulars) and $2.1 million to refurbish rig 230 and rig 247 for work in Turkmenistan. The major components of our net debt reduction were the purchases of $19.3 million face value of our outstanding 5.5% Convertible Subordinated Notes on the open market, $14.8 million in May 2003 and $4.5 million in December 2003. In addition, we paid down $5.5 million of a secured promissory note to Boeing Capital Corporation. During the fourth quarter of 2003 we paid off all of our outstanding 9.75% Senior Notes ($214.2 million face value) with proceeds from our new 9.625% Senior Notes ($175.0 million face value) and a $50.0 million initial draw of a $100.0 million term loan.
Financing Activity
On July 30, 2004 we drew down the remaining $50.0 million on our delay draw term loan portion of our credit agreement dated October 10, 2003. Those funds, along with existing cash, were used to retire the existing $64.4 million of our 5.5% Convertible Subordinated Notes on August 2, 2004. On the same day, August 2, 2004, we received proceeds from the sale of our five jackup rigs and four platform rigs and paid down $25.0 million of the delay draw term loan. On August 5, 2004, we paid an additional $5.0 million on the delay draw term loan with proceeds from the sale of our New Iberia facilities, leaving an outstanding balance of $70.0 million on the delay draw term loan.
In September 2004, we refinanced a portion of our existing debt by issuing $150.0 million of Senior Floating Rate Notes due 2010 with interest terms set at the three-month LIBOR rate plus 4.75%. In addition, we have entered into interest rate swap agreements to fix the interest rate at a range of 6.54% to
LIQUIDITY AND CAPITAL RESOURCES (continued)
Financing Activity (continued)
8.83% for portions of this debt through 2008. See Note 6 in the notes to the consolidated financial statements. Proceeds were used to pay off the $70.0 million outstanding balance of our delay draw term loan and to retire $80.0 million of the 10.125% Senior Notes due 2009 that had been tendered pursuant to a tender offer dated August 6, 2004. Total proceeds of $150.0 million from this transaction were used to pay down debt. Cash costs associated with the transaction totaled $9.7 million and were paid from existing cash. Cash costs included an early tender premium of 2.0 percent and a tender offer consideration of 104.54 percent on the $80.0 million tendered 10.125% Senior Notes, as well as underwriting, legal and other fees associated with the issuance of $150.0 million Senior Floating Rate Notes.
In December 2004, we replaced our existing $50.0 million credit facility with a new $40.0 million credit facility that expires in December 2007. The new revolving credit facility is secured by rental tools equipment, accounts receivable and substantially all of the stock of the subsidiaries, and contains customary affirmative and negative covenants such as minimum ratios for consolidated leverage, consolidated interest coverage and consolidated senior secured leverage.
We anticipate the working capital needs and funds required for capital spending will be met from existing cash, cash provided by operations and asset sales. It is our intention to limit capital spending, net of reimbursements from customers, to approximately $60.0 million in 2005. Should new opportunities requiring additional capital arise, we may seek project financing or equity participation from outside alliance partners or customers. We have no assurances that such financing or equity participation would be available on terms acceptable to us.
In October 2003, we refinanced a portion of our existing debt by issuing $175.0 million of the 9.625% Senior Notes due 2013 and replaced our senior credit facility with a $150.0 million senior credit agreement. The senior credit agreement consisted of a four-year $100.0 million delay draw term loan facility and a three-year $50.0 million revolving credit facility that were secured by certain drilling rigs, rental tools equipment, accounts receivable and substantially all of the stock of the subsidiaries, and contains customary affirmative and negative covenants. The proceeds of the 9.625% Senior Notes, plus an initial draw of $50.0 million under the delay draw term loan facility, were used to retire $184.3 million of the 9.75% Senior Notes due 2006 that had been tendered pursuant to a tender offer dated September 24, 2003. The balance of the proceeds from the 9.625% Senior Notes and the initial draw down under the term loan facility were used to retire the remaining $29.9 million of 9.75% Senior Notes that were not tendered. We redeemed the remaining bonds on November 15, 2003 at a call premium of 1.625 percent.
The new revolving credit facility is available for working capital requirements, general corporate purposes and to support letters of credit. Availability under the revolving credit facility is subject to a borrowing base limitation based on 85 percent of eligible receivables plus a value for eligible rental tools equipment. The credit facility calls for a borrowing base calculation only when the credit facility has commitments of at least $25.0 million. As of December 31, 2004, the total commitments of the credit facility were $16.1 million, of which $15.3 million related to letters of credit and $0.8 million related to the mark-to-market value of the variable-to-fixed, interest rate swap agreements relating to our Senior Floating Rate Notes, thus a borrowing base calculation was not required.
We had total debt of $481.1 million at December 31, 2004. The debt included:
•
$156.1 million aggregate principal amount of 10.125% Senior Notes, which are due November 15, 2009;
•
$150.0 million aggregate principal amount of Senior Floating Rate Notes bearing interest at a rate of the three-month LIBOR plus 4.75%, which are due September 1, 2010; and
•
$175.0 million aggregate principal amount of 9.625% Senior Notes, which are due October 1, 2013.
LIQUIDITY AND CAPITAL RESOURCES (continued)
Financing Activity (continued)
As of December 31, 2004, we had approximately $68.2 million of liquidity. This liquidity was comprised of $44.3 million of cash on hand and an estimated $23.9 million of undrawn availability under the new revolving credit facility.
On February 7, 2005, we purchased an additional $25.0 million face value of our 10.125% Senior Notes pursuant to a redemption notice dated January 6, 2005 at the redemption price of 105.0625 percent.
The following table summarizes our future contractual cash obligations as of December 31, 2004:
(1)
Long-term debt includes the principal and interest cash obligations of the 9.625% Senior Notes, the 10.125% Senior Notes and the Senior Floating Rate Notes. The unamortized premium of $0.4 million at December 31, 2004 related to the 10.125% Senior Notes is not included in the contractual cash obligations schedule. Some of the interest on the Senior Floating Rate Notes has been fixed through variable-to-fixed interest rate swap agreements. The issuer (Bank of America, N.A.) of each swap has the option to extend each swap for an additional two years at the termination of the initial swap period. For this table, the highest interest rate currently hedged is used in calculating the interest on future floating rate periods.
(2)
Operating leases consist of lease agreements in excess of one year for office space, equipment, vehicles and personal property.
(3)
We have a $40.0 million revolving credit facility. As of December 31, 2004 we had availability of $40.0 million, of which none has been drawn down, but $15.3 million of availability has been used to support letters of credit that have been issued and $0.8 million of availability has been reserved for the mark-to-market value of variable-to-fixed interest rate swap agreements relating to our Senior Floating Rate Notes, resulting in an estimated $23.9 million availability. The revolving credit facility expires in December 2007.
(4)
We have entered into employment agreements with the executive officers of the Company; see Note 12 in the notes to the consolidated financial statements.
We do not have any unconsolidated special-purpose entities, off-balance-sheet financing arrangements or guarantees of third-party financial obligations. We have no energy or commodity contracts.
OTHER MATTERS
Business Risks
Internationally, we specialize in drilling geologically challenging wells in locations that are difficult to access and/or involve harsh environmental conditions. Our international services are primarily utilized by major and national oil companies and integrated service providers in the exploration and development of reserves of oil. In the United States, we primarily drill in the transition zones of the U.S. Gulf of Mexico for major and independent oil and gas companies. Business activity is primarily dependent on the exploration and development activities of the companies that make up our customer base. Generally, temporary fluctuations in oil and gas prices do not materially affect these companies’ exploration and
OTHER MATTERS (continued)
Business Risks (continued)
development activities and consequently do not materially affect our operations, except for the U.S. 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 shorter-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 our operations. Generally, a sustained change in the price of oil would have a greater impact on our 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 we drill, our operations are subject to interruption, prolonged suspension and possible expropriation due to political instability and local community unrest. Further, we are exposed to potential liability issues from pollution 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
Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, we evaluate our estimates, including those related to bad debts, materials and supplies obsolescence, property and equipment, goodwill, income taxes, workers’ compensation and health insurance and contingent liabilities for which settlement is deemed to be probable. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. While we believe that such estimates are reasonable, actual results could differ from these estimates.
We believe the following are our most critical accounting policies as they are complex and require significant judgments, assumptions and/or estimates in the preparation of our consolidated financial statements. Other significant accounting policies are summarized in Note 1 in the notes to the consolidated financial statements.
Impairment of Property, Plant and Equipment. We periodically evaluate our property, plant and equipment to determine that the net carrying value is not in excess of the net realizable value. We review our property, plant and equipment for impairment when events or changes in circumstances indicate that the carrying value of such assets may be impaired. For example, evaluations are performed when we experience sustained significant declines in utilization and dayrates and we do not contemplate recovery in the near future, or when we reclassify property and equipment to assets held for sale or as discontinued operations as prescribed by SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” We consider a number of factors, including estimated undiscounted future cash flows, appraisals less estimated selling costs and current market value analysis in determining net realizable value. Assets are written down to fair value if the fair value is below net carrying value.
We recorded impairments to our long-lived assets of $13.1 million, $6.0 million and $1.1 million in 2004, 2003, and 2002, respectively. We also recorded $9.4 million and $53.8 million of impairments to our discontinued operations assets in 2004 and 2003, respectively.
Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets, reflect management’s assumptions and judgments regarding future
OTHER MATTERS (continued)
Critical Accounting Policies (continued)
industry conditions and their effect on future utilization levels, dayrates and costs. The use of different estimates and assumptions could result in materially different carrying values of our assets.
Impairment of Goodwill. We periodically assess whether the excess of cost over net assets acquired is impaired based generally on the estimated future cash flows of that operation. If the estimated fair value is in excess of the carrying value of the operation, no further analysis is performed. If the fair value of each operation, to which goodwill has been assigned, is less than 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 impairment should be recorded. Changes in the assumptions such as dayrate and utilization used in the fair value calculation could result in an estimated reporting unit fair value that is below the carrying value, which may give rise to an impairment of goodwill. In addition to the annual review, we also test for impairment should an event occur or circumstances change that may indicate a reduction in the fair value of a reporting unit below its carrying value.
In 2002, SFAS No. 142, “Goodwill and Other Intangible Assets,” became effective and as a result, we discontinued the amortization of goodwill. In lieu of amortization, we performed an impairment review at year-end 2002 and recorded an impairment of $73.1 million. Our annual impairment tests of goodwill at year-end 2003 and 2004 indicated that the fair value of operations to which goodwill relates exceeded the carrying values as of December 31, 2003 and 2004; accordingly, no impairments were recorded.
Insurance Reserves. Our operations are subject to many hazards inherent to the drilling industry, including blowouts, explosions, fires, loss of well control, loss of hole, damaged or lost drilling equipment and damage or loss from inclement weather or natural disasters. Any of these hazards could result in personal injury or death, damage to or destruction of equipment and facilities, suspension of operations, environmental damage and damage to the property of others. Generally, drilling contracts provide for the division of responsibilities between a drilling company and its customer, and we seek to obtain indemnification from our customers by contract for certain of these risks. To the extent that we are unable to transfer such risks to customers by contract or indemnification agreements, we seek protection through insurance. However, there is no assurance that such insurance or indemnification agreements will adequately protect us against liability from all of the consequences of the hazards described above. Moreover, our insurance coverage generally provides that we assume a portion of the risk in the form of an insurance coverage deductible.
Based on the risks discussed above, it is necessary for us to estimate the level of our liability related to insurance and record reserves for these amounts in our consolidated financial statements. Reserves related to insurance are based on the facts and circumstances specific to the insurance claims and our past experience with similar claims. The actual outcome of insured claims could differ significantly from estimated amounts. We maintain actuarially-determined accruals in our consolidated balance sheet to cover self-insurance retentions for workers’ compensation, employers’ liability, general liability and automobile liability claims. These accruals are based on certain assumptions developed utilizing historical data to project future losses. Loss estimates in the calculation of these accruals are adjusted based upon actual claim settlements and reported claims. These loss estimates and accruals recorded in our financial statements for claims have historically been reasonable in light of the actual amount of claims paid.
As the determination of our liability for insurance claims is subject to significant management judgment and in certain instances is based on actuarially estimated and calculated amounts, and such liabilities could be material in nature, management believes that accounting estimates related to insurance reserves are critical.
Accounting for Income Taxes. As part of the process of preparing the consolidated financial statements, we are required to estimate the income taxes in each of the jurisdictions in which we operate. This process involves estimating the actual current tax exposure together with assessing temporary
OTHER MATTERS (continued)
Critical Accounting Policies (continued)
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 our consolidated balance sheet. We then assess the likelihood that the deferred tax assets will be recovered from future taxable income, to the extent we believe that recovery is not likely, we establish a valuation allowance. To the extent we established a valuation allowance or increase or decrease this allowance in a period, we include an expense or reduction of expense within the tax provision in the statement of operations.
Revenue Recognition. We recognize revenues and expenses on dayrate contracts as the drilling progresses. For meterage contracts, which are rare, we recognize the revenues and expenses upon completion of the well. Revenues from rental activities are recognized ratably over the rental term which is generally less than six months. Mobilization fees received and related mobilization costs incurred, if significant, are deferred and amortized over the term of the related drilling contract.
Accounting for Derivative Instruments. We follow SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” as amended by SFAS No. 137 and SFAS No. 138. SFAS No. 133 established accounting and disclosure requirements for most derivative instruments and hedge transactions involving derivatives. SFAS No. 133 also requires formal documentation procedures for hedging relationships and effectiveness testing when hedge accounting is to be applied.
In August and September 2004, we entered into two variable-to-fixed interest rate swap agreements to reduce our cash flow exposure to increases in interest rates on our Senior Floating Rate Notes. The interest rate swap agreements provide us with interest rate protection on the $150.0 million Senior Floating Rate Notes due 2010.
We did not elect to pursue hedge accounting for the interest rate swap agreements, which were executed to provide the economic hedge against cash flow variability on the floating rate notes. We assessed the key characteristics of the interest rate swap agreements and the notes and determined that the hedging relationship would not be highly effective. This ineffectiveness is caused by the existence of embedded written call options in the interest rate swap agreements and not in the notes. Accordingly, we will recognize the volatility of the swap agreements on a mark-to-market basis in the statement of operations. For the year ended December 31, 2004, we recognized a non-cash decrease in the fair value of the interest rate derivatives of $0.8 million. This non-cash expense is reported in the statement of operations as “Changes in fair value of derivative positions.” The non-cash decrease in fair value is reported in the balance sheet as “Other long-term liabilities.” For additional information see Note 6 in the notes to the consolidated financial statements.
The fair market value adjustment of these swap agreements will generally fluctuate based on the implied forward interest rate curve for the three-month LIBOR. If the implied forward interest rate curve decreases, the fair market value of the interest swap agreements will decrease and we will record an additional charge. If the implied forward interest rate curve increases, the fair market value of the interest swap agreements will increase, and we will record income. We will analyze the position of the swap agreements on a quarterly basis and record the mark-to-market impact based on the analysis.
Recent Accounting Pronouncements
In November 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 151, “Inventory Costs - An Amendment of Accounting Research Bulletin (“ARB”) No. 43, Chapter 4.” SFAS No. 151 clarifies the accounting for idle facility expense, freight, handling costs and wasted material to require that all of the aforementioned items be recognized as current period costs. ARB No. 43 previously required that these items reach a level of abnormality before they were expensed. SFAS No. 151 eliminates the “abnormality” requirement and
OTHER MATTERS (continued)
Recent Accounting Pronouncements (continued)
establishes current period recognition. SFAS No. 151 will become effective for us beginning with the calendar year 2006. The adoption of this standard should not have a significant impact on our financial position, results of operations or cash flows.
In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets - an Amendment of Accounting Principles Board (“APB”) Opinion No. 29.” Under APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” the fundamental premise was that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. There was, however, an exception that allowed the exchange of similar productive assets to be recorded on a carryover basis of the original asset. This standard eliminates this exception and replaces it with a general exception that allows for a carryover basis only for exchanges that do not have commercial substance. A nonmonetary exchange is considered to have commercial substance if the entity’s future cash flows are expected to change as a result of the exchange. SFAS No. 153 will become effective for us for nonmonetary transactions entered into beginning with the calendar year 2006. We do not anticipate that the statement will have significant effect on our financial position, results of operations or cash flows.
Also in December 2004, the FASB revised SFAS No. 123, “Accounting for Stock Based Compensation” through issuance of SFAS No. 123R. SFAS No. 123R eliminates the alternative under the original statement to account for situations in which an entity compensates employees with share-based payments using the intrinsic value method established in APB Opinion No. 25. SFAS No. 123R requires that all such transactions be accounted for using the fair value method. We plan to adopt SFAS No. 123R on July 1, 2005 using the modified prospective method without restatement of prior interim periods of the current fiscal year. The impact of adopting SFAS No. 123R will be to record expense for previously-issued but unvested employee stock options and any employee stock options that we issue in the future. We expect the dollar impact on our financial statements to be consistent with the impact disclosed in Note 1 in the notes to the consolidated financial statements.
ITEM 7A.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Interest Rate Risk
The Company entered into two variable-to-fixed interest rate swap agreements as a strategy to manage the floating rate risk on the $150.0 million Senior Floating Rate Notes. The first agreement, signed on August 18, 2004, fixed the interest rate on $50.0 million at 8.83% for a three-year period beginning September 1, 2005 and terminating September 2, 2008 and fixed the interest rate on an additional $50.0 million at 8.48% for the two-year period beginning September 1, 2005 and terminating September 4, 2007. In each case, an option to extend each swap for an additional two years at the same rate was given to the issuer, Bank of America, N.A. The second agreement, signed on September 14, 2004, fixed the interest rate on $150.0 million at 6.54% for the three-month period beginning December 1, 2004 and terminating March 1, 2005. Options to extend $100.0 million at a fixed interest rate of 7.08% for the six-month period beginning March 1, 2005 and to extend $50.0 million at a fixed interest rate of 7.60% for the 18-month period beginning March 1, 2005 and terminating September 1, 2006 were given to the issuer, Bank of America, N.A. Subsequent to year end, Bank of America, N.A. allowed these options to expire unexercised.
These swap agreements do not meet the hedge criteria in SFAS No. 133 and are, therefore, not designated as hedges. Accordingly, the change in the fair value of the interest rate swaps is recognized currently in earnings. As of December 31, 2004, the Company had the following derivative instruments outstanding related to its interest rate swaps:
ITEM 8.
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Parker Drilling Company
We have completed an integrated audit of Parker Drilling Company’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004 and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements and financial statement schedule
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Parker Drilling Company and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 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 accompanying index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As discussed in Note 3 to the consolidated 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.”
Internal control over financial reporting
Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA (continued)
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM (continued)
design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Houston, Texas
March 15, 2005
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.
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 two companies 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 national oil and gas companies and integrated service providers. At December 31, 2004, the Company’s marketable rig fleet consists of 23 barge drilling and workover rigs, and 34 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. For meterage contracts, the Company recognizes the revenues and expenses upon completion of the well. Revenues from rental activities are recognized ratably over the rental term which is generally less than six months. Mobilization fees received and related mobilization costs incurred, if significant, are deferred and amortized over the term of the related drilling contract.
Construction Contract - The Company has historically only constructed drilling rigs for its own use. At the request of one of its significant customers, the Company entered into a contract to design, construct, mobilize and sell (“construction contract”) a specialized drilling rig to drill extended-reach wells to offshore targets from a land-based location on Sakhalin Island, Russia, for an international consortium of oil and gas companies. Subsequently, the Company entered into a contract to operate the rig on behalf of the consortium. Generally Accepted Accounting Principles (“GAAP”) requires that revenues received and costs incurred related to the construction contract be accounted for and reported on a gross basis and income for the related fees recognized on a percentage-of-completion basis. Because this construction contract is not a part of the Company’s historical or normal operations, the revenues and costs related to this contract have been shown as a separate component in the statement of operations. Construction costs in excess of funds received from the customer are accumulated and reported as part of other current assets. This contract was completed during 2003 and there are no outstanding amounts in receivables at December 31, 2003.
Reimbursable Costs - The Company recognizes reimbursements received for out-of-pocket expenses incurred as revenues and accounts for out-of-pocket expenses as direct operating costs.
Cash and Cash Equivalents - For purposes of the consolidated balance sheet and the statement of cash flows, the Company considers cash equivalents to be highly liquid debt instruments that have a remaining maturity of three months or less at the date of purchase.
Accounts Receivable and Allowance for Doubtful Accounts - Trade accounts receivable are recorded at the invoice amount and generally do not bear interest. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The Company determines the allowance based on historical write-off experience. The Company reviews all past due balances over 90 days individually for collectibility. Account balances are charged off against the
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 1 - Summary of Significant Accounting Policies (continued)
allowance when the Company feels it is probable the receivable will not be recovered. The Company does not have any off-balance-sheet credit exposure related to customers.
(1)
Employee receivables related to cash advances for business expenses and travel.
(2)
Additional information on the allowance for doubtful accounts for the year ended December 31, 2004 and 2003 are reported on Schedule II - Valuation and Qualifying Accounts.
Property, Plant and Equipment - The Company provides for depreciation of property, plant and equipment 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 up to 15 years. The depreciable lives for certain other equipment, including drill pipe and rental tools, range from three to seven years. Depreciable lives for buildings and improvements range from 10 to 30 years. When properties are retired or otherwise disposed of, the related cost and accumulated depreciation are removed from the accounts and any gain or loss is included in operations. Management periodically evaluates the Company’s assets to determine 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 fair value if the fair value is below the 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 is assessed for impairment on at least an annual basis (see Note 3 in the notes to the consolidated financial statements for additional details regarding goodwill).
Rig Materials and Supplies - Since the Company’s international drilling generally occurs in remote locations, making timely outside delivery of spare parts uncertain, a complement of parts and supplies is maintained either at the drilling site or in warehouses close to the operation. During periods of high rig utilization, these parts are generally consumed and replenished within a one-year period. During a period of lower rig utilization in a particular location, the parts, like the related idle rigs, are generally not transferred to other international locations until new contracts are obtained because of the significant transportation costs, which would result from such transfers. The Company classifies those parts which are not expected to be utilized in the following year as long-term assets. Rig materials and supplies are valued at the lower of cost or market value, net of a reserve for obsolete parts of $6.5 million and $4.7 million at December 31, 2004 and 2003, respectively.
Deferred Costs - For the purpose of the consolidated balance sheet, the Company includes costs which are amortized over the life of the related asset or term of the related contract. The costs to be amortized within 12 months are classified as current.
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
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 1 - Summary of Significant Accounting Policies (continued)
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, 2004 and 2003, the fair value of equity securities totaled $0 and $1.5 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 Liabilities - Included in this account is the accrual of workers’ compensation liability, deferred tax liability and deferred compensation, 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.
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, 2004 and 2003, the Company had deposits in domestic banks in excess of federally insured limits of approximately $43.7 million and $64.3 million, respectively. In addition, the Company had deposits in foreign banks at December 31, 2004 and 2003 of $11.1 million and $8.7 million, respectively, which are not federally insured.
The Company’s customer base consists of major, independent and national-owned oil and gas companies and integrated service providers. For the fiscal year 2004, Tengizchevroil (“TCO”), a joint venture with four oil companies, was the largest customer with 13 percent of total revenues. Total revenues include discontinued operations.
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 has used derivative instruments to hedge exposure to interest rate risk. For hedges which meet the criteria of SFAS No. 133, the Company formally designates and documents the instrument as a hedge of a specific underlying exposure, as well as the risk management objective and strategy for undertaking each hedge transaction. For those derivative instruments that do not meet the criteria of a hedge, the Company recognizes the volatility of the derivative instruments on a mark-to-market basis in the statement of operations. See Note 6 in the notes to the consolidated financial statements.
Fair Value of Financial Instruments - The estimated fair value of the Company’s $155.6 million principal amount 10.125% Senior Notes due 2009, based on quoted market prices, was $163.4 million at December 31, 2004, compared to the carrying amount of $156.0 million (including premium). The estimated fair value of the Company’s $175.0 million principal amount 9.625% Senior Notes due 2013, based on quoted market prices, was $196.4 million at December 31, 2004, compared to a carrying value of $175.0 million. The Company estimates that its recently issued $150.0 million principal amount of Senior
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 1 - Summary of Significant Accounting Policies (continued)
Floating Rate Notes due 2010, which were not publicly traded at December 31, 2004, approximate fair value.
The fair value of the Company’s cash equivalents, trade receivables, and trade payables approximated their carrying values due the short-term nature of these instruments.
Stock-Based Compensation - The Company has elected the disclosure-only provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” and thus follows the provisions of Accounting Principles Board (“APB”) No. 25 “Accounting for Stock Issued to Employees” and related interpretations in accounting for its employee stock options. Accordingly, no compensation cost has been recognized for the Company’s stock option plans when the option price is equal to or greater than the fair market value of a share of the Company’s common stock on the date of grant. Pro forma net income 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. See Note 16 in the notes to the consolidated financial statements for the Company’s plan to adopt SFAS No. 123R.
The fair value of each option grant is estimated using the Black-Scholes option pricing model with the following assumptions:
Options granted in 2004, 2003 and 2002 under the 1997 Stock Plan had an estimated fair value of $0.4 million, $0.2 million and $1.8 million, respectively.
Accounting Estimates - The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Reclassification - Certain reclassifications have been made to prior year balances to conform to the current year presentation.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 2 - Disposition of Assets
Discontinued Operations - In June 2003, the Company’s board of directors approved a plan to sell its Latin America assets consisting of 17 land rigs and related inventory and spare parts and its U.S. Gulf of Mexico offshore assets consisting of seven jackup rigs and four platform rigs. At June 30, 2003, the net book value of the assets to be sold exceeded the estimated fair value and as a result, a $54.0 million impairment charge including estimated sales expenses was recognized. The two operations that constituted this plan of disposition met the requirements of discontinued operations under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Accordingly, the consolidated financial statements presented the Latin America operations and the U.S. jackup and platform drilling operations as discontinued operations in the Company’s 2003 Form 10-K. One of the rigs and related spare parts sold in 2003 for $1.8 million.
On September 11, 2003, a malfunction caused one side of jackup rig 14 to become partially submerged resulting in significant damage to the rig and the drilling equipment, but there were no fatalities. The Company received from its insurance underwriters a total loss settlement of $27.0 million, of which $24.3 million was received in March 2004 with the remaining $2.7 million received April, 2004. The cost incurred to tow the rig to the port and pay for the damage assessment approximated $4.0 million resulting in net insurance proceeds of approximately $23.0 million. The net book value of jackup rig 14 was $17.7 million at March 31, 2004. In compliance with GAAP, the Company was required to recognize the gain from the insurance proceeds in excess of the net book value of the asset. When considered separately from the other U.S. Gulf of Mexico offshore disposal group, this resulted in a gain of approximately $5.3 million from the damage to the rig. After considering the impact of the gain, the Company determined that the overall valuation of the U.S. Gulf of Mexico offshore group was unchanged from that determined on June 30, 2003, as previously discussed. As a result, the Company recognized an additional impairment of $5.3 million which, along with the gain, was reported in discontinued operations during the first quarter of 2004.
In early 2004, the board of directors concurred with the Company’s plan to actively market certain of the Latin America land rigs in Mexico. As a result, in early May 2004, a subsidiary of the Company was awarded two contracts in Mexico utilizing seven Latin America land rigs. Based on this change in plan, the seven land rigs moved to Mexico were reclassified from discontinued operations to continuing operations effective May 2004. In addition, the nine land rigs remaining in Latin America were reclassified from discontinued operations to continuing operations effective June 30, 2004. The reclassification was made based on the application of SFAS No. 144, which requires that unless assets classified as discontinued operations are either sold or have a firm commitment for sale within a one-year period, they should be reclassified to continuing operations. SFAS No. 144 further requires that assets returned to continuing operations be recorded at the lower of net book value or fair value, and that net book value be adjusted by the depreciation that would have been recognized as if the asset had remained classified as continuing operations. Based on the foregoing, the Company recognized an impairment of $5.1 million, during the second quarter of 2004, as a provision for reduction in carrying value of assets for the Latin America rigs.
On August 2, 2004, the Company finalized the sale of five jackup and four platform rigs, realizing net proceeds of $39.3 million. No gain or loss was recorded on the sale and the proceeds were used to pay down debt. Jackup rig 25 was excluded from this sale, although the purchaser retained the exclusive right to purchase it. On January 3, 2005, the Company sold jackup rig 25 to such purchaser. The Company received proceeds of $21.5 million and recognized an additional impairment on the disposition of $4.1 million in December 2004. With the completion of this transaction, all the jackup and platform rigs have been sold. No other assets remain related to the Company’s discontinued operations and all proceeds were used to pay down debt.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 2 - Disposition of Assets (continued)
The following table presents revenues and income (loss) related to the remaining disposal group:
Provision for Reduction in Carrying Value of Certain Assets - During 2004, the Company recognized a provision for reduction in carrying value of certain assets of $13.1 million. During the fourth quarter of 2004, the Company determined that two workover barge rigs in the U.S. Gulf of Mexico fleet were not economically marketable. As a result, the Company recorded an impairment of $3.2 million and will dispose of the two barge rigs. In the Asia Pacific region, the Company reduced the carrying amount of two rigs to net realizable value, which resulted in recording an impairment charge of $0.7 million. Also, during the fourth quarter of 2004, the Company made the decision to dispose of all assets in Bolivia, which included two land rigs, inventory and spare parts. The Company incurred an impairment charge of $2.4 million to reduce the cost basis of these assets to net realizable value. The Company expects to close the Bolivia office in the second quarter of 2005. During the second quarter of 2004, the Company reclassified its Latin America assets from discontinued operations to continuing operations and recognized a $5.1 million charge to adjust the value of the Latin America assets to their fair value. In addition, during 2004 the Company reserved $1.7 million for an asset representing premiums paid in prior years on two split dollar life insurance policies for Robert L. Parker. The value of the asset was reduced to the cash surrender value of the insurance policies (see Note 13 in the notes to the consolidated financial statements).
During 2003, the Company recognized a provision for reduction in carrying value of certain assets of $6.0 million. Three non-marketable rigs in the Asia Pacific region and certain spare parts and equipment in New Iberia, Louisiana were impaired by $2.6 million to estimated salvage value. Subsequent to December 31, 2003, the Company signed an agreement to sell the New Iberia, Louisiana land and buildings for a net sales price of $6.4 million. The sale was consummated in August 2004. This resulted in an impairment of $3.4 million at December 31, 2003, as the net book value of the property exceeded the net sales price.
Assets Held for Sale - In August 2004, the Company sold the buildings and substantially all of its land in New Iberia, Louisiana relating to its drilling operations. The net sales price of approximately $6.4 million, all of which has been received, did not require any addition to the impairment of $3.4 million recorded in December 2003. Under the terms of the sale, the Company leased back certain portions of the land and office building under a two-year operating lease agreement. The assets held for sale of $23.7 million at December 31, 2004 are mainly comprised of the estimated fair value of $0.7 million related to the Bolivia assets, jack up rig 25 at $21.5 million, the Company’s former headquarters in Tulsa, valued at $0.8 million and certain other equipment at $0.7 million.
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 is assessed for impairment on 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
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 3 - Goodwill (continued)
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 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 of 2002. No further impairment was indicated in reviews performed in December 2004 and 2003.
The following is a summary of the change in goodwill by reporting unit for the years ended December 31, 2002, 2003 and 2004:
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 4 - Long-Term Debt
The aggregate maturities of long-term debt for the five years ending December 31, 2009 are as follows: $0 for 2005-2008, $156.0 million for 2009 and $325.0 million thereafter.
On July 30, 2004, the Company drew down the remaining $50.0 million on the delay draw term loan portion of the credit agreement dated October 10, 2003. These funds, along with existing cash, were used to retire the existing $64.4 million of 5.5% Convertible Subordinated Notes on August 2, 2004. On the same day, August 2, 2004, proceeds from the sale of five jackup rigs and four platform rigs were used to pay down $25.0 million of the delay draw term loan. On August 5, 2004, an additional $5.0 million was paid on the delay draw term loan with proceeds from the sale of the Company’s New Iberia facilities, leaving an outstanding balance of $70.0 million on the delay draw term loan.
In September 2004, the Company refinanced a portion of its existing debt by issuing $150.0 million of Senior Floating Rate Notes due 2010. Proceeds were used to pay off the $70.0 million outstanding balance of the delay draw term loan and to retire $80.0 million of the 10.125% Senior Notes due 2009 that had been tendered pursuant to a tender offer dated August 6, 2004. Total proceeds of $150.0 million from this transaction were used to pay down debt. Cash costs associated with the transaction totaled $9.7 million and were paid from existing cash. Cash costs included an early tender premium of 2.00 percent and a tender offer consideration of 104.54 percent on the $80.0 million tendered 10.125% Senior Notes, as well as underwriting, legal and other fees associated with the issuance of the $150.0 million Senior Floating Rate Notes.
In December 2004, the Company replaced its existing $50.0 million credit facility with a new $40.0 million credit facility that expires in December 2007. The new revolving credit facility is secured by rental tools equipment, accounts receivable and substantially all of the stock of the subsidiaries, and contains customary affirmative and negative covenants.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 4 - Long-Term Debt (continued)
On February 7, 2005, the Company purchased an additional $25.0 million face value of its 10.125% Senior Notes due 2009 pursuant to a redemption notice dated January 6, 2005 at the redemption price of 105.0625 percent.
In October 2003, the Company refinanced $325.0 million of its existing debt. The total refinancing package was comprised of $175.0 million of 9.625% Senior Notes due 2013 and a new $150.0 million senior credit agreement. The senior credit agreement consisted of a four-year $100.0 million delay draw term loan facility and a three-year $50.0 million revolving credit facility. The proceeds of the 9.625% Senior Notes, plus an initial draw of $50.0 million under the term loan facility, were used to retire $184.3 million of the 9.75% Senior Notes due 2006 that had been tendered pursuant to a tender offer dated September 24, 2003. The balance was used to redeem the remaining 9.75% Senior Notes on November 15, 2003 at a call premium of 1.625 percent. As a result of the debt, the Company recorded $8.7 million of debt issuance cost which is being amortized over the term of the related debt. A charge of $5.3 million for loss on extinguishment of debt was incurred by the Company as a result of the debt refinancing.
The senior credit agreement consisted of a four-year $100.0 million delay draw term loan facility and a three-year $50.0 million revolving credit facility that was collateralized by certain drilling rigs, rental tools equipment, accounts receivable and substantially all of the stock of the subsidiaries, and contains customary affirmative and negative covenants. Initially, $50.0 million was drawn on the term loan facility and proceeds were used to retire a portion of the 9.75% Senior Notes. The remaining $50.0 million of delay draw term loan facility was utilized to repay the 5.5% Convertible Subordinated Notes in August 2004. The Company classified $50.0 million of the 5.5% Convertible Subordinated Notes as long term debt at December 31, 2003 because it intended to use the remaining $50.0 million of the delay draw term loan to retire a portion of the 5.5% Convertible Subordinated 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 for a like amount of its 9.75% Senior Notes due 2006, pursuant to an exchange offer described in the Offering Circular dated April 1, 2002 (“Exchange Offer”).
In connection with the Exchange Offer, the Company solicited consents to certain amendments to the definitions and covenants in the indenture under which the 9.75% Senior 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 9.75% Senior Notes, the amendments to the 1998 Indenture were agreed, and the 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.
In July 1997, the Company issued $175.0 million of Convertible Subordinated Notes due 2004. The notes bear interest at 5.5% payable semi-annually in February and August. The notes were convertible at the option of the holder into shares of common stock of Parker Drilling at $15.39 per share at any time prior to maturity. During the fourth quarter of 2000, the Company repurchased on the open market $50.5 million principal amount of the 5.5% notes. 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. During May 2003 and December 2003, the Company repurchased notes on the open market with a face value of $14.8 million and $4.5 million, respectively. The amount of outstanding notes at December 31, 2003 was $105.2 million. The Company repurchased $9.5 million of the outstanding notes in January 2004, $5.3 million in April 2004 and $25.0 million in May 2004 before paying off the remaining $64.4 million in August 2004.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 4 - Long-Term Debt (continued)
On October 7, 1999, a wholly-owned subsidiary of the Company entered into a loan agreement with Boeing Capital Corporation for the refinancing of a portion of the capital cost of barge rig 75. The loan principal of approximately $24.8 million plus interest was being repaid in 60 monthly payments of approximately $0.5 million. The loan was collateralized by barge rig 75 and was guaranteed by Parker Drilling. The amount of principal outstanding at the end of 2003 was $5.1 million. The Company paid the remaining portion of the note in February 2004 at a 5.0 percent premium.
For each of the Company’s Senior note offerings, exchange offers were effected without registration, in reliance on the registration exemption provided by Section 4(2) of the Securities Act of 1933, as amended, which applies to offers and sales of securities that do not involve a public offering, and Regulation D promulgated under that act. Subsequently, for each of the offerings, the Company filed a registration statement on Form S-4 offering to exchange the new notes for notes of the Company having substantially identical terms in all material respects as the outstanding notes. New notes and exchange notes are governed by the terms of the indentures executed by the Company, the Subsidiary Guarantors and the trustee. Each of the 10.125% and the 9.625% Senior Notes, the Senior Floating Rate Notes and the credit agreement contains customary affirmative and negative covenants, including restrictions on incurrence of debt, sales of assets and dividends. In addition, the credit agreement contains covenants which require minimum ratios for consolidated leverage, consolidated interest coverage and consolidated senior secured leverage.
Note 5 - Guarantor/ Non-Guarantor Consolidating Condensed Financial Statements
Set forth on the following pages are the unaudited consolidating condensed financial statements of (i) Parker Drilling, (ii) the Company’s restricted subsidiaries that are guarantors of the Senior Notes and (iii) the Company’s restricted and unrestricted subsidiaries that are not guarantors of the Senior Notes. All of the Company’s Senior Notes are guaranteed by substantially all of the restricted subsidiaries of Parker Drilling. There are currently no restrictions on the ability of the restricted subsidiaries to transfer funds to Parker Drilling in the form of cash dividends, loans or advances. Parker Drilling is a holding company with no operations, other than through its subsidiaries.
AralParker (a Kazakhstan closed joint stock company, owned 50 percent by Parker Drilling (Kazakstan) Ltd. and 50 percent by Aralnedra, CJSC), Casuarina Limited (a wholly-owned captive insurance company), KDN Drilling Limited, Mallard Drilling of South America, Inc., Mallard Drilling of Venezuela, Inc., Parker Drilling Investment Company, Parker Drilling (Nigeria), Limited, Parker Drilling Company (Bolivia) S.A., Parker Drilling Company Kuwait Limited, Parker Drilling Company Limited (Bahamas), Parker Drilling Company of New Zealand Limited, Parker Drilling Company of Sakhalin, Parker Drilling de Mexico S. de R.L. de C.V., Parker Drilling International of New Zealand Limited, Parker Drilling Tengiz, Ltd., Parker TNK, PD Servicios Integrales, S. de R.L. de C.V., PKD Sales Corporation, Parker SMNG Drilling Limited Liability Company (owned 50 percent by Parker Drilling Company International, Inc.) and Universal Rig Leasing B.V. are all non-guarantor subsidiaries. The Company is providing unaudited consolidating condensed financial information of the parent, Parker Drilling, the guarantor subsidiaries, and the non-guarantor subsidiaries as of December 31, 2004 and December 31, 2003 and for the twelve months ended December 31, 2004, 2003 and 2002. The condensed consolidating financial statements present investments in both consolidated and unconsolidated subsidiaries using the equity method of accounting.
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 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 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 BALANCE SHEET
(Dollars in Thousands)
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
(Dollars in Thousands)
PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
(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 entered into two variable-to-fixed interest rate swap agreements as a strategy to manage the floating rate risk on the $150.0 million Senior Floating Rate Notes. The first agreement, signed on August 18, 2004, fixed the interest rate on $50.0 million at 8.83% for a three-year period beginning September 1, 2005 and terminating September 2, 2008 and fixed the interest rate on an additional $50.0 million at 8.48% for the two-year period beginning September 1, 2005 and terminating September 4, 2007. In each case, an option to extend each swap for an additional two years at the same rate was given to the issuer, Bank of America, N.A. The second agreement, signed on September 14, 2004, fixed the interest rate on $150.0 million at 6.54% for the three-month period beginning December 1, 2004 and terminating March 1, 2005. Options to extend $100.0 million at a fixed interest rate of 7.08% for the six-month period beginning March 1, 2005 and to extend $50.0 million at a fixed interest rate of 7.60% for the 18-month period beginning March 1, 2005 and terminating September 1, 2006 were given to the issuer, Bank of America, N.A. Subsequent to year end, Bank of America, N.A. allowed these options to expire unexercised.
These swap agreements do not meet the hedge criteria in SFAS No. 133 and are, therefore, not designated as hedges. Accordingly, the change in the fair value of the interest rate swaps is recognized currently in earnings. As of December 31, 2004, the Company had the following derivative instruments outstanding related to its interest rate swaps:
Note 7 - Income Taxes
Income (loss) before income taxes, discontinued operations and cumulative effect of change in accounting principle is summarized below:
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 7 - Income Taxes (continued)
Income tax expense (benefit) related to continuing operations are summarized as follows:
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:
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 7 - Income Taxes (continued)
The components of the Company’s deferred tax assets and (liabilities) as of December 31, 2004 and 2003 are shown below:
The total change in the valuation allowance of $37.1 million is made up of $12.2 million current increase in the valuation allowance. The remainder is due mainly to changes in deferred tax liabilities resulting from asset sales planned in 2003 which were not realized. The Company has a remaining valuation allowance of $56.0 million with respect to its net deferred tax asset for the amount of net operating loss carryforwards which are more likely than not to expire unused. The amount of the asset considered realizable could be different in the near term if estimates of future taxable income change.
At December 31, 2004, the Company had $184.3 million 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 - $9.3 million; 2008 - $12.0 million; 2009 - $6.7 million; thereafter - $156.3 million.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders’ Equity
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. As of December 31, 2004, there were 569,000 shares available for granting.
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 Securities and Exchange Commission (“SEC”). As of December 31, 2004, there were 1,247,189 shares available for granting. The Company issued 755,000 restricted shares in July 2003 to selected key personnel, of which 37,500 shares have reverted back to the Company. During March 2004, 377,500 shares vested after the closing stock price of $3.50 was met for 30 consecutive days resulting in $1.0 million in expense. Subsequent to December 31, 2004, the remaining 340,000 shares vested in March 2005 after the closing stock price of $5.00 was met for 30 consecutive days which will result in an expense of $0.7 million. This expense will be recognized during the first quarter of 2005.
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)
The Company has one additional stock plan, the Parker Drilling and Subsidiaries 1991 Stock Grant Plan, which provides for the issuance of stock for no cash consideration to officers and key non-officer employees. This plan provides that stock grants may vest no earlier than 24 months from the effective date of each grant and not later than 36 months. The plan has a total of 1,562,195 shares reserved and available for granting. A grant of 25,000 shares was awarded in June 2004 and then the award was cancelled in
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 8 - Common Stock and Stockholders’ Equity (continued)
November 2004. The granted shares were returned to shares available for granting. No shares were granted under this plan in 2003 and 2002.
The Company had 660,389 and 506,577 shares held in Treasury stock at December 31, 2004 and 2003, respectively.
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)
For the year ended December 31, 2004, options to purchase 7,754,654 shares of common stock at prices ranging from $1.960 to $12.188, which were outstanding during the period, were not included in the computation of diluted EPS because the assumed exercise of the options would have had an anti-dilutive effect on EPS due to the net loss incurred for 2004. For the fiscal year ended December 31, 2003, options to purchase 9,804,809 shares of common stock at prices ranging from $1.960 to $12.188, which were outstanding during the period, were not included in the computation of diluted EPS because the assumed exercise of the options would have had an anti-dilutive effect on EPS due to the net loss during 2003. For the fiscal year ended December 31, 2002, options to purchase 9,609,810 shares of common stock at prices ranging from $2.24 to $12.188, which were outstanding during the period, were not included in the computation of diluted EPS because the assumed exercise of the options would have had an anti-dilutive effect on EPS due to the net loss during 2002. At December 31, 2003, the Company had outstanding $105,169,000 of 5.5% Convertible Subordinated Notes which were convertible into 6,833,593 shares of common stock at $15.39 per share. The notes were outstanding since their issuance in July 1997 but were not included in the computation of diluted EPS because the assumed conversion of the notes would have had an anti-dilutive effect on EPS. All of the outstanding 5.5% Convertible Subordinated Notes were retired on August 2, 2004.
Note 10 - Employee Benefit Plans
The Parker Drilling Company Stock Bonus Plan (“Plan”) was originally adopted effective September 1980 for eligible employees of the Company 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. It was thereafter amended effective January 1, 2002 to reflect certain provisions of the Economic Growth and Tax Relief Reconciliation Act of 2001 (“EGTRRA”). The Plan was further amended effective January 1, 2003 to comply with new tax
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 10 - Employee Benefit Plans (continued)
laws and again amended effective November 1, 2003 to incorporate various plan design and administrative changes. Participants may contribute from one percent to 30 percent of eligible earnings and direct contributions to one or more of 12 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 402,760; 627,732; and 544,844 shares to the Plan in 2004, 2003 and 2002 with the Company recognizing expense of $1.4 million; $1.7 million; and $1.6 million in each of the periods, respectively.
Parker Drilling Company Limited (“PDCL”), a wholly-owned subsidiary of the Company, had a deferred compensation plan (“Compensation Plan”) of certain designated non-resident alien employees of PDCL and its affiliates. The Compensation Plan was terminated in 2004. The Compensation Plan was valued at $1.8 million when terminated in 2004 and $1.7 million as of December 31, 2003, respectively. The Company recognized expense of $0.3 million; $0.2 million; and $0.5 million in each of the years ending December 31, 2004, 2003 and 2002. As of December 31, 2004, the Company had no deferred compensation plan.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 11 - Business Segments
The Company is organized into three primary business segments: U.S. drilling operations, international drilling operations, and rental tools. This is the basis management uses for making operating decisions and assessing performance.
(1)
International drilling segment includes $55.2 million in revenues from Tengizchevroil (“TCO”), the Company’s largest customer, for the year ended December 31, 2004.
(2)
Drilling and rental operating income - drilling and rental revenues less direct drilling and rental operating expenses, including depreciation and amortization expense.
(3)
Includes assets related to discontinued operations.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 11 - Business Segments (continued)
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 11 - Business Segments (continued)
(1)
Includes assets related to discontinued operations.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 12 - Commitments and Contingencies
At December 31, 2004, the Company had a $40.0 million revolving credit facility available for general corporate purposes and to support letters of credit. As of December 31, 2004, $15.3 million of availability has been reserved to support letters of credit that have been issued and $0.8 million of availability was reserved for the mark-to-market value of variable-to-fixed interest rate swap agreements relating to the Senior Floating Rate Notes. At December 31, 2004, 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, 2004, under operating leases with non-cancelable terms are as follows (dollars in thousands):
Total rent expense for all operating leases amounted to $9.3 million for 2004, $10.3 million for 2003, and $10.9 million for 2002.
The Company is self-insured for certain losses relating to workers’ compensation, employers’ liability, general liability (for onshore liability), protection and indemnity (for offshore liability) and property damage. The Company’s exposure (that is, the retention or deductible) per occurrence is $250,000 for worker’s compensation, employer’s liability, general liability, protection and indemnity and maritime employers’ liability (Jones Act). In addition, the Company assumes a $750,000 annual aggregate deductible for protection and indemnity and maritime employers’ liability claims. The annual aggregate deductible is eroded by every dollar that exceeds the $250,000 per occurrence retention. The Company continues to assume a straight $250,000 retention for workers’ compensation, employers’ liability, and general liability losses. The self-insurance for automobile liability applies to historic claims only as we are currently on a first dollar policy, with those reserves being minimal. For all primary insurances mentioned above, the Company has excess coverage for those claims that exceed the retention and annual aggregate deductible. The Company maintains actuarially-determined accruals in its consolidated balance sheets to cover the self-insurance retentions.
The Company has self-insured retentions for certain other losses relating to rig, equipment, property, business interruption and political, war, and terrorism risks which vary according to the type of rig and line of coverage. Political risk insurance is procured for international operations. There is no assurance that such coverage will adequately protect the Company against liability from all potential consequences.
As of December 31, 2004, the Company’s gross self-insurance accruals for workers’ compensation, employers’ liability, general liability, protection and indemnity and maritime employers’ liability totaled $7.4 million and the related insurance recoveries/receivables were $1.8 million.
Each of the executive officers entered into an employment agreement with the Company, each of which became effective during 2002, with the exception of Mr. Mannon’s and Mr. Potter’s which became effective in December 2004 and June 2003, respectively. The term of each agreement is for three years and each provides for automatic extensions of two years, with the exception of Mr. Brassfield and Mr. Graham, whose agreements are for two years and provide for an automatic extension of two years, Mr. Potter, whose agreement is for two years with automatic extensions of one year, and Mr. Robert L.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 12 - Commitments and Contingencies (continued)
Parker whose agreement is for one year with automatic extensions of one year. The employment agreements provide for the following benefits:
•
payment of current salary, which may be increased upon review by the chief executive officer (or the board of directors in case of the chief executive officer and Chairman) on an annual basis but cannot be reduced except with consent of the executive;
•
payment of target bonuses of up to 100 percent of salary based on meeting certain incentives (75 percent for Mr. Mannon and Mr. Whalen and 50 percent for Mr. Brassfield and Mr. Graham and 30 percent for Mr. Potter); and
•
eligible to receive stock options, stock grants 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. Graham whose payment will be based on a 1.5 times multiplier and Mr. Potter, whose payment will be based on a one time multiplier (“Additional Benefit”); and
•
continued health benefits for two years, except for Mr. Brassfield and Mr. Graham who will receive these benefits for 1.5 years and Mr. Potter who will receive these benefits for one year (“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 Company is a party to various lawsuits and claims arising out of the ordinary course of business. Management, after review and consultation with legal counsel, considers that any liability resulting from these matters would not materially affect the results of operations, the financial position or the net cash flows of the Company.
As previously reported, the Kazakhstan branch (“PKD Kazakhstan”) of Parker Drilling Company International Limited (“PDCIL”) prevailed on its appeal arising out of an audit assessment of
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 12 - Commitments and Contingencies (continued)
approximately $29.0 million by the Ministry of State Revenues of Kazakhstan (“MSR”) based on payments PDCIL received from the operator to upgrade barge rig 257. The MSR did not appeal this ruling within the time required for a supervisory appeal, but in February 2005 filed an application for re-consideration based on new evidence, which new evidence was allegedly obtained pursuant to an audit of the operator who paid PDCIL for the upgrades and which audit revealed that the operator intends to claim this expenditure under cost oil. PKD Kazakhstan has filed an objection to this application for re-hearing. If the court determines to hear the application then PKD Kazakhstan intends to make a request for postponement of the hearing until the Competent Authority proceedings are completed as discussed below.
In a related matter, based on its interpretation of the initial ruling of the Kazakhstan Supreme Court, the Ministry of Finance of Kazakhstan (“MinFin”) made a claim on March 10, 2003 for corporate income taxes based primarily on the disallowance of depreciation of the full value of barge rig 257 in the income tax returns of PKD Kazakhstan in 1999-2001. PKD Kazakhstan instituted legal proceedings to challenge the validity of these claims by MinFin, which ultimately resulted in the Supreme Court confirming the decision of the Astana City Court, which earlier had ruled that approximately $7.7 million of the claims of MinFin are valid and payable upon receipt of the re-issuance of the corrected notice from the relevant taxing authority. The actual amount which PKD Kazakhstan will ultimately be required to pay, which was expensed in prior periods, will be reduced by available credits. MinFin has not issued a corrected notice; however, PKD Kazakhstan’s available credits were reduced by approximately $7.1 million leaving a remaining balance due of $0.7 million. While the Supreme Court disallowed depreciation for the years 1999-2001, the judgment does allow PKD Kazakhstan to depreciate the full value of barge rig 257 on its tax returns beginning in 2002, which will reduce taxable income and taxes to be paid in the future.
The Company continues to pursue its petition with the U.S. Treasury Department for Competent Authority review, which is a tax treaty procedure to resolve disputes as to which country may tax income covered under the treaty. The U.S. Treasury Department has granted the Company’s petition and has initiated proceedings with the MSR which are ongoing.
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, 2004, 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-
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 13 - Related Party Transactions (continued)
Oxley Act of 2002 (“SOX ACT”), additional loans to executive officers and directors may be prohibited, although continuance of loans in existence as of July 30, 2002, are allowed provided there is no material modification to such loans. Because the advancement of additional annual premiums by the Company may be considered a prohibited loan under the SOX ACT, the Company elected to not advance the annual premiums that were due in December 2002, 2003 and 2004 pending further clarification from the SEC as to how the Company’s obligation to advance these premiums under the Agreement can be honored without violating the SOX ACT. An analysis of the policies by a financial consultant indicated there is no reasonable certainty that the value of the policies will be adequate for the Company to recoup the full amount of premiums therefore during the year, the Company reduced the value of its asset by $1.7 million, to the cash surrender value of the insurance policies.
Robert L. Parker, chairman of the board and director of the Company, through the Robert L. Parker, Sr. Family Limited Partnership (the “Limited Partnership”) owns a 2,987 acre ranch near Kerrville, Texas, (the “Cypress Springs Ranch”) and a 4,982 acre ranch in Mazie, Oklahoma (the “Mazie Ranch”). The Cypress Springs Ranch has lodging, conference facilities, sporting and other outdoor activities which the Company utilized in connection with marketing and other business purposes during 2004. The Mazie Ranch has hunting, fishing and other outdoor facilities. Effective as of January 1, 2004, the Company and the Limited Partnership entered into a Lease Agreement pursuant to which the Company pays the Limited Partnership a monthly fee in exchange for unlimited access to the facilities of the Limited Partnership at the Cypress Springs Ranch and the Mazie Ranch. During 2004, the Company paid the Limited Partnership a total of $0.4 million in lease fees. The Limited Partnership also entered into a Services Agreement with the Company effective as of January 1, 2004, pursuant to which the Company provides certain personnel to the Limited Partnership to maintain the Cypress Springs Ranch and the Mazie Ranch. During 2004, the Limited Partnership paid the Company a total of $0.2 million for the provision of such personnel.
Robert L. Parker Jr., president and chief executive officer and director of the Company owns a 1,400 acre ranch near Kerrville, Texas (the “Camp Verde Ranch”). The Camp Verde Ranch has lodging as well as hunting, fishing and other outdoor facilities. Effective January 1, 2004, the Company entered into a Lease Agreement pursuant to which the Company pays Robert L. Parker Jr. a monthly fee in exchange for unlimited access to the Camp Verde Ranch facilities. During 2004, the Company paid Robert L. Parker Jr. a total of $0.1 million in lease fees. Mr. Parker Jr. also entered into a Services Agreement with the Company effective as of January 1, 2004, pursuant to which the Company provides certain personnel to Mr. Parker Jr. to maintain the Camp Verde Ranch. During 2004, Mr. Parker Jr. paid the Company a total of $41 thousand for the provision of such personnel.
During the majority of 2004, one of the Company’s directors held the position of president and chief executive officer of Halliburton Energy Services Group (“HES”). During 2004, subsidiaries of the Company received $31.4 million in gross revenues for performance of drilling services from subsidiaries of HES.
Note 14 - Supplementary Information
At December 31, 2004, accrued liabilities included $7.0 million of accrued interest expense, $5.7 million of workers’ compensation and health plan liabilities and $14.4 million of accrued payroll and payroll taxes. At December 31, 2003, accrued liabilities included $9.4 million of accrued interest expense, $4.0 million of workers’ compensation and health plan liabilities and $9.4 million of accrued payroll and payroll taxes. Other long-term obligations included $3.3 million and $4.4 million of workers’ compensation liabilities as of December 31, 2004 and 2003, respectively.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 15 - Selected Quarterly Financial Data
(1)
As a result of shares issued during the year, earnings per share for the year’s four quarters, which are based on weighted average shares outstanding during each quarter, do not equal the annual earnings per share, which is based on the weighted average shares outstanding during the year.
(2)
Operating income and net loss includes a $13.1 million provision for reduction in carrying value of certain assets in 2004; $6.5 million and $6.6 million in the second and fourth quarters, respectively.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 15 - Selected Quarterly Financial Data (continued)
(1)
As a result of shares issued during the year, earnings per share for the year’s four quarters, which are based on weighted average shares outstanding during each quarter, do not equal the annual earnings per share, which is based on the weighted average shares outstanding during the year.
(2)
Operating income and net loss includes a $6.0 million provision for reduction in carrying value of certain assets.
Note 16 - Recent Accounting Pronouncements
In November 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 151, “Inventory Costs - An Amendment of Accounting Research Bulletin (“ARB”) No. 43, Chapter 4.” SFAS No. 151 clarifies the accounting for idle facility expense, freight, handling costs and wasted material to require that all of the aforementioned items be recognized as current period costs. ARB No. 43 previously required that these items reach a level of abnormality before they were expensed. SFAS No. 151 eliminates the “abnormality” requirement and establishes current period recognition. SFAS No. 151 will become effective for the Company beginning with the calendar year 2006. The adoption of this standard should not have a significant impact on the Company’s financial position, results of operations or cash flows.
In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets - an Amendment of Accounting Principles Board (“APB”) Opinion No. 29.” Under APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” the fundamental premise was that exchanges of nonmonetary assets should be measured based on the fair value of the assets exchanged. There was, however, an exception that allowed the exchange of similar productive assets to be recorded on a carryover basis of the original asset. This standard eliminates this exception and replaces it with a general exception that allows for a carryover basis only for exchanges that do not have commercial substance. A nonmonetary exchange is considered to have commercial substance if the entity’s future cash flows are expected to change as a result of the exchange. SFAS No. 153 will become effective for the Company’s for nonmonetary transactions entered into beginning with the calendar year 2006. The Company does not anticipate that the statement will have significant effect on the financial position, results of operations or cash flows.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)
Note 16 - Recent Accounting Pronouncements (continued)
Also in December 2004, the FASB revised SFAS No. 123, “Accounting for Stock Based Compensation” through issuance of SFAS No. 123R. SFAS No. 123R eliminates the alternative under the original statement to account for situations in which an entity compensates employees with share-based payments using the intrinsic value method established in APB Opinion No. 25. SFAS No. 123R requires that all such transactions be accounted for using the fair value method. The Company plans to adopt SFAS No. 123R on July 1, 2005 using the modified prospective method without restatement of prior interim periods of the current fiscal year. The impact of adopting SFAS No. 123R will be to record expense for previously-issued but unvested employee stock options and any employee stock options that the Company issues in the future. The Company expects the dollar impact on the financial statements to be consistent with the impact disclosed in Note 1 in the notes to the consolidated financial statements.
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 SEC only if the Company had changed independent auditors and, if it had, only under certain circumstances.
ITEM 9A.
ITEM 9A.
CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures - The Company’s management, under the supervision and with the participation of our chief executive officer and chief financial officer, has evaluated the effectiveness of the Company’s disclosure controls and procedures (as such term is defined in Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of December 31, 2004. Based on such evaluation, our chief executive officer and chief financial officer have concluded that, as of December 31, 2004, the disclosure controls and procedures were effective in recording, processing, summarizing and reporting information required to be disclosed in the reports that the Company files or submits under the Exchange Act within the time periods specified in the SEC’s rules and forms.
Changes in Internal Control over Financial Reporting - There were no changes in the Company’s internal control over financial reporting during the quarter ended December 31, 2004 that have materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting - The Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Because of its inherent limitations, internal control over financial reporting may not prevent or detect material misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. The Company’s management, under the supervision and with the participation of our chief executive officer and chief financial officer assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on that assessment and those criteria, management believes that the Company maintained effective internal control over financial reporting as of December 31, 2004. Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004 has been audited by PricewaterhouseCoopers, LLP, an independent registered public accounting firm, as stated in their report that is included herein.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
None.
PART III
ITEM 10.
ITEM 10.
DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information with respect to directors can be found under the captions “Item 1 - Election of Directors” and “Board of Directors” of the Company’s 2005 Proxy Statement. Such information is incorporated herein by reference.
Information with respect to executive officers is shown in Item 4A of this report on Form 10-K.
Information with respect to the Company’s audit committee and audit committee financial expert can be found under the caption, “The Audit Committee” in the Company’s 2005 Proxy Statement and is incorporated herein by reference.
The information in the Company’s 2005 Proxy Statement set forth under the caption: “Section 16(a) Beneficial Reporting Compliance” is incorporated herein by reference.
The Company has adopted the Parker Drilling Code of Corporate Conduct (“CCC”) which includes a code of financial ethics that is applicable to the chief executive officer, chief financial officer, controller and other senior financial personnel as required by the SEC and the NYSE corporate governance listing standards. The CCC is publicly available on the Company’s Web site at http://www.parkerdrilling.com. If any waivers of the CCC occur that apply to a director, the chief executive officer, the chief financial officer, the controller or senior financial personnel or if the Company amends the CCC, the Company will disclose the nature of the waiver or amendment on the web site and in a report on Form 8-K.
ITEM 11.
ITEM 11.
EXECUTIVE COMPENSATION
The information under the captions “Executive Compensation” and “Director Compensation” in the Company’s 2005 Proxy Statement is incorporated herein by reference. Notwithstanding the foregoing, in accordance with the instructions to Item 402 of Regulations S-K, the information contained in the Company’s 2005 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.
EQUITY OWNERSHIP OF OFFICERS, DIRECTORS AND PRINCIPAL STOCKHOLDERS
The information required by this item is hereby incorporated by reference from the information appearing under the captions “Equity Ownership of Officers, Directors and Principal Stockholders” and “Equity Compensation Plan Information” in the Company’s 2005 Proxy Statement .
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 “Certain Relationships and Related Party Transactions” in the Company’s 2005 Proxy Statement.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this item is hereby incorporated by reference from the information appearing under the caption “Audit and Non-Audit Fees” and “Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent Accountant” in the Company’s 2005 Proxy Statement.
PART IV
ITEM 15.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as part of this report:
(1) Financial Statements of Parker Drilling Company and subsidiaries which are included in Part II, Item 8:
(2)
Financial Statement Schedule:
(3) Exhibits:
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (continued)
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES (continued)
*
Management Contract, Compensatory Plan or Agreement
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 hereunto duly authorized.
PARKER DRILLING COMPANY
By:
/s/ Robert L. Parker Jr.
Robert L. Parker Jr.
President and Chief Executive Officer and Director
Date: March 14, 2005
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.
Exhibit Index
*
Management Contract, Compensatory Plan or Agreement