PARKER DRILLING CO /DE/ - 10-K Annual Report

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

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

Indicate by check mark whether the agreement is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes [X] No [ ]

The aggregate market value of our common stock held by non-affiliates on June 30, 2003 was $258.9 million. At January 31, 2004, there were 94,176,081 shares of common stock issued and outstanding.

Portions of our definitive proxy statement for the 2004 annual meeting of shareholders are incorporated by reference in Part III.

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

	•		prices and demand for oil and natural gas;

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

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

	•		our future operating results;

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

	•		our future capital expenditures and investments in the acquisition and refurbishment of rigs and equipment;

	•		our future liquidity;

	•		availability and sources of funds to reduce our debt;

	•		future sales of our assets;

	•		the outcome of pending and future legal proceedings;

	•		our recovery of insurance proceeds in respect to our damaged rigs in Nigeria and the Gulf of Mexico;

	•		maintenance of the borrowing base and compliance with other covenants under our credit facilities; and

	•		expansion and growth of our operations.

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

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

	•		the pace and duration of recovery in the U.S. economy and the demand for natural gas;

	•		fluctuations in the market prices of oil and gas;

	•		imposition of unanticipated trade restrictions and political instability;

	•		unanticipated operating hazards and uninsured risks;

	•		political instability, terrorism or war;

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

	•		adverse environmental events;

	•		adverse weather conditions;

	•		changes in concentration of customer and supplier relationships;

	•		unexpected cost increases for upgrade and refurbishment projects;

	•		unanticipated cancellation of contracts by operators without cause;

	•		breakdown of equipment and other operational problems;

	•		changes in competition; and

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

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

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, or on the Securities and Exchange Commission website at www.sec.gov, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports as soon as reasonably practicable after we electronically file such material with, or furnish to, the Securities and Exchange Commission.

We are a leading worldwide provider of contract drilling and drilling-related services. Since beginning operations in 1934, we have operated in 50 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 core international land drilling operations are focused primarily in the Commonwealth of Independent States (former Soviet Union referred to herein as “CIS”) and the Asia Pacific region. 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 the Caspian Sea.

	•		Our core U.S. drilling operations are comprised of barge drilling in the transition zones of the 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 in the Gulf of Mexico, West Texas and Rocky Mountain regions.

We also manage and provide labor resources for drilling rigs owned by third parties, which are generally oil companies that prefer to own the rig equipment but do not have the technical expertise or labor resources to operate the rig.

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, 2003, our fleet of rigs available for service consisted of:

	•		six land rigs in the CIS, which include premium and specialized deep drilling rigs capable of drilling to depths from 10,000 feet to in excess of 25,000 feet;

	•		two land rigs in the CIS, which are owned by AralParker, a joint venture in which we own a 50 percent interest, both of which are capable of drilling to depths of over 25,000 feet;

	•		12 land rigs in the Asia Pacific region and two land rigs in Africa;

	•		four barge drilling rigs in the transition zone waters of Nigeria;

	•		the world’s largest arctic-class barge rig in the Caspian Sea; and

	•		21 barge drilling and workover rigs in the transition zones of the Gulf of Mexico, consisting of nine deep drilling barge rigs, five intermediate drilling barge rigs and seven workover and shallow drilling barge rigs.

In addition to the fleet of rigs we own that are available for service, we also own non-core assets that are held for sale. As of December 31, 2003, our fleet of rigs held for sale consisted of six shallow-water jackup rigs and four offshore platform rigs located in the Gulf of Mexico and 16 land rigs and related inventory and spare parts located in Latin America. We have classified these non-core assets as assets held for sale and their related operations as discontinued operations. Pending their sale, we are actively seeking to contract these assets and maximize revenues from their utilization.

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 and an 8,000 square foot facility on nearly 10-acres in Odessa, Texas, to serve a growing oil and gas market in that region. The newest location, in Evanston, Wyoming, opened in the summer of 2002. Quail Tools’ principal customers are major and independent oil and gas exploration and production companies operating in the Gulf of Mexico, West Texas and Rocky Mountain regions.

Our core operations are subject to different 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, we believe that 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 which typically are major, large independent or foreign national oil companies; (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. Utilization and dayrates typically move in conjunction with oil and gas prices. If gas prices remain above historical averages, we believe there should be increased exploration and development drilling activity in the U.S. Gulf of Mexico in 2004. In addition, the United States government has provided incentives for operators to develop deeper gas reserves. We believe that these incentives will benefit the utilization of our barge rigs that are capable of drilling deep gas wells, as well as our rental tools business.

Our strategy is to maintain our position as a leading worldwide provider of contract drilling and drilling-related services and U.S. rental tools while we seek to return to profitability. Key elements in implementing our strategy include:

Significantly Reducing Our Debt and Enhancing Our Liquidity. In January 2003, we announced our goal of reducing debt by approximately $200 million and stated we would accomplish this goal by using cash currently on hand, cash generated from operations and cash generated by asset sales. During 2003, we used some of our existing cash and cash flows to repay debt. We purchased $19.3 million of our 5.5% Convertible Subordinated Notes in the open market and paid down our secured promissory note to Boeing Capital Corporation by $5.5 million. During January 2004 we purchased an additional $9.5 million of our 5.5% Convertible Subordinated Notes and in February 2004 we paid off the remaining Boeing Capital Corporation note which had a balance of $5.1 million at December 31, 2003. The 5.5% Convertible Subordinated Notes have an outstanding balance of $95.7 million after giving effect to the January 2004 purchase.

We continue to actively pursue the sale of our non-core assets to further enhance our debt reduction capabilities. We wrote down these assets to their estimated fair value in the second quarter of 2003. These assets, including related inventory, had a carrying value of approximately $143.5 million as of December 31, 2003. We may also seek to sell other assets to achieve this goal or to redirect our emphasis in more strategic areas.

During October 2003, we completed a refinancing of a portion of our debt. The total refinancing package was for $325.0 million comprised of $175.0 million of 9.625% Senior Notes due 2013 and the replacement of our senior credit facility with a $100.0 million delayed draw term loan facility and a $50.0 million revolving credit facility. Proceeds from the refinancing were used to retire in full the outstanding $214.2 million of our 9.75% Senior Notes due 2006. We believe these transactions have provided adequate financial flexibility to pursue asset sales in a very determined, but conservative fashion. The transactions have neither reduced our resolve to successfully complete asset sales, nor modified our January 2003 goal to reduce debt by $200 million.

We believe that our liquidity will be sufficient to repay our 5.5% Convertible Subordinated Notes on their stated maturity in August 2004. As of December 31, 2003, after giving pro forma effect to the January and February debt reductions described above, we have approximately $137.3 million of liquidity. This liquidity is comprised of $53.2 million of cash on hand (reduced by $14.6 million of our payments subsequent to year-end), $34.1 million of undrawn availability under our new revolving credit facility and $50.0 million of availability under our new delayed draw term loan. The remaining $50.0 million of delayed draw term loan facility may only be utilized to repay the 5.5% Convertible Subordinated Notes.

Increasing the Utilization of Our Barge and Land Rigs. One of our strategic objectives is to increase the utilization of our barge and land rigs, which has been at historically low levels for the past two years. To achieve this objective we have restructured and continue to position the regional management and marketing personnel closer to our customers’ key decision makers and each operating region is accountable for its profitability. We have also revised the compensation structure for many of our managers and marketing personnel to provide them with incentives directly related to the profitability of their operating region.

Controlling Our Costs and Minimizing Our Capital Expenditures. We continue to be vigilant in our efforts to conserve cash by reducing our general and administrative expenses and limiting our capital expenditures. We decreased general and administrative expenses in 2003 to $19.3 million from $24.7 million in 2002 by reducing our corporate workforce in 2002 and by limiting administrative costs. Our capital expenditure program calls for limiting expenditures to scheduled ongoing maintenance projects, our preventive maintenance program and capital projects that we believe have the potential to yield an attractive rate of return. As a result, our capital expenditures for 2003 were $35.0 million.

Pursuing Strategic Growth Opportunities. We intend to pursue selective strategic growth opportunities in our drilling and rental tools operations after we complete a significant portion of our planned debt reduction and sales of selected assets.

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 14 countries and have operated in 50 foreign countries and the United States since our founding in 1934, making us among the most geographically diverse drilling contractors in the world. As of December 31, 2003, our core international land drilling operations focus primarily on the CIS, where we have eight land rigs and the Asia Pacific region, where we have 12 land rigs, including seven helicopter transportable rigs. Our international offshore drilling operations focus on the transition zones of Nigeria, where we have four barge rigs, and the Caspian Sea. We own and operate the world’s largest arctic-class barge rig in the Caspian Sea. We also have 21 drilling and workover barges in the transition zones of the 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. 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 this market.

Strong Market Position in the Transition Zones of the Gulf of Mexico. We are one of only two drilling companies with a significant presence in the transition zones of the Gulf of Mexico. This area historically has been the world’s largest market for shallow-water barge drilling, but in recent months barge utilization and dayrates have been depressed despite relatively strong natural gas prices. With 21 drilling and workover barges devoted to this market, we believe that we are well positioned to take advantage of opportunities as this market recovers.

High Margin 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’ principal customers are 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.

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. Our safety record 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.

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 operated under the AralParker joint venture), one rig in Russia and two rigs in Turkmenistan. The two rigs in Turkmenistan are the result of a three-year contract signed with Calik Enerji A.S. to work for the Turkmenneft State Concern and is our first entry into this country. Operations for the first rig began during the fourth quarter of 2003 and operations for the second rig will begin during the first quarter of 2004.

As of December 31, 2003, we have 12 land rigs located in the Asia Pacific region including rig 255 which began operations in Bangladesh during the fourth quarter of 2003 and two land rigs in Africa. Included are seven helicopter transportable rigs which facilitate exploration in areas of difficult access, like the mountainside and jungle terrain of Indonesia and Papua New Guinea.

Our international barge drilling operations are focused in the transition zones of Nigeria 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. Although commodity prices also affect demand for international drilling, international markets typically are more attractive than U.S. markets because the increased capital and equipment requirements usually allow contractors to secure longer-term contracts and higher dayrates when compared with drilling operations in the U.S. Gulf of Mexico.

We are a leading provider of barge rigs in Nigeria, with four of the eight rigs in this market. We have operated in Nigeria since 1996. During 2003, significant community unrest in Nigeria resulted in suspensions of drilling operations on two of our working rigs and currently one barge rig remains evacuated. We also own and operate the world’s largest arctic-class barge rig in the Caspian Sea. This rig completed its initial four-year contract in November 2003 and is currently being marketed within the region.

The U.S. market for our barge drilling rigs is the transition zones of the Gulf of Mexico, primarily in Louisiana and, to a lesser extent, Alabama and Texas. This area historically has been the world’s largest market for shallow-water barge drilling. With 21 drilling and workover barges, we are one of two companies with a significant presence in this market.

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. Drilling operations under a five-year operations and maintenance contract with this customer commenced in June 2003. As of December 31, 2003, we were actively managing drilling rigs owned by third parties in Russia, Kazakhstan, Kuwait and China.

The contract drilling industry is a competitive and cyclical business characterized by high capital requirements and difficulty in finding and retaining qualified field personnel.

In the Gulf of Mexico barge drilling and workover markets, we compete with one major contractor. In international land markets, we compete with a number of international drilling contractors but also with smaller local contractors in certain markets like Indonesia. However, due to the high capital costs of operating in international land markets as compared to the U.S. land market, the high cost of mobilizing land rigs from one country to another, and the technical expertise required, there are usually fewer competitors in international land markets. In international land and offshore markets, experience in operating in challenging environments and our customer alliances have been factors in being awarded a contract in certain cases, as well as our patented drilling equipment 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 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 the Gulf Coast land markets. Some of Quail Tools’ competitors are substantially larger and have greater financial resources than Quail Tools.

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 records, service and experience.

Our drilling and rental tools customer base consists of major, independent and foreign-owned oil and gas companies. In 2003 Royal Dutch Shell, Tengizchevroil (“TCO”), a consortium led by ChevronTexaco and ChevronTexaco Corporation accounted for approximately 15 percent, 14 percent and 11 percent, respectively, of our total revenues, including discontinued operations. Our ten most significant customers collectively accounted for approximately 66 percent of our total revenues in 2003, including discontinued operations.

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 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 that may be beyond our 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. Some of our contracts may provide the customer with an option to purchase the rig that is employed under the contract. 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 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.

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 is no assurance that such insurance will adequately protect us against or will be available to cover all liability from all of the consequences and hazards we may encounter in our drilling operations.

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 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. 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 issued 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. To the extent damages and removal costs exceed this amount, the mobile offshore drilling rig will be treated as an offshore facility and the offshore lessee will be responsible up to higher liability limits for all removal costs plus $75.0 million. A party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by the OPA. The OPA also imposes ongoing requirements on a responsible party, including proof of financial responsibility (to cover at least some costs in a potential spill) and preparation of an oil spill contingency plan for offshore facilities and vessels in excess of 300 gross tons. 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. However, such OPA amendments do not reduce the amount of financial responsibility required for “tank vessels.” Since our offshore drilling rigs are typically classified as tank vessels, these provisions do not have a significant effect on our operations. A failure to comply with ongoing requirements or inadequate cooperation in a spill may even subject a responsible party to civil or criminal enforcement actions.

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

All of 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 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 or financial position 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.

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, 2003, 2002 and 2001 is set forth in Note 11 in the notes to the consolidated financial statements.

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.

The following table shows, as of December 31, 2003, the locations and drilling depth ratings of our land rigs available for service. Twelve of these rigs were under contract and the remainder were available for contract as of December 31, 2003.

(1)

Two of these rigs are owned by AralParker, a Kazakhstan joint venture company.

In addition, we have three land rigs in the Asia Pacific region classified as cold stacked which would need to be refurbished at a significant cost before being placed back into service.

The following table shows our international deep drilling barges as of December 31, 2003. Three of these rigs were under contract and two were available for contract at December 31, 2003.

The following table shows our deep, intermediate, and workover and shallow drilling barge rigs located in the Gulf of Mexico. Ten of these barge rigs were under contract and the remainder were available for contract as of December 31, 2003.

The following table presents our utilization rates and rigs available for service for the years ended December 31, 2003 and 2002.

(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.

We are currently attempting to sell a number of rigs and related spare parts and have classified them as assets held for sale. As of December 31, 2003, these rigs consisted of the following:

(1)		IC — independent leg, cantilevered; IS — independent leg, slot; MC — mat-supported, cantilevered.

(2)		Workover rig only.

(3)		In September 2003, a malfunction caused jackup rig No. 14 to become partially submerged in the water. We have removed this jackup rig from our marketable rigs as we assess the damage.

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 us.

There were no matters submitted to Parker Drilling Company security holders during the fourth quarter of 2003.

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, 80, 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., 55, 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 elected chief executive officer. He has been a director since 1973.

	(3)		Robert F. Nash, 60, senior vice president and chief operating officer, joined Parker Drilling in November 2001. Mr. Nash joined us following a 26-year career with Halliburton, during which time he held numerous senior management positions with responsibility for operations, technical development, manufacturing, procurement, inventory management and sales and marketing. He also has considerable experience with mergers, acquisitions, divestitures and reorganizations.

	(4)		James W. Whalen, 62, 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, 48, 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)		John R. Gass, 52, vice president of operations, joined Parker Drilling in 1977 and has served in various management positions in our international divisions. In 1985, he became the division manager of Africa and the Middle East. In 1987, he directed our core drilling operations in South Africa. In 1989, he was promoted to international contract manager. He was named vice president, frontier areas in January 1996, and vice president of sales and contracts in March 1999. He assumed his current position in September 2003.

	(7)		Denis J. Graham, 54, 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.

	(8)		Ronald C. Potter, 50, 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.

(9)

David W. Tucker, 48, 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.

ITEM 5. MARKET FOR REGISTRANT’S COMMON STOCK AND RELATED STOCKHOLDER MATTERS

Parker Drilling Company common stock is listed for trading on the New York Stock Exchange under the symbol “PKD.” At the close of business on December 31, 2003, there were 2,682 holders of record of Parker Drilling common stock. Prices on Parker Drilling’s common stock for the years ended December 31, 2003 and 2002 were as follows:

No dividends have been paid on common stock since February 1987. Restrictions contained in Parker Drilling’s existing credit agreement prohibit the payment of dividends 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 following table presents selected historical consolidated financial data derived from the audited financial statements of Parker Drilling for each of the five years in the period ended December 31, 2003. In 2003, our board of directors approved a plan to sell our non-core assets, which, as of December 31, 2003, includes our Latin America assets, consisting of 16 land rigs and related inventory and spare parts, and our U.S. offshore assets, consisting of six jackup and four platform rigs. The two operations that constitute this plan of disposition meet the requirements of discontinued operations under the provisions of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Accordingly, our consolidated financial statements for each of the five years in the period ended December 31, 2003 have been reclassified to present our Latin America operations and our U.S. jackup and platform drilling operations as discontinued operations and net gain on disposition of assets for continuing operations have been reclassified as part of total operating income. The financial data for the year ended December 31, 2000 has also been reclassified to reflect the adoption of SFAS No. 145, “Rescission of FASB Statements No. 4, No. 44, and No. 64, Amendment of FASB Statement No. 13, and Technical Corrections,” which resulted in the reclassification of the extraordinary gain on early extinguishment of debt to other income and the related deferred taxes to income tax expense.

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.

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

The financial results for 2003 continued to reflect the current depressed conditions in most drilling markets. Barge drilling rig dayrates in the Gulf of Mexico drilling market were depressed during 2003 despite natural gas prices remaining at historically high levels during the period. We believe this can be attributed to several factors, including operators addressing debt reduction issues, lack of acceptable well prospects for major oil companies and funding issues for independent operators. Consistent with these market conditions, barge rig utilization and dayrates declined one percent and nine percent, respectively, during 2003 when compared to 2002. We believe that the factors mentioned above have become less significant and that utilization and dayrates have improved during the first quarter of 2004. If natural gas prices remain at current levels, we expect the continuation of the current trend.

During 2003 we had two incidents that resulted in significant damage to two of our rigs in the Gulf of Mexico. On September 11, 2003, a malfunction caused one side of jackup rig 14 to become partially submerged in the water, resulting in significant damage to the rig and the loss of certain drilling equipment overboard. After being towed to the shipyard, the damages were analyzed and an insurance claim submitted, which is presently under consideration. We believe that substantially all of the loss will be covered by insurance. Our insurance is based on replacement cost and is thus expected to exceed the net book value of the rig plus costs incurred to tow it to the shipyard and evaluate the damage. On November 6, 2003, we experienced a well control incident during completion operations on our workover barge rig 18. The barge rig was declared a total loss and we received $6.0 million in insurance proceeds in December 2003, which was in excess of the loss incurred.

Revenues and operating income in our rental tools business in the Gulf of Mexico increased during 2003 when compared to 2002. Revenues increased primarily due to more deep water projects and the addition of new customers in the Gulf of Mexico. In addition, contributing to the increase has been the opening of Quail Tools’ new Evanston, Wyoming operation that meets the market niche of Quail Tools as they continue to establish a solid customer base.

The Commonwealth of Independent States (former Soviet Union, referred to herein as “CIS”) is our leading market of international land operations. In addition to our established operations in Kazakhstan and Russia, one of our subsidiaries signed a three-year, two rig contract in 2003 with Calik Enerji, A.S. to provide drilling services to Turkmenneft State Concern in Turkmenistan. One drilling rig began operations in early November; the second rig is on site and is expected to begin drilling operations in the first quarter of 2004. Our remaining international land operations showed signs of improvement during the fourth quarter of 2003 due primarily to new contracts in our Asia Pacific operation. We have two new contracts in New Zealand and a new contract in Bangladesh. The new contracts in New Zealand and Bangladesh are anticipated to last from nine to twelve months. We continue to experience increased bidding activity in New Zealand.

Our international barge drilling operations were negatively impacted during 2003 by continued community unrest in Nigeria. One incident has resulted in the shutdown and evacuation of barge rig 74 since March 2003. We have been unable to access the barge rig due to the ongoing community unrest. Based on a very preliminary high fly over assessment by our customer in July 2003, we recorded a charge of approximately $1.7 million in June 2003, to account for the portion of the estimated repair costs that will not be covered by insurance. Although the rig is still not accessible, indirect reports that are not verifiable indicate that the rig has sustained significant damage that is not quantifiable at this time. We believe that the damage to this rig will be covered by insurance. In the Caspian Sea, our arctic-class barge rig 257 completed its initial four-year contract in November 2003. As of the end of 2003, barge rig 257 was stacked and we are currently in discussions with potential customers; however, we do not anticipate that this rig will resume operations until late 2004 or early 2005. Considering the current unrest in Nigeria and the status of rig 257, we expect international barge drilling operations to remain flat or decline in 2004.

In 2003, our board of directors approved a plan to sell our non-core assets to generate funds to enhance our debt reduction capabilities. As of December 31, 2003, our fleet of rigs held for sale consisted of six shallow-water jackup rigs and four offshore platform rigs located in the Gulf of Mexico and 16 land rigs and related inventory and spare parts located in Latin America. We identified these assets for sale based on the relatively low utilization rates of the land rigs and platform rigs and the wide fluctuations in the dayrates for the jackup rigs. The operations that constitute this plan of disposition meet the requirements of discontinued operations under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” Accordingly, our consolidated financial statements for the years ended December 31, 2003, 2002 and 2001 have been reclassified to present our Latin America operations and our U.S. jackup and platform drilling operations as discontinued operations. The assets held for sale have been written down to their estimated fair value, resulting in a non-cash impairment charge of $54.0 million recognized in the second quarter of 2003. We will continue to report separately the results of operations of these discontinued operations until the closing of the actual sales.

Although no asset sales were consummated during 2003, we used some of our existing cash and cash flows to repay $19.3 million as a first step toward our goal of a debt reduction of $200 million. Since December 31, 2003, we have further reduced our debt an additional $14.6 million by purchasing $9.5 million of our 5.5% Convertible Subordinated Notes and paying off the remaining Boeing Capital Corporation note which had a balance of $5.1 million.

During October 2003, we completed a refinancing of a portion of our debt. The total refinancing package was for $325.0 million comprised of $175.0 million of 9.625% Senior Notes due 2013 and the replacement of our senior credit facility with a $100.0 million delayed draw term loan facility and a $50.0 million revolving credit facility. Proceeds from the refinancing were used to retire in full the outstanding $214.2 million of our 9.75% Senior Notes due 2006. We believe these transactions have provided adequate financial flexibility to pursue asset sales in a very determined but conservative fashion. The transactions have neither reduced our resolve to successfully complete asset sales nor modified our January 2003 goal to reduce debt by $200 million.

We continue to be vigilant in our efforts to conserve cash by reducing our general and administrative expenses and limiting our capital expenditures. We reduced our general and administrative expenses in 2003 to $19.3 million from $24.7 million in 2002 by reducing our corporate workforce in 2002 and by limiting administrative costs. We will continue to make adjustments as appropriate for the level of our operations. Our capital expenditure program calls for limiting expenditures to scheduled ongoing maintenance projects, our preventive maintenance program and capital projects that we believe have the potential to yield an attractive rate of return. As a result, our capital expenditures for 2003 were $35.0 million.

During our fourth quarter conference call with investors, management confirmed its previously released earnings guidance. Based on current prices for natural gas and oil, management is anticipating that domestic dayrates will improve slightly and both international and domestic utilization will continue to increase during 2004. The combined result of the anticipated debt reduction and improved utilization is expected to result in a loss in diluted earnings per share from continuing operations for 2004 of $0.10 to $0.20. We are projecting to return to profitability during the third quarter of 2004.

We recorded a loss from continuing operations of $51.8 million for the year ended December 31, 2003 as compared to a loss from continuing operations of $15.3 million for the year ended December 31, 2002. We recorded a loss from discontinued operations of $57.9 million for the year ended December 31, 2003 as compared to a loss from discontinued operations of $25.6 million for the year ended December 31, 2002. For the year ended December 31, 2002 we recognized a change in accounting principle related to our adoption of Statement of Financial Accounting Standards “SFAS” No. 142, “Goodwill and Other Intangible Assets” which resulted in recording the impairment of goodwill, effective the first quarter of 2002, in the amount of $73.1 million.

The reduction in revenues from $342.8 million to $313.8 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.

U.S. drilling revenues from continuing operations of 21 barge rigs decreased $10.9 million in 2003 to $67.5 million due primarily to lower dayrates. The 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, 51 percent in 2003 and 52 percent in 2002. Although prices for natural gas have risen, uncertainty regarding the economy and international issues caused operators to be hesitant to significantly increase drilling in 2003.

International drilling revenues decreased $25.3 million to $191.7 million in 2003 as compared to 2002, of which $8.2 million was attributed to a decrease in international land drilling revenues. International land drilling revenues in the CIS region increased $2.8 million in 2003 primarily attributed to commencement of drilling operations on Sakhalin Island in 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. The remaining rig in the Karachaganak field is expected to continue drilling through 2004. In addition, in December 2002, one 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 by $11.6 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.

International offshore drilling revenues accounted for the remaining $17.1 million decrease in international drilling revenues and were 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 will terminate in March 2004. As of December 31, 2003, barge rigs 75 and 73 are operating on full dayrates and barge rig 74 remains on the reduced standby rate. Barge rig 72 has been stacked since the completion of its contract during the third quarter of 2002.

Rental tools revenues increased $7.1 million in 2003 as Quail Tools reported revenues of $54.6 million. 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 new 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. The Odessa, Texas operation 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 new Evanston, Wyoming operation continues to expand its customer base.

Drilling and rental operating income of $42.1 million for the year ended December 31, 2003 reflected a decrease of $15.8 million from 2002. Decreased gross margins in the U.S. drilling operations and international operations were partially offset by increased gross margin in the rental tools operations. The U.S. drilling operations gross margin decreased $6.1 million during the current period. The gross margin percentage decreased from 33 percent to 29 percent primarily attributed to the decrease in barge rig revenues in the current period.

International drilling gross margin decreased $14.6 million in 2003 as compared to the year ended December 31, 2002. International land drilling gross margin decreased $12.2 million to $36.6 million in 2003 due primarily to the reduced revenues in our land drilling operations in Kazakhstan, Papua New Guinea and New Zealand, as previously discussed. The gross margin percentage for the international land drilling decreased from 40 percent to 32 percent in the current year. The international offshore drilling gross margin decreased $2.4 million to $23.1 million for 2003. The decrease is primarily attributed to reduced revenues resulting from the community unrest issues in Nigeria as previously discussed. Gross margins in Nigeria decreased approximately $6.3 million during the current year as compared to 2002. 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 2003 year 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 prior year was negatively impacted by an additional assessment for property taxes.

Rental tools gross margin increased $5.9 million to $31.6 million during the current year as compared to 2002. Gross margin percentage increased to 58 percent during the current year 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 during the period. The slight increase in operating expenses was driven primarily by increased administrative costs and increased man hours worked.

Depreciation and amortization expense increased $1.0 million to $68.9 million during the current period. Depreciation expense increased due to capital additions during 2002.

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 are recognized as construction contract revenues and expenses, with the profit calculated on a percentage of completion basis. 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 is primarily attributed to the following: salaries and wages decreased $2.1 million as a result of the reduction in force in June 2002, professional and legal fees decreased $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 is a result of the ongoing 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 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.

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 $4.5 million in the current year 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 consists of foreign tax expense of $16.7 million for the year ended December 31, 2003. For the year ended December 31, 2002 income tax expense from continuing operations included foreign tax expense of $14.2 million and deferred tax benefit of $17.1 million. In the year-to-year comparison foreign taxes increased $2.5 million. However, this was primarily due to a realized tax benefit in 2002 from a Kazakhstan tax ruling related to a prior-year filing. For the current year 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, exceeds 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 the current year.

	(1)		Drilling gross margins are 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 to 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 no longer record depreciation expense related to the discontinued operations.

(3)

Drilling operating income (loss) - drilling revenues less direct drilling operating expenses, including depreciation and amortization expense.

The $18.0 million reduction in revenues from the Latin America region was due primarily to fewer drilling contracts and thus the region operated an average of only 3.0 rigs during the current year as compared to 7.0 rigs during the year ended December 31, 2002. The decline in utilization is 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 has been moved 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.

Gross margin in the Latin America region decreased $5.2 million to $4.9 million in the current year as compared to the year ended December 31, 2002. The loss of four contracts with one customer in Colombia in mid-2002 and completion of one contract in Ecuador contributed to the decline in gross margin. Of the four contracts cancelled in Colombia, only one rig returned to work for the customer in early 2003. The other three rigs maintained approximately the same utilization in 2003 as 2002.

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 the current period, an increase of $4.5 million from 2002. The gross margin was positively impacted in the current period by higher dayrates and utilization for the jackup rigs and platform rigs as previously discussed.

Pending the sale of discontinued operations, we continue to actively seek contracts for these assets and maximize revenues from their utilization.

We recorded a loss from continuing operations of $15.3 million for the year ended December 31, 2002, before discontinued operations and the cumulative effect of a change in accounting principle, compared to income from continuing operations of $1.0 million for the year ended December 31, 2001. We recorded a loss from discontinued operations of $25.6 million for the year ended December 31, 2002 as compared to income from discontinued operations of $10.1 million for 2001. The change in accounting principle related to our adoption of SFAS No. 142, “Goodwill and Other Intangible Assets” resulted in recording the impairment of goodwill, effective the first quarter of 2002, in the amount of $73.1 million.

Our revenues decreased $52.2 million from $395.0 million in 2001 to $342.8 million for the year ended December 31, 2002. This reduction in revenues was attributed to reduced drilling activity worldwide, most notably in the Gulf of Mexico, due to the economic downturn in the United States and increased inventories of oil and natural gas.

U.S. barge drilling revenues decreased $40.7 million in 2002 to $78.3 million due primarily to decreased dayrates and reduced utilization. The Gulf of Mexico market declined significantly during the fourth quarter of 2001 and continued throughout 2002 due primarily to a reduction in drilling activity by operators. This reduction in drilling activity was in response to declining demand and prices for natural gas and the economic recession in the United States that began during mid-2001. Although prices for natural gas had risen, uncertainty regarding the economy and international issues had caused operators to be hesitant to significantly increase drilling in 2002. Utilization for the barge rigs decreased from 76 percent in 2001 to 52 percent in 2002 with a 10 percent decrease in dayrates.

International drilling revenues increased $6.6 million to $217.0 million in 2002 as compared to 2001. International land drilling revenues increased $17.2 million to $122.7 million during 2002 as compared to 2001. International land drilling revenues in the CIS region increased $9.7 million in 2002. Revenues increased $8.4 million in our Tengiz operations in 2002 as compared to 2001 primarily due to increased utilization. Revenues from our interest in SaiPar B.V. increased $5.1 million due to increased rig lease rates in 2002 and from early termination fees for the two rigs released by the operator in July and December 2002. The early termination fees totaled $3.7 million. Revenues increased in the Asia Pacific region by $6.1 million related primarily to increased utilization and dayrates in Papua New Guinea. Additionally, we increased the number of labor contracts in Kuwait from two rigs in 2001 to six rigs in 2002 resulting in additional revenues of $1.4 million.

International offshore drilling revenues decreased $10.6 million to $94.3 million when compared to 2001, primarily attributable to Nigeria. During the second and third quarters, two of our four barge rigs operating in Nigeria incurred downtime for required American Bureau of Shipping (“ABS”) inspections and repairs that resulted in a combined total of five months with no revenues. Shortly after returning to work the drilling contracts for these two barge rigs concluded and only one contract was subsequently renewed. At December 31, 2002, three of the four barge rigs were drilling.

Rental tools revenues decreased $18.1 million due to the decline in drilling activity in the Gulf of Mexico and decreased land drilling in West Texas, which reduced the demand for rental tools. Revenues decreased $9.1 million in the New Iberia, Louisiana operation, $6.6 million in the Victoria, Texas operation and $3.2 million from the Odessa, Texas operation. Quail Tools opened a new operation in Evanston, Wyoming in July 2002 which contributed $0.8 million in revenues in 2002.

(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 to those amounts reported under 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.

Drilling and rental operating income of $57.8 million in 2002 reflects a decrease of $31.9 million from the $89.7 million recognized during the year ended December 31, 2001. The U.S. and international drilling segments recorded gross margin percentages of 33 percent and 34 percent, respectively, in 2002 as compared to 43 percent and 31 percent in 2001. U.S. gross margins decreased $24.8 million to $25.9 million for the year ended December 31, 2002 due to declining revenues as discussed above. In response to declining revenues, U.S. operations instituted cost controls for labor, materials and supplies. As a result, the gross margin percentage increased during the fourth quarter to 40 percent from 35 percent during the third quarter on comparable revenues.

International drilling gross margin increased $9.9 million to $74.2 million during the year ended December 31, 2002 as compared to 2001. International land drilling gross margin increased $13.9 million to $48.7 million. Gross margin in the CIS region increased $11.4 million with Kazakhstan and Russia operations each increasing gross margin by approximately $5.7 million. The Kazakhstan increase was primarily attributable to increased utilization in the Tengiz field and the early termination fees received for the two rigs released that were previously operating in the Karachaganak field. The gross margin increase in Russia was due to higher than anticipated mobilization and start up costs incurred in 2001 that resulted in a significant loss. Asia Pacific region gross margin increased $2.5 million to $17.3 million during 2002. Improvement in Asia Pacific is primarily related to increased revenues in Papua New Guinea that resulted in increased gross margin of $2.3 million. International offshore drilling gross margins decreased $4.0 million to $25.5 million during 2002. This decrease in gross margin is primarily attributed to Nigeria where two of the four barge rigs incurred a combined total of five months downtime during the second and third quarters due to ABS inspections and repairs. In addition, these two rigs both completed their respective contracts toward the end of the third quarter and only one contract was renewed in the fourth quarter.

Rental tools gross margin decreased $16.9 million to $25.7 million during 2002 as compared to the year ended December 31, 2001. Gross margin decreased primarily due to the $18.1 million decline in revenues during 2002. The gross margin percentage decreased during 2002 to 54 percent from 65 percent for 2001 due to the significant fixed costs related to the rental tools operation.

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 project are recognized as construction contract revenues and expenses. The estimated profit from the engineering, construction, mobilization and rig-up fees was calculated on a percentage of completion basis, of which $2.5 million was recognized during the year ended December 31, 2002.

General and administrative expense increased $3.0 million to $24.7 million for the year ended December 31, 2002. The increase is primarily due to severance costs related to reductions in corporate personnel, significant increase in the vacation accrual, professional fees and required maintenance on our former corporate headquarters in Tulsa, Oklahoma currently held for sale. With regards to the vacation accrual, we adopted a paid time off policy in 2002, significantly increasing the required vacation accrual.

The $1.1 million provision for reduction in carrying value of certain assets is to increase the allowance for doubtful accounts for a U.S. customer who filed for bankruptcy protection during the second quarter of 2002. The $7.5 million of reorganization costs recorded in 2001 includes employee moving expenses and severance costs related to the consolidation and relocation of our corporate and international drilling management to Houston, Texas from Tulsa, Oklahoma. The reorganization of certain senior management positions and management of drilling operations accompanied the relocation.

Interest expense decreased $0.6 million in 2002 compared to 2001. Savings of $2.9 million associated with the three $50.0 million interest rate swap agreements, including $0.3 million from the amortization of gain on the termination of the interest rate swap agreements, were offset by $1.5 million less interest capitalized and $0.6 million higher interest due to the higher interest rate on the exchange notes. Other expense of $4.3 million for the year ended December 31, 2002 includes $3.6 million related to the exchange offer and $0.4 million of costs incurred for the attempted purchase of Australia Oil and Gas Corporation Limited.

Income tax expense for the year ended December 31, 2002 consists of foreign tax expense of $14.2 million and a deferred tax benefit of $17.1 million. Foreign taxes increased $1.4 million due to increased taxes in the Kazakhstan and the Asia Pacific regions, limited primarily due to a tax benefit realized in 2002 from a Kazakhstan tax ruling related to prior years. The deferred tax benefit was recognized due to the loss generated during 2002.

(1)

Drilling gross margins are 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 to 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 no longer record depreciation expense related to the discontinued operations.

	(3)		Drilling operating income (loss) - drilling revenues less direct drilling operating expenses, including depreciation and amortization expense.

U.S. jackup and platform drilling revenues decreased $38.0 million in 2002 from 2001. Revenues for the jackup rigs decreased $27.7 million during 2002 as compared to 2001. The seven jackup rigs experienced a 44 percent decrease in average dayrates during 2002 as compared to 2001, while utilization for the jackups remained relatively constant in year-to-year comparisons. Revenues for the platform rigs decreased $10.3 million to $1.6 million, as all four platform rigs were stacked the last three quarters of 2002. The significant decrease in gross margin relates almost entirely to the 44 percent decrease in average dayrates for the jackup rigs.

Latin America revenues decreased $15.0 million in 2002 as compared to 2001. The decrease primarily related to reduced utilization in Colombia and Bolivia. During the fourth quarter of 2001, Colombia and Bolivia had six rigs and one rig working, respectively. At December 31, 2002, Colombia had three rigs working and Bolivia had no rig activity. In Colombia, we had four drilling rigs working for a customer when the operator terminated all drilling activity in May 2002. Since then, one rig has returned to work for this particular customer. The drilling market in Bolivia, which diminished significantly in mid-2001, showed no signs of recovery throughout 2002, primarily due to reduced demand for natural gas from Brazil. Contributing to the reduced demand in 2002 were delays in receiving the Bolivian government’s commitment to a new gas pipeline to the west coast of South America to enable the exporting of natural gas to Mexico and the United States. Revenues in Bolivia decreased $10.5 million to $1.0 million in 2002.

Latin America’s discontinued operations gross margin declined $2.6 million primarily due to decreased drilling activity in Colombia and Bolivia. The decrease in Colombia and Bolivia were partially offset by increased gross margin in Ecuador and Peru. The contract in Ecuador was completed in the third quarter of 2002.

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 and $12.3 million of proceeds from the disposition of equipment. Included in proceeds was $6.0 million of insurance proceeds for barge rig 18. 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.

As of December 31, 2002, we had cash and cash equivalents of $52.0 million, a decrease of $8.4 million from December 31, 2001. The net cash provided by operating activities was $33.2 million for 2002. Due to reduced revenues during 2002, accounts and notes receivable decreased $8.9 million. Lower utilization and reduced capital spending resulted in a decrease of $19.8 million to accounts payable and accrued liabilities. Net cash used in investing activities was $38.7 million in 2002. This included $45.2 million for capital expenditures net of proceeds from the sale of assets of $6.5 million. Net cash used in financing activities was $2.9 million in 2002. This included $5.5 million repayment of debt net of $2.6 million proceeds from the settlement of three interest rate swap agreements.

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 less than $50.0 million in 2004. 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.

LIQUIDITY AND CAPITAL RESOURCES (continued)

In October 2003, we refinanced a portion of our existing debt by issuing $175.0 million of new 9.625% Senior Notes due 2013 and replaced our senior credit facility with a $150.0 million senior credit agreement. The senior credit agreement consists of a four-year $100.0 million delayed draw term loan facility and a three-year $50.0 million revolving credit facility that are 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 new 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 of the proceeds from the new 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 revolving credit facility portion of the senior credit agreement replaces the previous $50.0 million revolving credit facility that would have expired in late October 2003. The 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. As of December 31, 2003, the borrowing base was $44.7 million, of which none had been drawn down, and $10.6 million had been reserved for letters of credit, resulting in available revolving credit of $34.1 million.

We had total long-term debt of $571.6 million, including the current portion of $60.2 million, at December 31, 2003. The long-term debt included:

• $105.2 million aggregate principal amount of 5.5% Convertible Subordinated Notes, which are due August 1, 2004; (The undrawn portion of the term loan can only be used to repay the 5.5% Convertible Subordinated Notes, therefore $50.0 million of these notes have been classified as long-term.)

• $50.0 million term loan, with an additional $50.0 million available for the sole purpose of repaying the 5.5% Convertible Subordinated Notes, which is due on October 10, 2007;

• $236.4 million aggregate principal amount of 10.125% Senior Notes, which are due November 15, 2009; and

• $175.0 million aggregate principal amount of 9.625% Senior Notes, which are due October 1, 2013.

As of December 31, 2003, we had approximately $151.9 million of liquidity. This liquidity was comprised of $67.8 million of cash on hand, $34.1 million of undrawn availability under the new revolving credit facility and $50.0 million of availability under the delayed draw term loan facility (which may only be used to repay the 5.5% Convertible Subordinated Notes and we currently intend to do that). In the third quarter of 2003, we advised that due to cross default provisions in our debt agreements, if we were unable to pay the 5.5% Convertible Subordinated Notes when due, all of our debt would be declared in default and would become immediately due and payable. We believe that any such concern has been substantially alleviated. We believe our current liquidity, along with cash generated from operations, will provide sufficient liquidity to repay the remaining $95.7 million, after the subsequent $9.5 million payment in January 2004, of the 5.5% Convertible Subordinated Notes due in August 2004.

LIQUIDITY AND CAPITAL RESOURCES (continued)

In January 2004, we purchased an additional $9.5 million face value of our 5.5% Convertible Subordinated Notes at a 0.625 percent premium. We also prepaid the remaining balance of our secured promissory note to Boeing Capital Corporation in February 2004 at a premium of 5.0 percent. The outstanding balance at December 31, 2003 was $5.1 million. The following table summarizes our future contractual cash obligations as of December 31, 2003.


	Total		Less than 1 Year		1 - 3 Years		3 - 5 Years		More than 5 Years
	(Dollars in Thousands)
Contractual cash obligations:
Long-term debt - principal (1)	$	570,837	$	110,225	$	—	$	50,000	$	410,612
Long-term debt - interest (1)		325,984		48,900		91,069		85,133		100,882
Operating and capital leases (2)		14,902		4,278		4,746		5,001		877

Total contractual obligations	$	911,723	$	163,403	$	95,815	$	140,134	$	512,371

Commercial commitments:
Revolving credit facility (3)	$	—	$	—	$	—	$	—	$	—
Standby letters of credit (3)		10,619		—		—		—		10,619

Total commercial commitments	$	10,619	$	—	$	—	$	—	$	10,619

(1) Long-term debt includes the principal and interest cash obligations of the 9.625% Senior Notes, the 10.125% Senior Notes, the 5.5% Convertible Subordinated Notes and the secured 10.1278% promissory note. The unamortized premiums of $0.8 million at December 31, 2003 related to the 10.125% Senior Notes are not included in the contractual cash obligations schedule.

(2) Operating leases consist of lease agreements in excess of one year for office space, equipment, vehicles and personal property.

(3) We have a $50.0 million revolving credit facility with an available borrowing base of $44.7 million. As of December 31, 2003, none has been drawn down, but $10.6 million of availability has been used to support letters of credit that have been issued. The revolving credit facility expires on October 10, 2006.

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 in the exploration and development of reserves of oil. In the United States, we primarily drill in the coastal and offshore waters of the Gulf of Mexico with barge, jackup and platform rigs 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 development activities and consequently do not materially affect our operations, except for the Gulf of Mexico, where drilling contracts are generally for a shorter term, and oil and gas companies tend to respond more quickly to upward or downward changes in prices. Many international contracts are of longer duration and oil and gas companies have committed to longer-term projects to develop reserves and thus our international operations are not as susceptible to 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 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. These policies require significant judgments and estimates used 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. Our management periodically evaluates 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 have realized sustained significant declines in utilization and dayrates and recovery is not contemplated in the near future, or when reclassifications are made between property and equipment and assets held for sale as prescribed by SFAS No. 144, “Accounting for Impairment or Disposal of Long-Lived Assets.” Our management considers a number of factors such as estimated undiscounted future cash flows, appraisals and current market value analysis in determining net realizable value. Assets are written down to fair value if they are below net carrying value.

OTHER MATTERS (continued)

During the second quarter of 2003, our board of directors approved a plan to sell our non-core assets which as of December 31, 2003 includes our Latin America assets consisting of 16 land rigs and related inventory and spare parts and our U.S. offshore assets consisting of six jackup rigs and four platform rigs. We are actively marketing the assets through an independent broker. At June 30, 2003, the net book value of the assets to be sold exceeded the fair value and as a result an impairment charge including estimated sales expenses was recognized in the amount of $54.0 million.

In December 2003, the salvage values on three non-marketable land rigs in our Asia Pacific region and certain spare parts and equipment located at our New Iberia, Louisiana facility were impaired. We provided a provision totaling $2.6 million for this equipment. Subsequent to December 31, 2003, we entered into an agreement to sell our land and buildings in New Iberia, Louisiana. The net sales price approximates $6.4 million which resulted in a provision for impairment of $3.4 million for the land and buildings. This impairment was recognized in the December 31, 2003 consolidated financial statements.

Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by our assets, and reflect management’s assumptions and judgments regarding future industry conditions and their effect on future utilization levels, dayrates and costs. The use of different estimates and assumptions could result in materially different carrying values of our assets.

Impairment of Goodwill. Our management periodically assesses whether the excess of cost over net assets acquired is impaired based on the estimated fair value of the operation to which it relates, which value is generally determined based on estimated future cash flows of that operation. If the estimated fair value is in excess of the carrying value of the operation, no further analysis is performed. If the fair value of each operation, to which goodwill has been assigned, is less than the carrying value, we will deduct the fair value of the tangible and intangible assets and compare the residual amount to the carrying value of the goodwill to determine if impairment should be recorded. Changes in the assumptions 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 $189.1 million of goodwill. In lieu of amortization, we performed an initial impairment review of goodwill and impaired goodwill by $73.1 million. We performed our annual impairment test of goodwill at year-end 2003 and determined that the fair value exceeded the carrying value as of December 31, 2003; accordingly, no impairment was recorded.

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 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 must then assess the likelihood that the deferred tax assets will be recovered from future taxable income, and to the extent we believe that recovery is not likely, we must establish a valuation allowance. To the extent we established a valuation allowance or increase or decrease this allowance in a period, we must include an expense or reduction of expense within the tax provision in the statement of operations.

OTHER MATTERS (continued)

Revenues Recognition. We recognize revenues and expenses on dayrate contracts as the drilling progresses (percentage of completion method) because we do not bear the risk of completion of the well. For meterage contracts, which are rare, we recognize the revenues and expenses upon completion of the well (completed contract method). Revenues from rental activities are recognized ratably over the rental term which is generally less than six months. Mobilization revenues, related costs and reimbursements for customer required rig equipment or refurbishments, if significant, are amortized over the term of the related drilling contracts.

Recent Accounting Pronouncements

In May 2003, the Financial Accounting Standards Board (“FASB”) issued the Statement on Financial Accounting Standards (“SFAS”) No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.” SFAS No. 150 establishes standards regarding the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). Many of those instruments were previously classified as equity. SFAS No. 150 became effective for the Company starting in the quarter ended September 30, 2003. The adoption of this standard did not have any impact on the Company’s financial position or results of operations.

In January 2003, the FASB issued FASB Interpretation (“FIN”) 46, “Consolidation of Variable Interest Entities an Interpretation of ARB No. 51.” A Variable Interest Entity (“VIE”) is created when: (i) the equity investment at risk is not sufficient to permit the entity from financing its activities without additional subordinated financial support from other parties or (ii) equity holders at risk either: (a) lack direct or indirect ability to make decisions about the entity, (b) are not obligated to absorb expected losses of the entity or (c) do not have the right to receive expected residual returns of the entity if they occur. If an entity is deemed to be a VIE, pursuant to FIN 46, an enterprise that absorbs the majority of the expected losses of the VIE is considered the primary beneficiary and must consolidate the VIE. The application of FIN 46 (as amended by FIN 46-R) is required in financial statements of public entities that have interests in variable interest entities or potential variable interest entities commonly referred to as special-purpose entities for periods ending after December 15, 2003. Application by public entities (other than small business issuers) for all other types of entities is required in financial statements for periods ending after March 15, 2004. We adopted this interpretation in December 2003 and implementation of this interpretation did not have a material effect on our results of operations or our financial position.

In December 2003, the Securities and Exchange Commission issued Staff Accounting Bulletin (“SAB”) No. 104, “Revenue Recognition,” which supersedes SAB No. 101, “Revenue Recognition in Financial Statements.” SAB No. 104’s primary purpose is to rescind accounting guidance contained in SAB No. 101 related to multiple element revenue arrangements, which was superseded as a result of the issuance of Emerging Issues Task Force (“EITF”) No. 00-21, “Accounting for Revenue Arrangements with Multiple Deliverables.” While the wording of SAB No. 104 has changed to reflect the issuance of EITF No. 00-21, the revenue recognition principles of SAB No. 101 remain largely unchanged by the issuance of SAB No. 104. The implementation of SAB No. 104 is not expected to affect the Company’s financial position or results of operations.

Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

We are exposed to interest rate risk from our fixed-rate debt. In January 2002, we hedged against a portion of the risk of changes in fair value associated with our $214.2 million 9.75% Senior Notes by entering into three fixed-to-variable interest rate swap agreements with a total notional amount of $150.0 million. We assumed no ineffectiveness as each interest rate swap agreement met the short-cut method requirements under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” for fair value hedges of debt instruments. As a result, changes in the fair value of the interest rate swap agreements were offset by changes in the fair value of the debt and no net gain or loss was recognized in earnings. During the year ended December 31, 2002, the interest rate swap agreements reduced interest expense by $2.9 million.

On July 24, 2002, we terminated all the interest rate swap agreements and received $3.5 million. A gain totaling $2.6 million was being amortized as a reduction to interest expense and was subsequently included in the loss on the debt extinguishment of the 9.75% Senior Notes in October 2003. During 2003, $0.5 million was recognized as a reduction to interest expense and a gain of $1.9 million was included in loss on extinguishment of debt.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT AUDITORS

To the Board of Directors and Stockholders
Parker Drilling Company

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) of the Form 10-K, present fairly, in all material respects, the consolidated financial position of Parker Drilling Company and its subsidiaries at December 31, 2003 and 2002, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) of the Form 10-K, presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these financial statements in accordance with auditing standards generally accepted in the United States of America which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 3 to the 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.”

As discussed in Note 1 to the consolidated financial statements, the Company has revised its 2002 and 2001 statement of operations related to its reporting of reimbursable costs.

/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP

Houston, Texas
February 6, 2004, except for Note 17 as to which the date is March 5, 2004.

PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS
(Dollars in Thousands Except Per Share and Weighted Average Shares Outstanding)


	Year Ended December 31,
	2003			2002 (1)			2001 (1)
Drilling and rental revenues:
U.S. drilling	$	67,449		$	78,330		$	118,998
International drilling		191,698			216,991			210,427
Rental tools		54,637			47,510			65,629

Total drilling and rental revenues		313,784			342,831			395,054

Drilling and rental operating expenses:
U.S. drilling		47,740			52,475			68,345
International drilling		132,014			142,749			146,091
Rental tools		23,051			21,810			23,005
Depreciation and amortization		68,890			67,954			67,889

Total drilling and rental operating expenses		271,695			284,988			305,330

Drilling and rental operating income		42,089			57,843			89,724

Construction contract revenue		7,030			86,818			—
Construction contract expense		5,030			84,356			—

Construction contract operating income		2,000			2,462			—

General and administration expense		19,256			24,728			21,721
Provision for reduction in carrying value of certain assets		6,028			1,140			—
Gain on disposition of assets, net		3,557			2,997			1,757
Reorganization expense		—			—			7,500

Total operating income		22,362			37,434			62,260

Other income and (expense):
Interest expense		(53,790	)		(52,409	)		(53,015	)
Interest income		973			851			3,553
Loss on extinguishment of debt		(5,274	)		—			—
Minority interest		464			278			—
Other		199			(4,269	)		(384	)

Total other income and (expense)		(57,428	)		(55,549	)		(49,846	)

Income (loss) before income taxes		(35,066	)		(18,115	)		12,414
Income tax expense (benefit)		16,703			(2,836	)		11,429

Income (loss) from continuing operations		(51,769	)		(15,279	)		985
Discontinued operations, net of taxes		(57,930	)		(25,631	)		10,074
Cumulative effect of change in accounting principle		—			(73,144	)		—

Net income (loss)	$	(109,699	)	$	(114,054	)	$	11,059

Basic earnings (loss) per share:
Income (loss) from continuing operations	$	(0.55	)	$	(0.16	)	$	0.01
Discontinued operations, net of taxes	$	(0.62	)	$	(0.28	)	$	0.11
Cumulative effect of change in accounting principle	$	—		$	(0.79	)	$	—
Net income (loss)	$	(1.17	)	$	(1.23	)	$	0.12
Diluted earnings (loss) per share:
Income (loss) from continuing operations	$	(0.55	)	$	(0.16	)	$	0.01
Discontinued operations, net of taxes	$	(0.62	)	$	(0.28	)	$	0.11
Cumulative effect of change in accounting principle	$	—		$	(0.79	)	$	—
Net income (loss)	$	(1.17	)	$	(1.23	)	$	0.12
Number of common shares used in computing earnings per share:
Basic		93,420,713			92,444,773			92,008,877
Diluted		93,420,713			92,444,773			92,691,033

(1) Revised — see Note 1 in the notes to the consolidated financial statements regarding reporting of reimbursable costs.

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


	December 31,
ASSETS	2003		2002
Current assets:
Cash and cash equivalents	$	67,765	$	51,982
Accounts and notes receivable, net of allowance for bad debts of $4,732 in 2003 and $4,762 in 2002		89,050		89,363
Rig materials and supplies		13,627		17,161
Other current assets		2,466		8,631

Total current assets		172,908		167,137

Property, plant and equipment, at cost:
Drilling equipment		655,239		1,099,211
Rental tools		93,105		81,325
Buildings, land and improvements		15,708		27,905
Other		30,353		31,371
Construction in progress		7,924		6,279

		802,329		1,246,091

Less accumulated depreciation and amortization		414,665		604,813

Property, plant and equipment, net		387,664		641,278

Assets held for sale		150,370		896

Other assets:
Goodwill		114,398		115,983
Rig materials and supplies		1,288		9,450
Debt issuance costs		11,143		6,330
Other assets		9,861		12,251

Total other assets		136,690		144,014

Total assets	$	847,632	$	953,325

See accompanying notes to the consolidated financial statements.

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


	December 31,
LIABILITIES AND STOCKHOLDERS’ EQUITY	2003			2002
Current liabilities:
Current portion of long-term debt	$	60,225		$	6,486
Accounts payable		20,212			14,377
Accrued liabilities		34,383			36,365
Accrued income taxes		13,809			4,347

Total current liabilities		128,629			61,575

Long-term debt		511,400			583,444
Discontinued operations		6,421			—
Other long-term liabilities		8,379			7,680
Commitments and contingencies (Note 12)		—			—
Stockholders’ equity:
Preferred stock, $1 par value, 1,942,000 shares authorized, no shares outstanding		—			—
Common stock, $0.16 2/3 par value, authorized 140,000,000 shares, issued and outstanding 94,176,081 shares (92,793,349 shares in 2002)		15,696			15,465
Capital in excess of par value		438,311			434,998
Unamortized restricted stock plan compensation		(1,885	)		—
Accumulated other comprehensive income - net unrealized gain on investments available for sale		881			664
Retained earnings (accumulated deficit)		(260,200	)		(150,501	)

Total stockholders’ equity		192,803			300,626

Total liabilities and stockholders’ equity	$	847,632		$	953,325

See accompanying notes to the consolidated financial statements.

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


	Year Ended December 31,
	2003			2002			2001
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(109,699	)	$	(114,054	)	$	11,059
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		68,890			67,954			67,889
Gain on disposition of assets		(3,557	)		(2,997	)		(1,757	)
Cumulative effect of change in accounting principle		—			73,144			—
Provision for reduction in carrying value of certain assets		6,028			1,140			—
Deferred tax benefit		—			(17,120	)		(1,899	)
Discontinued operations		68,574			30,474			28,811
Other		6,561			6,045			4,625
Change in assets and liabilities:
Accounts and notes receivable		(107	)		8,851			24,158
Rig materials and supplies		(1,120	)		2,390			(3,807	)
Other current assets		5,701			347			(4,366	)
Accounts payable and accrued liabilities		8,973			(19,834	)		(4,484	)
Accrued income taxes		9,462			(1,843	)		(2,784	)
Other assets		2,748			(1,316	)		(1,440	)

Net cash provided by operating activities		62,454			33,181			116,005

CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from the sale of assets		12,337			6,451			7,628
Capital expenditures (net of reimbursements)		(34,962	)		(45,181	)		(122,033	)
Proceeds from sale of short-term investments		—			—			799

Net cash used in investing activities		(22,625	)		(38,730	)		(113,606	)

See accompanying notes to the consolidated financial statements.

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


	Year Ended December 31,
	2003			2002			2001
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of debt	$	225,000		$	—		$	—
Principal payments under debt obligations		(240,308	)		(5,489	)		(5,034	)
Payment of debt issuance costs		(8,738	)		—			—
Proceeds from interest rate swap agreements		—			2,620			—
Other		—			—			555

Net cash used in financing activities		(24,046	)		(2,869	)		(4,479	)

Net increase (decrease) in cash and cash equivalents		15,783			(8,418	)		(2,080	)
Cash and cash equivalents at beginning of year		51,982			60,400			62,480

Cash and cash equivalents at end of year	$	67,765		$	51,982		$	60,400

Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest	$	52,894		$	52,532		$	53,257
Income taxes	$	15,741		$	19,454		$	14,956

Supplemental noncash investing and financing activity:
Net unrealized gain on investments available for sale (net of taxes of $0 in 2003 and 2002, and $37 in 2001)	$	217		$	261		$	64
Capital lease obligation	$	290		$	1,255		$	—

See accompanying notes to the consolidated financial statements.

PARKER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(Dollars and Shares in Thousands)


							Retained			Accumulated		Unamortized
					Capital in		Earnings			Other		Restricted
			Common		Excess of		(Accumulated			Comprehensive		Stock Plan
	Shares		Stock		Par Value		Deficit)			Income		Compensation
Balances, December 31, 2000		91,724	$	15,287	$	431,043	$	(47,506	)	$	339	$	—
Activity in employees’ stock plans		330		55		1,802		—			—		—
Other comprehensive income - net unrealized gain on investments (net of taxes of $37)		—		—		—		—			64		—
Net income (total comprehensive
income of $11,123)		—		—		—		11,059			—		—

Balances, December 31, 2001		92,054		15,342		432,845		(36,447	)		403		—
Activity in employees’ stock plans		739		123		2,153		—			—		—
Other comprehensive income - net unrealized gain on investments (net of taxes of $0)		—		—		—		—			261		—
Net loss (total comprehensive loss of $113,793)		—		—		—		(114,054	)		—		—

Balances, December 31, 2002		92,793		15,465		434,998		(150,501	)		664		—
Activity in employees’ stock plans		1,383		231		3,313		—			—		(2,031	)
Amortization of restricted stock plan compensation		—		—		—		—			—		146
Other comprehensive income - net unrealized gain on investments (net of taxes of $0)		—		—		—		—			217		—
Net loss (total comprehensive loss of $109,482)		—		—		—		(109,699	)		—		—

Balances, December 31, 2003		94,176	$	15,696	$	438,311	$	(260,200	)	$	881	$	(1,885	)

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1 - Summary of Significant Accounting Policies

Consolidation - The consolidated financial statements include the accounts of Parker Drilling Company (“Parker Drilling”) and all of its majority-owned subsidiaries and a company in which a subsidiary of Parker Drilling has a 50 percent stock ownership but exerts significant influence over its operation. A subsidiary of Parker Drilling also has a 50 percent interest in another company, which is accounted for under the equity method (collectively, the “Company”).

Operations - The Company provides land and offshore contract drilling services and rental tools on a worldwide basis to major, independent and foreign-owned oil and gas companies. At December 31, 2003, the Company’s marketable rig fleet consists of 26 barge drilling and workover rigs, six offshore jackup rigs, four offshore platform rigs and 38 land rigs. The Company specializes in the drilling of deep and difficult wells, drilling in remote and harsh environments, drilling in transition zones and offshore waters, and in providing specialized rental tools. The Company also provides a range of services that are ancillary to its principal drilling services, including engineering and logistics, as well as project management activities.

Drilling Contracts and Rental Revenues - The Company recognizes revenues and expenses on dayrate contracts as the drilling progresses (percentage-of-completion method) because the Company does not bear the risk of completion of the well. For meterage contracts, the Company recognizes the revenues and expenses upon completion of the well (completed-contract method). Revenues from rental activities are recognized ratably over the rental term which is generally less than six months. Mobilization revenues, related costs and reimbursements for customer required rig equipment or refurbishments, if significant, are amortized over the term of the related drilling contracts.

Construction Contract - The Company has historically only constructed drilling rigs for its own use. At the request of one of its significant customers, the Company entered into a contract to design, construct, mobilize and sell (“construction contract”) a specialized drilling rig to drill extended-reach wells to offshore targets from a land-based location on Sakhalin Island, Russia for an international consortium of oil and gas companies. The Company also entered into a contract to subsequently operate the rig on behalf of the consortium. Generally Accepted Accounting Principles (“GAAP”) requires that revenues received and costs incurred related to the construction contract be accounted for and reported on a gross basis and income for the related fees should be recognized on a percentage-of-completion basis. Because this construction contract is not a part of the Company’s historical or normal operations, the revenues and costs related to this contract have been shown as a separate component in the statement of operations. Construction costs in excess of funds received from the customer are accumulated and reported as part of other current assets. At December 31, 2002, a net receivable (construction costs less progress payments) of $5.3 million was included in 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 balance sheet and the statement of cash flows, the Company considers cash equivalents to be all highly liquid debt instruments that have a remaining maturity of three months or less at the date of purchase.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 1 - Summary of Significant Accounting Policies (continued)

Property, Plant and Equipment - The Company provides for depreciation of property, plant and equipment primarily on the straight-line method over the estimated useful lives of the assets after provision for salvage value. The depreciable lives for land drilling equipment approximate 15 years. The depreciable lives for offshore drilling equipment generally range from 15 to 20 years. The depreciable lives for certain other equipment, including drill pipe and rental tools, range from three to seven years. Depreciable lives for buildings and improvements range from 10 to 30 years. 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 will be assessed for impairment on at least an annual basis (see Note 3 in the notes to the consolidated financial statements for additional details regarding goodwill).

Rig Materials and Supplies - Since the Company’s international drilling generally occurs in remote locations, making timely outside delivery of spare parts uncertain, a complement of parts and supplies is maintained either at the drilling site or in warehouses close to the operation. During periods of high rig utilization, these parts are generally consumed and replenished within a one-year period. During a period of lower rig utilization in a particular location, the parts, like the related idle rigs, are generally not transferred to other international locations until new contracts are obtained because of the significant transportation costs, which would result from such transfers. The Company classifies those parts which are not expected to be utilized in the following year as long-term assets. Rig materials and supplies are valued at the lower of cost or market value, net of a reserve for obsolete parts of $4.7 million and $3.4 million at December 31, 2003 and 2002, respectively.

Other Assets - Other assets include the Company’s investment in marketable equity securities. Equity securities that are classified as available for sale are stated at fair value as determined by quoted market prices. Unrealized holding gains and losses are excluded from current earnings and are included in comprehensive income, net of taxes, in a separate component of stockholders’ equity until realized. At December 31, 2003 and 2002, the fair value of equity securities totaled $1.5 million and $1.3 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 assets includes debt issuance costs which are amortized over the term of the related debt instruments.

Other Long-Term Obligations - Included in this account is the accrual of workers’ compensation 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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 1 - Summary of Significant Accounting Policies (continued)

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, 2003 and 2002, the Company had deposits in domestic banks in excess of federally insured limits of approximately $64.3 million and $51.6 million, respectively. In addition, the Company had deposits in foreign banks at December 31, 2003 and 2002 of $8.7 million and $4.8 million, respectively, which are not federally insured.

The Company’s customer base consists of major, independent and foreign-owned oil and gas companies. For the fiscal year 2003, Royal Dutch Shell was the Company’s largest customer with approximately 15 percent of total revenues. In 2003, Tengizchevroil (“TCO”), a joint venture with four oil companies, was the second largest customer with 14 percent of total revenues. ChevronTexaco Corporation was the Company’s third largest customer with approximately 11 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. See Note 6 in the notes to the consolidated financial statements. For hedges which meet the SFAS No. 133 criteria, the Company formally designates and documents the instrument as a hedge of a specific underlying exposure, as well as the risk management objective and strategy for undertaking each hedge transaction.

Fair Value of Financial Instruments - The carrying amount of the Company’s cash and cash equivalents and short-term and long-term debt had fair values that approximated their carrying amounts.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 1 - Summary of Significant Accounting Policies (continued)

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.


	Year Ended December 31,
	2003			2002			2001
	(Dollars in Thousands)
Net income (loss), as reported	$	(109,699	)	$	(114,054	)	$	11,059
Compensation expense, net of tax		(1,277	)		(2,597	)		(3,361	)

Pro forma net income (loss)	$	(110,976	)	$	(116,651	)	$	7,698

Basic and diluted net earnings (loss) per share:
As reported	$	(1.17	)	$	(1.23	)	$	0.12
Compensation expense, net of tax		(0.02	)		(0.03	)		(0.04	)

Pro forma net income (loss)	$	(1.19	)	$	(1.26	)	$	0.08

The fair value of each option grant is estimated using the Black-Scholes option pricing model with the following assumptions:


Expected dividend yield	0.0	%
Expected stock volatility	54.5	%	in 2003
	56.9	%	in 2002
	56.3	%	in 2001

Risk-free interest rate	3.0% - 6.7%
Expected life of options	5 - 7	years

Options granted in 2003, 2002 and 2001 under the 1997 Stock Plan had an estimated fair value of $206,000, $1,759,000 and $4,326,000 respectively.

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

Reclassification - During 2003, the Company adopted SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” Pursuant to the provisions of SFAS No. 144, the Company reclassed net gain on disposition of assets for continuing operations to total operating income from other income and expense of $3.6 million, $3.0 million and $1.8 million for the years ended December 31, 2003, 2002 and 2001.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 1 - Summary of Significant Accounting Policies (continued)

Revision of Previously Issued Financial Statements - During the first quarter of 2003, the Company determined that pursuant to the provisions of EITF No. 01-14, “Income Statement Characterization of Reimbursements Received for Out-of-Pocket Expenses Incurred,” amounts received as reimbursements should have been reported as revenues, with the corresponding amounts reported as operating expenses. In prior years, the Company netted the reimbursement with the cost in the statement of operations. Accordingly, the Company has revised its previously issued statement of operations to reflect this new presentation. The effect of making this change was an increase in both total drilling and rental revenues and total drilling and rental operating expenses for continuing operations of $32.6 million and $37.6 million for the years ended December 31, 2002 and 2001, respectively, and $4.9 million and $7.1 million for discontinued operations for the years ended December 31, 2002 and 2001, respectively. This revision has no effect on total operating income, net income, cash flows or any balance sheet amount presented.

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 Gulf of Mexico offshore assets consisting of seven jackup rigs and four platform rigs. The Company is actively marketing the assets through an independent broker and expects to complete the sales during 2004. At June 30, 2003, the net book value of the assets to be sold exceeded the estimated fair value and as a result an impairment charge including estimated sales expenses was recognized in the amount of $54.0 million. One Latin America land rig and related spare parts were sold to a third party for $1.8 million in July 2003.

The two operations that constitute this plan of disposition meet the requirements of discontinued operations under the provisions of SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets.” The consolidated financial statements were restated to present the Latin America operations and the U.S. jackup and platform drilling operations as discontinued operations. The discontinued operations assets of $143.4 million at December 31, 2003 are mainly comprised of the estimated fair value of drilling rigs and related spare parts and supplies. The discontinued operations liabilities of $6.4 million at December 31, 2003 consist mainly of deferred revenue and estimated accrued costs to sell the assets. The prior periods presented have been reclassified to reflect the discontinued operations.


	Year Ended December 31,
	2003			2002			2001
	(Dollars in Thousands)
Discontinued operations drilling revenues:
U.S. jackup and platform drilling	$	47,239		$	39,297		$	76,432
Latin America drilling		24,869			40,444			54,063


Total discontinued operation drilling revenues	$	72,108		$	79,741		$	130,495

Discontinued operations operating income (loss):
U.S. jackup and platform drilling	$	6,320		$	1,799		$	27,676
Latin America drilling		4,882			10,080			12,707
Depreciation and amortization		(14,606	)		(30,549	)		(29,370	)

Total discontinued operations operating income (loss)		(3,404	)		(18,670	)		11,013

Other income (expense), net		(276	)		535			220
Provision for impairment of assets		(53,968	)		(360	)		—
Tax expense		(282	)		(7,136	)		(1,159	)

Income (loss) from discontinued operations	$	(57,930	)	$	(25,631	)	$	10,074

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 2 - Disposition of Assets (continued)

Sale of Property - During January 2004, we entered into an agreement to sell our land and buildings in New Iberia, Louisiana. The net sales price approximates $6.4 million which resulted in a provision for impairment of $3.4 million for the property. This impairment was recognized in the December 31, 2003 consolidated financial statements. We will lease certain portions of the land and office building under a two-year operating lease agreement. In addition, three non-marketable rigs in the Asia Pacific region and certain spare parts and equipment in New Iberia were impaired by $2.6 million to estimated salvage value.

Note 3 - Goodwill

Effective January 1, 2002, the Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets.” In accordance with this accounting principle, goodwill is no longer amortized but will be assessed for impairment on at least an annual basis.

As an initial step in the implementation process, the Company identified four reporting units that would be tested for impairment. The four units qualify as reporting units in that they are one level below an operating segment, or an individual operating segment and discrete financial information exists for each unit. The four reporting units identified by segment are as follows:


U.S. drilling segment:		Barge rigs, Jackup and Platform rigs (1)

International drilling segment:		Nigeria barge rigs

Rental tools segment:		Rental tools business

(1) The jackup and platform rigs were aggregated due to the similarities in the markets served.

As required under the transitional accounting provisions of SFAS No. 142, the Company completed both steps required to identify and measure goodwill impairment at each reporting unit. The first step involved identifying all reporting units with carrying values (including goodwill) in excess of fair value, which was estimated by an independent business valuation consultant using the present value of estimated future cash flows. The reporting units for which the carrying value exceeded fair value were then measured for impairment by comparing the implied fair value of the reporting unit goodwill, determined in the same manner as in a business combination, with the carrying amount of goodwill. The jackup and platform rigs reporting unit was the only unit where impairment was identified. As a result, goodwill related to the jackup and platform rigs was impaired by $73.1 million and was recognized as a cumulative effect of a change in accounting principle retroactive to the first quarter 2002. The Company performs its annual impairment review during the fourth quarter of each year. The review in the fourth quarter 2003 resulted in no additional impairment.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 3 - Goodwill (continued)

The following is a summary of the change in goodwill by reporting unit for the years ended December 31, 2001, 2002 and 2003:


							International
	U.S. Drilling						Drilling			Rental Tools
	Segment						Segment			Segment
	Barge			Jackup &			Nigeria			Rental Tools
	Rigs			Platform Rigs			Barge Rigs			Business
	(Dollars in Thousands)
Balance as of January 1, 2001	$	60,743		$	75,974		$	22,334		$	37,558
Goodwill amortization		(2,334	)		(2,830	)		(864	)		(1,454	)

Balance as of December 31, 2001		58,409			73,144			21,470			36,104
Impairment losses		—			(73,144	)		—			—

Balance as of December 31, 2002		58,409			—			21,470			36,104
Write-off of goodwill related to asset disposal		(1,585	)		—			—			—

Balance as of December 31, 2003	$	56,824		$	—		$	21,470		$	36,104

The following is a summary of pro forma net income and earnings per share as adjusted to remove the amortization of goodwill (dollars in thousands, except per share amounts):


	Year Ended December 31,
	2001
Net income - as reported	$	11,059
Goodwill amortization		7,482
Income tax impact (1)		(1,131	)

Net income - as adjusted	$	17,410

Basic earnings per share:
Net income - as reported	$	0.12
Goodwill amortization		0.08
Income tax impact (1)		(0.01	)

Net income - as adjusted	$	0.19

Diluted earnings per share:
Net income - as reported	$	0.12
Goodwill amortization		0.08
Income tax impact (1)		(0.01	)

Net income - as adjusted	$	0.19

(1) Certain goodwill amounts are non-deductible for tax purposes; therefore, the income tax impact reflects only the deductible goodwill amortization.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 4 - Long-Term Debt


	December 31,
	2003		2002
	(Dollars in Thousands)

Senior Notes payable in November 2009 with interest at 10.125% payable semi-annually in May and November, net of unamortized premium of $788 and $922 at December 31, 2003 and 2002, respectively (effective interest rate of 10.03%)	$	236,400	$	236,534

Senior Notes payable in October 2013 with interest at 9.625% payable semi-annually in April and October		175,000		—

Term Loan payable in October 2007 with interest at LIBOR + 4.25% payable monthly		50,000		—

Convertible Subordinated Notes payable in August 2004 with interest at 5.5% payable semi-annually in February and August		105,169		124,509

Secured promissory note to Boeing Capital Corporation with interest at 10.1278%, principal and interest payable monthly over a 60-month term		5,056		10,588

Senior Notes payable in November 2006 with interest at 9.75% payable semi-annually in May and November, net of unamortized premium of $790 at December 31, 2002 (effective interest rate of 9.62%)		—		214,982

Market adjustment for interest rate swap agreements, net of amortization of $257		—		2,363

Capital Lease and Other		—		954


Total debt		571,625		589,930

Less current portion		60,225		6,486


Total long-term debt	$	511,400	$	583,444

The aggregate maturities of long-term debt for the five years ending December 31, 2008 are as follows (000’s): 2004 - $110,225; 2005 - $0; 2006 - $0; 2007 - $50,000; 2008 - $0.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 4 - Long-Term Debt (continued)

In October 2003, the Company refinanced a portion of its existing debt. The total refinancing package was for $325.0 million comprised of $175.0 million of new 9.625% Senior Notes due 2013 and replacement of the senior credit facility with a new $150.0 million senior credit agreement. The senior credit agreement consists of a four-year $100.0 million delayed draw term loan facility and a three-year $50.0 million revolving credit facility. Immediately prior to the refinancing, the Company tendered for the 9.75% Senior Notes due 2006 and obtained the consent from the holders of the 9.75% Senior Notes to eliminate substantially all of the restrictive covenants contained in the indenture governing these Senior Notes and obtained a consent from the holders of our 10.125% Senior Notes due 2009 to acquire up to $75.0 million of the 5.5% Convertible Subordinated Notes due 2004 at a price equal to or less than 100.786 percent of the principal amount of such notes. The proceeds of the new 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 of the proceeds from the new 9.625% Senior Notes and the initial draw down under the term loan facility were used to retire the remaining $29.9 million 9.75% Senior Notes due 2006 that were not tendered. The Company redeemed the remaining notes on November 15, 2003 at a call premium of 1.625 percent. As a result of the new 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 consists of a four-year $100.0 million delayed draw term loan facility and a three-year $50.0 million revolving credit facility that are 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 delayed draw term loan facility may only be utilized to repay the 5.5% Convertible Subordinated Notes. The Company has classified the $50.0 million as long term debt at December 31, 2003 because it intends to use the $50.0 million term loan to retire a portion of the 5.5% Convertible Subordinated Notes. The revolving credit facility portion of the senior credit agreement replaces the previous $50.0 million revolving credit facility that would have expired in late October 2003. The 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. As of December 31, 2003, the borrowing base was $44.7 million, of which none had been drawn down, and $10.6 million had been reserved for letters of credit, resulting in available revolving credit of $34.1 million.

On May 2, 2002, the Company announced it had successfully completed the exchange of $235.6 million in principal amount of new 10.125% Senior Notes due 2009 (“New Notes”) for a like amount of its 9.75% Senior Notes due 2006 (“Outstanding Notes”), pursuant to an exchange offer described in the Offering Circular dated April 1, 2002 (the “Exchange Offer”). The consummation of the Exchange Offer was effected without registration, in reliance on the registration exemption provided by Section 4(2) of the Securities Act of 1933, as amended, which applies to offers and sales of securities that do not involve a public offering, and Regulation D promulgated under that act. On July 1, 2002, the Company filed a registration statement on Form S-4 offering to exchange the New Notes for notes of the Company having substantially identical terms in all material respects as the Outstanding Notes (the “Exchange Notes”). The offer to exchange the New Notes for Exchange Notes was consummated on September 17, 2002. The New Notes and Exchange Notes are governed by the terms of the indenture executed by the Company, the Subsidiary Guarantors and the trustee dated May 2, 2002, the terms of which are substantially the same as the terms of the 1998 Indenture, as amended by the Fourth Supplemental Indenture, as described below.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 4 - Long-Term Debt (continued)

In connection with the Exchange Offer, the Company solicited consents to certain amendments to the definitions and covenants in the indenture under which the Outstanding Notes were issued, which all participants in the Exchange Offer were deemed to have accepted. As a result of the participation in the Exchange Offer of more than 50 percent of the holders of the Outstanding Notes, the amendments to the 1998 Indenture were agreed, and 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 are convertible at the option of the holder into shares of common stock of Parker Drilling at $15.390 per share at any time prior to maturity. The notes are currently redeemable at the option of the Company at a redemption price of 100.786 percent. During the fourth quarter of 2000, the Company repurchased on the open market $50.5 million principal amount of the 5.5% notes at an average price of 86.11 percent of face value, recognizing a gain of $3.9 million, net of $2.2 million of tax. The note repurchases were funded with proceeds from an equity offering in September 2000, whereby the Company sold 13.8 million shares of common stock for net proceeds of approximately $87.3 million. 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 an additional $9.5 million of the outstanding notes in January 2004.

On October 7, 1999, a wholly-owned subsidiary of the Company entered into a loan agreement with Boeing Capital Corporation for the refinancing of a portion of the capital cost of barge rig 75. The loan principal of approximately $24.8 million plus interest is being repaid in 60 monthly payments of approximately $0.5 million. The loan is collateralized by barge rig 75 and is guaranteed by Parker Drilling. The amount of principal outstanding at the end of 2003 was $5.1 million. The Company paid the remaining portion of the note in February 2004 at a 5.0 percent premium.

Each of the 10.125% and the 9.625% Senior Notes, 5.5% Convertible Subordinated Notes and the credit agreement contains customary affirmative and negative covenants, including restrictions on incurrence of debt and sales of assets. The credit agreement contains covenants which require minimum ratios for consolidated leverage, consolidated interest coverage, consolidated secured leverage, consolidated liquidity and limits annual capital expenditures. The credit agreement prohibits payment of dividends and the indentures for the Senior Notes restrict the payment of dividends.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

Set forth on the following pages are the consolidating condensed financial statements of the restricted subsidiaries and our subsidiaries which are not restricted by the Senior Notes. All of the Company’s Senior Notes are guaranteed by substantially all wholly-owned subsidiaries of Parker Drilling. There are currently no restrictions on the ability of the subsidiaries to transfer funds to Parker Drilling in the form of cash dividends, loans or advances. Parker Drilling is a holding company with no operations, other than through its subsidiaries. For years prior to 2002, the non-guarantors were inconsequential, individually and in the aggregate, to the consolidated financial statements and separate financial statements of the guarantors were not presented because management had determined that they would not be material to investors.

In August, 2002, Parker Drilling Company International Limited (“PDCIL”) entered into an agreement to sell two of its rigs in Kazakhstan to AralParker, a Kazakhstan joint venture company owned 50 percent by PDCIL and 50 percent by a Kazakhstan company. Because PDCIL has significant influence over the business affairs of AralParker, its financial statements are consolidated with those of the Company.

AralParker, Casuarina Limited (a wholly-owned captive insurance company) and Parker Drilling Investment Company are all non-guarantor subsidiaries whose aggregate financial position and results of operations are no longer deemed to be inconsequential and, accordingly the Company is providing consolidating condensed financial information of the parent, Parker Drilling, the guarantor subsidiaries, and the non-guarantor subsidiaries as of and for the years ended December 31, 2003 and 2002.

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


	Year Ended December 31, 2003
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Drilling and rental revenues	$	61		$	258,249		$	53,056		$	2,418		$	313,784

Drilling and rental operating expenses		1			156,497			43,889			2,418			202,805
Depreciation and amortization		—			62,968			5,922			—			68,890

Drilling and rental operating income		60			38,784			3,245			—			42,089

Construction contract revenue		—			7,030			—			—			7,030
Construction contract expense		—			5,030			—			—			5,030

Net construction contract operating income		—			2,000			—			—			2,000

General and administrative expense (1)		112			19,144			—			—			19,256
Provision for reduction in carrying value of certain assets		—			6,028			—			—			6,028
Gain on disposition of assets, net		196			14,365			(24	)		(10,980	)		3,557

Total operating income		144			29,977			3,221			(10,980	)		22,362

Other income and (expense):
Interest expense		(58,543	)		(51,438	)		(4,153	)		60,344			(53,790	)
Interest income		55,691			3,928			1,698			(60,344	)		973
Loss on extinguishment of debt		(5,274	)		—			—			—			(5,274	)
Other		(10,979	)		215			447			10,980			663
Equity in net earnings of subsidiaries		(89,105	)		—			—			89,105			—

Total other income and (expense)		(108,210	)		(47,295	)		(2,008	)		100,085			(57,428	)

Income (loss) before income taxes		(108,066	)		(17,318	)		1,213			89,105			(35,066	)
Income tax expense (benefit)		1,633			15,070			—			—			16,703

Income (loss) from continuing operations		(109,699	)		(32,388	)		1,213			89,105			(51,769	)
Discontinued operations, net of taxes		—			(57,930	)		—			—			(57,930	)

Net income (loss)	$	(109,699	)	$	(90,318	)	$	1,213		$	89,105		$	(109,699	)

(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)


	Year Ended December 31, 2002
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Drilling and rental revenues	$	—		$	312,629		$	27,772		$	2,430		$	342,831

Drilling and rental operating expenses		3			191,124			23,477			2,430			217,034
Depreciation and amortization		1			64,776			3,299			(122	)		67,954

Drilling and rental operating income (loss)		(4	)		56,729			996			122			57,843

Construction contract revenue		—			86,818			—			—			86,818
Construction contract expense		—			84,356			—			—			84,356

Net construction contract operating income		—			2,462			—			—			2,462

General and administrative expense (1)		361			24,467			—			(100	)		24,728
Provision for reduction in carrying value of certain assets		—			1,140			—			—			1,140
Gain on disposition of assets, net		15			7,614			(3	)		(4,629	)		2,997

Total operating income (loss)		(350	)		41,198			993			(4,407	)		37,434

Other income and (expense):
Interest expense		(56,602	)		(43,106	)		(1,551	)		48,850			(52,409	)
Interest income		44,264			3,760			1,677			(48,850	)		851
Other		(4,506	)		225			112			178			(3,991	)
Equity in net earnings of subsidiaries		(40,836	)		—			—			40,836			—

Total other income and (expense)		(57,680	)		(39,121	)		238			41,014			(55,549	)

Income (loss) before income taxes		(58,030	)		2,077			1,231			36,607			(18,115	)
Income tax expense (benefit)		(17,120	)		14,284			—			—			(2,836	)

Income (loss) from continuing operations		(40,910	)		(12,207	)		1,231			36,607			(15,279	)
Discontinued operations, net of taxes		—			(25,631	)		—			—			(25,631	)
Cumulative effect of change in accounting principle		(73,144	)		(73,144	)		—			73,144			(73,144	)

Net income (loss)	$	(114,054	)	$	(110,982	)	$	1,231		$	109,751		$	(114,054	)

(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)


	December 31, 2003
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	53,055		$	7,806		$	6,904		$	—		$	67,765
Accounts and notes receivable, net		141,397			92,936			20,724			(166,007	)		89,050
Rig materials and supplies		—			13,627			—			—			13,627
Other current assets		9			2,394			13			50			2,466

Total current assets		194,461			116,763			27,641			(165,957	)		172,908

Property, plant and equipment, net		133			366,389			34,736			(13,594	)		387,664

Assets held for sale		—			150,370			—			—			150,370

Goodwill		—			114,398			—			—			114,398

Investment in subsidiaries and intercompany advances		615,598			661,847			15,399			(1,292,844	)		—

Other noncurrent assets		17,436			4,359			536			(39	)		22,292

Total assets	$	827,628		$	1,414,126		$	78,312		$	(1,472,434	)	$	847,632

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	60,225		$	—		$	—		$	—		$	60,225
Accounts payable and accrued liabilities		32,240			186,259			11,518			(175,422	)		54,595
Accrued income taxes		1,677			12,134			(2	)		—			13,809

Total current liabilities		94,142			198,393			11,516			(175,422	)		128,629

Long-term debt		511,400			—			—			—			511,400
Deferred income taxes		(45,300	)		45,300			—			—			—
Discontinued operations		—			6,421			—			—			6,421
Other long-term liabilities		—			8,552			—			(173	)		8,379
Intercompany payables		74,583			540,844			33,512			(648,939	)		—

Stockholders’ equity:
Common stock		15,696			61,054			121			(61,175	)		15,696
Capital in excess of par value		438,311			1,011,974			5,335			(1,017,309	)		438,311
Unamortized restricted stock plan compensation		(1,885	)		—			—			—			(1,885	)
Accumulated other comprehensive income - net unrealized gain on investments available for sale		881			—			—			—			881
Retained earnings (accumulated deficit)		(260,200	)		(458,412	)		27,828			430,584			(260,200	)

Total stockholders’ equity		192,803			614,616			33,284			(647,900	)		192,803

Total liabilities and stockholders’ equity	$	827,628		$	1,414,126		$	78,312		$	(1,472,434	)	$	847,632

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


	December 31, 2002
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	43,254		$	6,218		$	2,510		$	—		$	51,982
Accounts and notes receivable, net		81,551			100,400			19,080			(111,668	)		89,363
Rig materials and supplies		—			17,161			—			—			17,161
Other current assets		—			8,567			27			37			8,631

Total current assets		124,805			132,346			21,617			(111,631	)		167,137

Property, plant and equipment, net		151			614,088			40,633			(13,594	)		641,278

Assets held for sale		—			896			—			—			896

Goodwill		—			115,983			—			—			115,983

Investment in subsidiaries and intercompany advances		808,784			531,959			21,521			(1,362,264	)		—

Other noncurrent assets		12,556			15,440			(103	)		138			28,031

Total assets	$	946,296		$	1,410,712		$	83,668		$	(1,487,351	)	$	953,325

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Current portion of long-term debt	$	5,532		$	954		$	—		$	—		$	6,486
Accounts payable and accrued liabilities		25,106			150,455			7,218			(132,037	)		50,742
Accrued income taxes		1,069			3,278			—			—			4,347

Total current liabilities		31,707			154,687			7,218			(132,037	)		61,575

Long-term debt		583,444			—			—			—			583,444
Deferred income taxes		(45,473	)		45,473			—			—			—
Other long-term liabilities		1,409			6,271			—			—			7,680
Intercompany payables		74,583			490,099			44,557			(609,239	)		—

Stockholders’ equity:
Common stock		15,465			61,748			121			(61,869	)		15,465
Capital in excess of par value		434,998			1,024,953			5,330			(1,030,283	)		434,998
Accumulated other comprehensive income - net unrealized gain on investments available for sale		664			—			—			—			664
Retained earnings (accumulated deficit)		(150,501	)		(372,519	)		26,442			346,077			(150,501	)

Total stockholders’ equity		300,626			714,182			31,893			(746,075	)		300,626

Total liabilities and stockholders’ equity	$	946,296		$	1,410,712		$	83,668		$	(1,487,351	)	$	953,325

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


	Year Ended December 31, 2003
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	(109,699	)	$	(90,318	)	$	1,213		$	89,105		$	(109,699	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		—			62,968			5,922			—			68,890
Gain on disposition of assets		(196	)		(14,365	)		24			10,980			(3,557	)
Provision for reduction in carrying value of certain assets		—			6,028			—			—			6,028
Other		2,156			4,405			—			—			6,561
Equity in net earnings of subsidiaries		89,105			—			—			(89,105	)		—
Discontinued operations		—			68,574			—			—			68,574
Change in assets and liabilities		(53,159	)		67,415			2,195			9,206			25,657

Net cash (used in) provided by operating activities		(71,793	)		104,707			9,354			20,186			62,454

Cash flows from investing activities:
Proceeds from the sale of assets		142			12,165			30			—			12,337
Capital expenditures (net of reimbursements)		—			(34,895	)		(67	)		—			(34,962	)

Net cash provided by (used in) investing activities		142			(22,730	)		(37	)		—			(22,625	)

Cash flows from financing activities:
Proceeds from issuance of debt		225,000			—			—			—			225,000
Principal payments under debt obligations		(239,064	)		(1,244	)		—			—			(240,308	)
Payment of debt issuance costs		(8,738	)		—			—			—			(8,738	)
Intercompany advances, net		104,254			(79,145	)		(4,923	)		(20,186	)		—

Net cash provided by (used in) financing activities		81,452			(80,389	)		(4,923	)		(20,186	)		(24,046	)

Net increase (decrease) in cash and cash equivalents		9,801			1,588			4,394			—			15,783

Cash and cash equivalents at beginning of year		43,254			6,218			2,510			—			51,982

Cash and cash equivalents at end of year	$	53,055		$	7,806		$	6,904		$	—		$	67,765

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


	Year Ended December 31, 2002
	Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
Cash flows from operating activities:
Net income (loss)	$	(114,054	)	$	(110,982	)	$	1,231		$	109,751		$	(114,054	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		1			64,776			3,299			(122	)		67,954
Gain on disposition of assets		(15	)		(7,614	)		3			4,629			(2,997	)
Cumulative effect of change in accounting principle		—			73,144			—			—			73,144
Provision for reduction in carrying value of certain assets		—			1,140			—			—			1,140
Deferred tax benefit		(17,120	)		—			—			—			(17,120	)
Discontinued operations		—			30,474			—			—			30,474
Other		6,874			4,060			—			(4,889	)		6,045
Equity in net earnings of subsidiaries		113,980			—			—			(113,980	)		—
Change in assets and liabilities		28,477			(25,608	)		(5,853	)		(8,421	)		(11,405	)

Net cash provided by (used in) operating activities		18,143			29,390			(1,320	)		(13,032	)		33,181

Cash flows from investing activities:
Proceeds from the sale of assets		144			6,307			—			—			6,451
Capital expenditures (net of reimbursements)		(81	)		(45,181	)		(43,932	)		44,013			(45,181	)

Net cash provided by (used in) investing activities		63			(38,874	)		(43,932	)		44,013			(38,730	)

Cash flows from financing activities:
Principal payments under debt obligations		(5,489	)		—			—			—			(5,489	)
Proceeds from interest rate swap agreements		2,620			—			—			—			2,620
Intercompany advances, net		(23,020	)		7,630			46,371			(30,981	)		—

Net cash provided by (used in) financing activities		(25,889	)		7,630			46,371			(30,981	)		(2,869	)

Net increase (decrease) in cash and cash equivalents		(7,683	)		(1,854	)		1,119			—			(8,418	)

Cash and cash equivalents at beginning of year		50,937			8,072			1,391			—			60,400

Cash and cash equivalents at end of year	$	43,254		$	6,218		$	2,510		$	—		$	51,982

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 6 - Derivative Financial Instruments

The Company is exposed to interest rate risk from its fixed-rate debt. The Company has hedged against a portion of the risk of changes in fair value associated with its $214.2 million 9.75% Senior Notes by entering into three fixed-to-variable interest rate swap agreements with a total notional amount of $150.0 million. The terms of the interest rate swap agreements are as follows:


Months	Notional Amount		Fixed Rate			Floating Rate
	(Dollars in Thousands)

December 2001 - November 2006	$	50,000		9.75	%	Three-month LIBOR plus 446 basis points
January 2002 - November 2006	$	50,000		9.75	%	Three-month LIBOR plus 475 basis points
January 2002 - November 2006	$	50,000		9.75	%	Three-month LIBOR plus 482 basis points

The Company assumes no ineffectiveness as each interest rate swap agreement meets the short-cut method requirements under SFAS No. 133 for fair value hedges of debt instruments. As a result, changes in the fair value of the interest rate swap agreements are offset by changes in the fair value of the debt and no net gain or loss is recognized in earnings. During the year ended December 31, 2002, the interest rate swap agreements reduced interest expense by $2.9 million.

Note 7 - Income Taxes

Income (loss) before income taxes, discontinued operations and cumulative effect of change in accounting principle is summarized below (dollars in thousands):


	Year Ended December 31,
	2003			2002			2001
United States	$	(33,707	)	$	(34,351	)	$	19
Foreign		(1,359	)		16,236			12,395

	$	(35,066	)	$	(18,115	)	$	12,414

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 7 - Income Taxes (continued)

Income tax expense (benefit) related to continuing operations are summarized as follows (dollars in thousands):


	Year Ended December 31,
	2003		2002			2001
Current:
United States:
Federal	$	—	$	104		$	530
State		—		—			—
Foreign		16,703		14,180			12,798

Deferred:
United States:
Federal		—		(17,120	)		(1,846	)
State		—		—			(53	)

	$	16,703	$	(2,836	)	$	11,429

Total income tax expense (benefit) differs from the amount computed by multiplying income (loss) before income taxes by the U.S. federal income tax statutory rate. The reasons for this difference are as follows (dollars in thousands):


	Year Ended December 31,
	2003						2002						2001
				% of						% of						% of
				Pre-Tax						Pre-Tax						Pre-Tax
	Amount			Income			Amount			Income			Amount			Income
Computed expected tax expense (benefit)	$	(12,273	)		(35	%)	$	(6,340	)		(35	%)	$	4,345			35	%
Foreign taxes, net of federal benefit		10,857			31	%		8,986			50	%		8,319			67	%
Change in valuation allowance		11,858			34	%		(2,927	)		(16	%)		(9,593	)		(77	%)
Foreign corporation income (loss)		1,238			4	%		(5,506	)		(30	%)		8,193			66	%
Permanent differences		4,701			13	%		2,780			15	%		509			4	%
Other		322			1	%		171			1	%		(344	)		(3	%)

Actual tax expense (benefit)	$	16,703			48	%	$	(2,836	)		(15	%)	$	11,429			92	%

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 7 - Income Taxes (continued)

The components of the Company’s tax assets and (liabilities) as of December 31, 2003 and 2002 are shown below (dollars in thousands):


	December 31,
	2003			2002
Deferred tax assets:
Net operating loss carryforwards	$	64,488		$	49,529
Alternative minimum tax carryforwards		401			401
Reserves established against realization of certain assets		3,800			2,937
Accruals not currently deductible for tax purposes		8,879			5,814

		77,568			58,681
Deferred tax liabilities:
Property, plant and equipment		(48,039	)		(43,337	)
Goodwill		(10,662	)		(8,335	)

Net deferred tax (liability) asset		18,867			7,009
Valuation allowance		(18,867	)		(7,009	)

Deferred income tax liability	$	—		$	—

The change in the valuation allowance in 2003 is due to the Company making the determination that it is more likely than not that the benefit of the net operating loss for 2003 will not be fully realizable in future years. The Company has a remaining valuation allowance of $18,867,000 with respect to its net deferred tax asset for the amount of net operating loss carryforwards expected to expire unused. However, the amount of the asset considered realizable could be different in the near term if estimates of future taxable income change.

At December 31, 2003, the Company had $184,252,000 of net operating loss carryforwards. For tax purposes the net operating loss carryforwards expire over a 20-year period ending December 31 as follows: 2007 - $10,141,000; 2008 - $11,968,000; 2009 - $6,700,000; thereafter - $155,443,000.

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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

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, 2003, there were 27,000 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 SEC. As of December 31, 2003, there were 250,754 shares available for granting. The Company issued 755,000 restricted shares in July 2003 to selected key personnel. The shares will become vested as follows: 50 percent of the outstanding restricted shares vesting when the closing stock price is $3.50 or above for thirty consecutive days, the remaining 50 percent will vest when the closing stock price is $5.00 or above for thirty consecutive days. After seven years, all shares will vest regardless of price.

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


	1994 Director Plan
			Weighted
			Average
			Exercise
	Shares		Price
Shares under option:

Outstanding at December 31, 2000		200,000	$	8.431
Granted		—		—
Exercised		—		—
Cancelled		—		—

Outstanding at December 31, 2001		200,000		8.431

Granted		—		—
Exercised		—		—
Cancelled		—		—

Outstanding at December 31, 2002		200,000		8.431

Granted		—		—
Exercised		—		—
Cancelled		—		—

Outstanding at December 31, 2003		200,000	$	8.431

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

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


	1994 Option Plan
	Incentive Options					Non-Qualified Options
				Weighted					Weighted
				Average					Average
				Exercise					Exercise
	Shares			Price		Shares			Price
Shares under option:

Outstanding at December 31, 2000		622,564		$	7.227		1,568,186		$	7.580

Granted		—			—		—			—
Exercised		(17,000	)		4.500		(1,250	)		2.250
Cancelled		—			—		—			—

Outstanding at December 31, 2001		605,564			7.303		1,566,936			7.585

Granted		—			—		—			—
Exercised		—			—		—			—
Cancelled		—			—		—			—

Outstanding at December 31, 2002		605,564			7.303		1,566,936			7.585

Granted		—			—		—			—
Exercised		—			—		—			—
Cancelled		(27,000	)		7.741		—			—

Outstanding at December 31, 2003		578,564		$	7.286		1,566,936		$	7.585


	1997 Stock Plan
	Incentive Options					Non-Qualified Options
				Weighted					Weighted
				Average					Average
				Exercise					Exercise		Restricted
	Shares			Price		Shares			Price		Shares
Shares under option:

Outstanding at December 31, 2000		2,721,901		$	8.158		2,053,335		$	6.556		—

Granted		—			—		1,485,000			5.167		—
Exercised		(137,061	)		3.193		(31,915	)		3.188		—
Cancelled		—			—		—			—		—

Outstanding at December 31, 2001		2,584,840			8.421		3,506,420			6.000		—

Granted		—			—		1,355,000			2.301		30,000
Exercised		(10,196	)		3.188		(8,053	)		3.188		—
Cancelled		(84,884	)		9.020		(105,817	)		6.391		—

Outstanding at December 31, 2002		2,489,760			8.422		4,747,550			4.924		30,000

Granted		62,402			8.322		262,598			3.736		755,000
Exercised		—			—		—			—		(6,000	)
Cancelled		(50,513	)		10.314		(52,488	)		4.020		—

Outstanding at December 31, 2003		2,501,649		$	8.382		4,957,660		$	4.887		779,000

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

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


				Outstanding Options
				Weighted
				Average	Weighted
				Remaining	Average
		Number of		Contractual	Exercise
Plan	Exercise Prices	Shares		Life	Price
1994 Director Plan
Non-qualified	$3.281 - $ 6.125		40,000	3.4 years	$	4.827
Non-qualified	$8.875 - $12.094		160,000	4.5 years	$	9.332

1994 Executive Option Plan
Incentive option	$4.500		210,554	2.0 years	$	4.500
Incentive option	$8.875		368,010	4.4 years	$	8.875
Non-qualified	$2.250		55,500	2.0 years	$	2.250
Non-qualified	$4.500		379,446	2.0 years	$	4.500
Non-qualified	$8.875		1,131,990	4.4 years	$	8.875

1997 Stock Plan
Incentive option	$3.188 - $5.938		786,984	2.4 years	$	3.364
Incentive option	$8.875 - $12.188		1,714,665	3.2 years	$	10.685
Non-qualified	$1.960 - $6.070		3,789,825	4.2 years	$	3.603
Non-qualified	$8.875 - $10.813		1,167,835	3.6 years	$	9.053


		Exercisable Options
				Weighted
				Average
		Number of		Exercise
Plan	Exercise Prices	Shares		Price
1994 Director Plan
Non-qualified	$3.281 - $6.125		40,000	$4.827
Non-qualified	$8.875 - $12.094		160,000	$9.332

1994 Executive Option Plan
Incentive option	$4.500		210,554	$4.500
Incentive option	$8.875		368,010	$8.875
Non-qualified	$2.250		55,500	$2.250
Non-qualified	$4.500		379,446	$4.500
Non-qualified	$8.875		1,131,990	$8.875

1997 Stock Plan
Incentive option	$3.188 - $5.938		786,984	$3.364
Incentive option	$8.875 - $12.188		1,714,665	$10.685
Non-qualified	$1.960 - $6.070		2,709,825	$3.737
Non-qualified	$8.875 - $12.094		1,167,835	$9.053

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

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

The Company has three additional stock plans which provide for the issuance of stock for no cash consideration to officers and key non-officer employees. Under two of the plans, each employee receiving a grant of shares may dispose of 15 percent of the grant on each annual anniversary date from the date of grant for the first four years and the remaining 40 percent on the fifth-year anniversary. These two plans have a total of 11,375 shares reserved and available for granting. Shares granted under the third plan are fully vested no earlier than 24 months from the effective date of the grant and not later than 36 months. The third plan has a total of 1,562,195 shares reserved and available for granting. No shares were granted under these plans in 2003, 2002 and 2001.

At December 31, 2003 and 2002, 506,577 shares were held in Treasury.

Stock Reserved for Issuance

The following is a summary of common stock reserved for issuance:


	December 31,
	2003		2002
Stock plans		12,449,066		12,441,135
Stock bonus plan		947,353		1,577,221
Convertible notes		6,833,593		8,090,254

Total shares reserved for issuance		20,230,012		22,108,610

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)


	For the Year Ended December 31, 2003
	Loss			Shares		Per-Share
	(Numerator)			(Denominator)		Amount
Basic EPS:
Loss from continuing operations	$	(51,769,000	)		93,420,713	$	(0.55	)
Discontinued operations, net of taxes		(57,930,000	)				(0.62	)

Net loss	$	(109,699,000	)			$	(1.17	)

Effect of dilutive securities:
Stock options		—			—		—

Diluted EPS:
Loss from continuing operations	$	(51,769,000	)			$	(0.55	)
Discontinued operations, net of taxes		(57,930,000	)				(0.62	)

Net loss	$	(109,699,000	)			$	(1.17	)


	For the Year Ended December 31, 2002
	Loss			Shares		Per-Share
	(Numerator)			(Denominator)		Amount
Basic EPS:
Loss from continuing operations	$	(15,279,000	)		92,444,773	$	(0.16	)
Discontinued operations, net of taxes		(25,631,000	)				(0.28	)
Cumulative effect of change in accounting principle		(73,144,000	)				(0.79	)

Net loss	$	(114,054,000	)			$	(1.23	)

Effect of dilutive securities:
Stock options		—			—		—

Diluted EPS:
Loss from continuing operations	$	(15,279,000	)			$	(0.16	)
Discontinued operations, net of taxes		(25,631,000	)				(0.28	)
Cumulative effect of change in accounting principle		(73,144,000	)				(0.79	)

Net loss	$	(114,054,000	)			$	(1.23	)

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, 2001
	Income		Shares		Per-Share
	(Numerator)		(Denominator)		Amount
Basic EPS:
Income from continuing operations	$	985,000		92,008,877	$	0.01
Discontinued operations, net of taxes		10,074,000				0.11

Net income	$	11,059,000			$	0.12

Effect of dilutive securities:
Stock options		—		682,156		—

Diluted EPS:
Income from continuing operations	$	985,000		92,691,033	$	0.01
Discontinued operations, net of taxes		10,074,000				0.11

Net income plus assumed conversions	$	11,059,000			$	0.12

The Company has outstanding $105,169,000 of 5.5% Convertible Subordinated Notes, which are convertible into 6,833,593 shares of common stock at $15.39 per share. The Notes have been outstanding since their issuance in July 1997, but were not included in the computation of diluted EPS because the assumed conversion of the Notes would have had an anti-dilutive effect on EPS. For the year ended December 31, 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 incurred for 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. For the fiscal year ended December 31, 2001, options to purchase 6,049,000 shares of common stock at prices ranging from $5.00 to $12.188, which were outstanding during the period, were not included in the computation of diluted EPS because the options’ exercise prices were greater than the average market price of the common shares during the period.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

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 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 627,732; 544,844; and 343,289 shares to the Plan in 2003, 2002 and 2001 with the Company recognizing expense of $1.5 million; $1.5 million; and $1.9 million in each of the periods, respectively.

Parker Drilling Company Limited (“PDCL”), a wholly-owned subsidiary of the Company, maintains an unfunded, deferred compensation “Compensation Plan” on behalf of certain designated non-resident alien employees of PDCL, which is maintained outside of the United States. The Compensation Plan gives participants the option to defer from two percent to 100 percent of the participant’s base pay and between five percent and 100 percent of the participant’s bonus pay for a minimum period of two years. The Compensation Plan provides that PDCL agrees to match up to three percent of the participant’s base pay and bonus pay which shall be posted to the account of the participant. The participant may direct PDCL to invest deferrals posted to the participant’s account in investment funds as determined by the chief operating officer of the Company. All benefits payable under the plan constitute general corporation obligations which shall be subject to the claims of general creditors of PDCL in the event of PDCL’s insolvency. PDCL may amend or terminate this plan at its discretion at any time, at which time all account balances shall be paid in a lump sum to the participant or their designated beneficiary. The Compensation Plan was valued at $1.7 million and $1.9 millions as of December 31, 2003 and 2002, respectively. The Company recognized expense of $0.2 million; $0.5 million; and $40 thousand in each of the years ending December 31, 2003, 2002 and 2001.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 11 - Business Segments

The Company is organized into three primary business segments: U.S. drilling operations, international drilling operations, and rental tools. This is the basis management uses for making operating decisions and assessing performance.


	Year Ended December 31,
Operations by Industry Segment	2003			2002			2001
	(Dollars in Thousands)
Drilling and rental revenues:
U.S. drilling (1)	$	67,449		$	78,330		$	118,998
International drilling (1)		191,698			216,991			210,427
Rental tools (1)		54,637			47,510			65,629

Total drilling and rental revenues		313,784			342,831			395,054

Drilling and rental operating income (loss):
U.S. drilling		(221	)		6,296			24,972
International drilling		24,726			38,529			34,809
Rental tools		17,584			13,018			29,943

Total drilling and rental operating income (loss)		42,089			57,843			89,724

Net construction contract operating income		2,000			2,462			—
General and administrative expense		(19,256	)		(24,728	)		(21,721	)
Provision for reduction in carrying value of certain assets		(6,028	)		(1,140	)		—
Gain on disposition of assets, net		3,557			2,997			1,757
Reorganization expense		—			—			(7,500	)

Total operating income		22,362			37,434			62,260

Interest expense		(53,790	)		(52,409	)		(53,015	)
Loss on extinguishment of debt		(5,274	)		—			—
Minority interest		464			278			—
Other income (expense)		1,172			(3,418	)		3,169

Income (loss) from continuing operations before income taxes	$	(35,066	)	$	(18,115	)	$	12,414

Identifiable assets: (2)
U.S. drilling	$	227,479		$	307,811		$	343,357
International drilling		413,338			418,665			424,022
Rental tools		77,940			69,998			70,365

Total identifiable assets		718,757			796,474			837,744

Corporate assets		128,875			156,851			268,033

Total assets	$	847,632		$	953,325		$	1,105,777

(1) U.S. drilling segment includes $7.3 million in revenues from ChevronTexaco Corporation; International drilling segment includes $56.2 million, $53.1 million and $10.3 million in revenues from Royal Dutch Shell, Tengizchevroil and ChevronTexaco Corporation respectively; Rental tools segment includes $7.1 million in revenues from ChevronTexaco Corporation.

(2) Includes assets related to discontinued operations.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 11 - Business Segments (continued)


	Year Ended December 31,
Operations by Geographic Area	2003			2002			2001
	(Dollars in Thousands)
Drilling and rental revenues:
United States	$	122,086		$	125,840		$	184,627
Asia Pacific		28,492			40,124			34,037
Africa and Middle East		56,601			73,873			82,273
CIS		106,605			102,994			94,117

Total drilling and rental revenues		313,784			342,831			395,054

Drilling and rental operating income (loss):
United States		17,411			19,314			54,915
Latin America		(1,078	)		(968	)		(4	)
Asia Pacific		3,237			14,224			11,259
Africa and Middle East		3,210			9,103			11,733
CIS		19,309			16,170			11,821

Total drilling and rental operating income (loss)		42,089			57,843			89,724

Net construction contract operating income (United States)		2,000			2,462			—
General and administrative expense		(19,256	)		(24,728	)		(21,721	)
Provision for reduction in carrying value of certain assets		(6,028	)		(1,140	)		—
Gain on disposition of assets, net		3,557			2,997			1,757
Reorganization expense		—			—			(7,500	)

Total operating income		22,362			37,434			62,260

Interest expense		(53,790	)		(52,409	)		(53,015	)
Loss on extinguishment of debt		(5,274	)		—			—
Minority interest		464			278			—
Other income (expense)		1,172			(3,418	)		3,169

Income (loss) from continuing operations before income taxes	$	(35,066	)	$	(18,115	)	$	12,414

Identifiable assets: (1)
United States	$	434,294		$	534,660		$	681,756
Latin America		104,817			88,985			93,722
Asia Pacific		55,520			46,385			39,963
Africa and Middle East		81,283			99,496			94,986
CIS		171,718			183,799			195,350

Total identifiable assets	$	847,632		$	953,325		$	1,105,777

(1) Includes assets related to discontinued operations

Note 12 - Commitments and Contingencies

At December 31, 2003, the Company had a $50.0 million revolving credit facility available for general corporate purposes and to support letters of credit. As of December 31, 2003, $10.6 million of availability has been reserved to support letters of credit that have been issued. At December 31, 2003, no amounts had been drawn under the revolving credit facility.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 12 - Commitments and Contingencies (continued)

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, 2003, under operating leases with non-cancelable terms in excess of one year, are as follows (dollars in thousands):


2004	$	4,133
2005		2,467
2006		2,231
2007		2,159
2008		2,842
Thereafter		877

Total	$	14,709

Total rent expense for all operating leases amounted to $10.3 million for 2003, $10.9 million for 2002, and $5.5 million for 2001.

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. Potter’s which became effective in June 2003. The term of each agreement is for three years and each provides for automatic extensions of two years, with the exception of Mr. Brassfield, Mr. Gass 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. 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 CEO (or the board of directors in case of CEO and Chairman) on an annual basis but cannot be reduced except with consent of the executive;

• payment of target bonuses of up to 100 percent of salary based on meeting certain incentives (75 percent for Mr. Nash and Mr. Whalen and 50 percent for Mr. Brassfield, Mr. Gass and Mr. Graham and 30 percent for Mr. Potter); and

• eligible to receive stock options and 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, Mr. Gass 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, Mr. Gass 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”).

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 12 - Commitments and Contingencies (continued)

In consideration for these benefits the executive agrees to perform his customary duties set forth in the employment agreement, and further covenants not to solicit business except on behalf of the Company during his employment and to refrain from hiring employees of the Company or to compete against the Company for a period of one year following his termination.

In addition to the above benefits, each employment agreement provides that in the event of a change in control, as defined in the agreement, the term of the employment agreement will be extended for three years. If the executive is terminated during this three year period for any reason except for cause or the executive resigns during the first two years after the change in control for good reason, the Additional Benefit payable shall be based on three times salary and bonus, payable in a lump sum, and the Other Benefits shall also be provided for three years. In certain circumstances, the Company has agreed to make the executive whole for excise taxes that may apply with respect to payments made after a change in control. The benefits provided under the employment agreements executed by the executive officers are in lieu of and replace the benefits under the Severance Compensation and Consulting Agreements previously executed by certain executive officers, which Severance Compensation and Consulting Agreements have been terminated.

The drilling of oil and gas wells is subject to various federal, state, local and foreign laws, rules and regulations. The Company, as an owner or operator of both onshore and offshore facilities operating in or near waters of the United States, may be liable for the costs of removal and damages arising out of a pollution incident to the extent set forth in the Federal Water Pollution Control Act, as amended by the Oil Pollution Act of 1990 (“OPA”) and the Outer Continental Shelf Lands Act. In addition, the Company may also be subject to applicable state law and other civil claims arising out of any such incident. Certain of the Company’s facilities are also subject to regulations of the Environmental Protection Agency (“EPA”) that require the preparation and implementation of spill prevention, control and countermeasure plans relating to possible discharge of oil into navigable waters. Other regulations of the EPA may require certain precautions in storing, handling and transporting hazardous wastes. State statutory provisions relating to oil and natural gas generally include requirements as to well spacing, waste prevention, production limitations, pollution prevention and cleanup, obtaining drilling and dredging permits and similar matters.

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 (see Note 17 in the notes to the consolidated financial statements).

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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 13 - Related Party Transactions (continued)

As of December 31, 2003, the accrued amount of premiums paid by the Company on the policies and to be reimbursed by the Trust to the Company was $4.7 million. Due to the adoption of the Sarbanes-Oxley Act of 2002 (“SOX”), additional loans to executive officers and directors may be prohibited, although continuance of loans in existence as of July 30, 2002, are allowed; provided there is no modification to such loans. Because the advancement of additional annual premiums by the Company may be considered a prohibited loan under SOX, the Company elected to not advance the $0.6 million premium that was due in December 2002 and 2003 pending further clarification from the Securities and Exchange Commission as to how the Company’s obligation to advance these premiums under the Agreement can be honored without violating SOX.

Note 14 - Supplementary Information

At December 31, 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. At December 31, 2002, accrued liabilities included $8.5 million of accrued interest expense, $4.4 million of workers’ compensation and health plan liabilities and $7.0 million of accrued payroll and payroll taxes. Other long-term obligations included $4.4 million and $4.7 million of workers’ compensation liabilities as of December 31, 2003 and 2002, respectively.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 15 - Selected Quarterly Financial Data (Unaudited)


	Quarter
Year 2003	First			Second			Third			Fourth (2)			Total
	(Dollars in Thousands Except Per Share Amounts)

Revenues	$	77,970		$	73,866		$	77,016		$	84,932		$	313,784

Drilling and rental operating income	$	10,966		$	6,974		$	8,567		$	15,582		$	42,089

Operating income	$	6,332		$	2,760		$	5,893		$	7,377		$	22,362

Loss from continuing operations	$	(10,588	)	$	(13,719	)	$	(10,613	)	$	(16,849	)	$	(51,769	)

Discontinued operations, net of taxes	$	(5,613	)	$	(60,689	)	$	3,957		$	4,415		$	(57,930	)

Net loss	$	(16,201	)	$	(74,408	)	$	(6,656	)	$	(12,434	)	$	(109,699	)

Basic earnings (loss) per share:
Loss from continuing operations	$	(0.11	)	$	(0.15	)	$	(0.11	)	$	(0.18	)	$	(0.55	)
Discontinued operations, net of taxes	$	(0.06	)	$	(0.65	)	$	0.04		$	0.05		$	(0.62	)
Net loss	$	(0.17	)	$	(0.80	)	$	(0.07	)	$	(0.13	)	$	(1.17	)

Diluted earnings (loss) per share: (1)
Loss from continuing operations	$	(0.11	)	$	(0.15	)	$	(0.11	)	$	(0.18	)	$	(0.55	)
Discontinued operations, net of taxes	$	(0.06	)	$	(0.65	)	$	0.04		$	0.05		$	(0.62	)
Net loss	$	(0.17	)	$	(0.80	)	$	(0.07	)	$	(0.13	)	$	(1.17	)

(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.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 15 - Selected Quarterly Financial Data (continued) (Unaudited)


	Quarter
Year 2002	First			Second			Third			Fourth			Total
	(Dollars in Thousands Except Per Share Amounts)

Revenues	$	86,203		$	83,659		$	87,247		$	85,722		$	342,831

Drilling and rental operating income	$	13,758		$	10,932		$	16,961		$	16,192		$	57,843

Operating income	$	9,016		$	5,642		$	12,075		$	10,701		$	37,434

Loss from continuing operations	$	(1,793	)	$	(7,672	)	$	(176	)	$	(5,638	)	$	(15,279	)

Discontinued operations, net of taxes	$	(9,276	)	$	(3,817	)	$	(7,844	)	$	(4,694	)	$	(25,631	)

Cumulative effect of change in accounting principle (2)	$	(73,144	)	$	—		$	—		$	—		$	(73,144	)

Net loss	$	(84,213	)	$	(11,489	)	$	(8,020	)	$	(10,332	)	$	(114,054	)

Basic loss per share:
Loss from continuing operations	$	(0.02	)	$	(0.08	)	$	(0.00	)	$	(0.06	)	$	(0.16	)
Discontinued operations, net of taxes	$	(0.10	)	$	(0.04	)	$	(0.09	)	$	(0.05	)	$	(0.28	)
Cumulative effect of change in accounting principle (2)	$	(0.79	)	$	—		$	—		$	—		$	(0.79	)
Net loss	$	(0.91	)	$	(0.12	)	$	(0.09	)	$	(0.11	)	$	(1.23	)

Diluted loss per share: (1)
Loss from continuing operations	$	(0.02	)	$	(0.08	)	$	(0.00	)	$	(0.06	)	$	(0.16	)
Discontinued operations, net of taxes	$	(0.10	)	$	(0.04	)	$	(0.09	)	$	(0.05	)	$	(0.28	)
Cumulative effect of change in accounting principle (2)	$	(0.79	)	$	—		$	—		$	—		$	(0.79	)
Net loss	$	(0.91	)	$	(0.12	)	$	(0.09	)	$	(0.11	)	$	(1.23	)

(2) The first quarter includes recognition of $73.1 million goodwill impairment related to the jackup and platform rigs resulting from the adoption of SFAS No. 142. The impairment provision was included in the second quarter Form 10-Q, retroactive to January 1, 2002.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 16 - Recent Accounting Pronouncements

In January 2003, the FASB issued FASB Interpretation (“FIN”) 46, “Consolidation of Variable Interest Entities an Interpretation of ARB No. 51.” A Variable Interest Entity (“VIE”) is created when: (i) the equity investment at risk is not sufficient to permit the entity from financing its activities without additional subordinated financial support from other parties or (ii) equity holders at risk either: (a) lack direct or indirect ability to make decisions about the entity, (b) are not obligated to absorb expected losses of the entity or (c) do not have the right to receive expected residual returns of the entity if they occur. If an entity is deemed to be a VIE, pursuant to FIN 46, an enterprise that absorbs the majority of the expected losses of the VIE is considered the primary beneficiary and must consolidate the VIE. The application of FIN 46 (as amended by FIN 46-R) is required in financial statements of public entities that have interests in variable interest entities or potential variable interest entities commonly referred to as special-purpose entities for periods ending after December 15, 2003. Application by public entities (other than small business issuers) for all other types of entities is required in financial statements for periods ending after March 15, 2004. The Company adopted this interpretation in December 2003 and implementation of this interpretation did not have a material effect on our results of operations or our financial position.

In December 2003, the Securities and Exchange Commission issued Staff Accounting Bulletin (“SAB”) No. 104, “Revenue Recognition,” which supersedes SAB No. 101, “Revenue Recognition in Financial Statements.” SAB No. 104’s primary purpose is to rescind accounting guidance contained in SAB No. 101 related to multiple element revenue arrangements, which was superseded as a result of the issuance of Emerging Issues Task Force (“EITF”) No. 00-21, “Accounting for Revenue Arrangements with Multiple Deliverables.” While the wording of SAB No. 104 has changed to reflect the issuance of EITF No. 00-21, the revenue recognition principles of SAB No. 101 remain largely unchanged by the issuance of SAB No. 104. The implementation of SAB No. 104 is not expected to effect the Company’s financial position or results of operations.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (continued)

Note 17 - Subsequent Event - Kazakhstan Tax Issue

On July 6, 2001, the Ministry of State Revenues of Kazakhstan (“MSR”) issued an Act of Audit to the Kazakhstan branch (“PKD Kazakhstan”) of Parker Drilling Company International Limited (“PDCIL”), a wholly-owned subsidiary of the Company, assessing additional taxes of approximately $29.0 million for the years 1998-2000. The assessment consisted primarily of adjustments in corporate income tax based on a determination by the Kazakhstan tax authorities that payments by Offshore Kazakhstan International Operating Company, (“OKIOC”), to PDCIL of $99.0 million, in reimbursement of costs for modifications to rig 257, performed by PDCIL prior to the importation of the drilling rig into Kazakhstan, are income to PKD Kazakhstan, and therefore, taxable to PKD Kazakhstan. PKD Kazakhstan sought judicial review of the assessment and in March 2002 the Supreme Court confirmed the decision of the Astana City Court that the reimbursements were not income to PKD Kazakhstan. Although the MSR did not appeal the decision of the Civil Panel to the Supervisory Panel of the Supreme Court of Kazakhstan within the required time period and has not offered any material new evidence to re-open the case, the Ministry of Finance of Kazakhstan (“MinFin”) has made additional claims against PKD Kazakhstan by applying its interpretation of the Supreme Court decision. Specifically, MinFin has made a claim for additional corporate income taxes based primarily on the disallowance of depreciation of the full value of 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 and in December 2003 the Astana City Court issued a decision confirming a substantial portion of the claims of MinFin. This decision was appealed by PKD Kazakhstan and on March 5, 2004, the Supreme Court issued a judgment confirming the decision of the Astana City Court. Although the judgment provides that the claims approved by the Astana City Court of approximately $7.7 million are valid and payable upon receipt of the re-issuance of the corrected notice from the relevant taxing authority, the incremental amount which PKD Kazakhstan will ultimately be required to pay after the application of approximately $5.0 million in credits available to PKD Kazakhstan, will be approximately $3.0 million, which amount is fully reserved on the financial books of the Company. While the disallowance of depreciation for the years 1999-2001 will result in a cash payment at this time, the judgment does allow PKD Kazakhstan to depreciate the full value of rig 257 on its tax returns beginning in 2002, which will reduce taxable income and taxes to be paid in the future. In addition, 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 our petition and has initiated proceedings with the MSR which are ongoing.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

This item is not applicable to the Company in that disclosure is required under Regulation S-X by the Securities and Exchange Commission only if the Company had changed independent auditors and, if it had, only under certain circumstances.

ITEM 9A. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures - The Company’s management, with the participation of our chief executive officer and chief financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Security Exchange Act of 1934, as amended (the “Exchange Act”)) as of the end of the period covered by this annual report. Based on such evaluation, our chief executive officer and chief financial officer have concluded that, as of the end of such period, our disclosure controls and procedures are effective in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by us in the reports that we file or submit under the Exchange Act.

Internal Control Over Financial Reporting - There have not been any changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) under the Exchange Act) during the quarter ended December 31, 2003, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Information with respect to directors can be found under the caption “Item 1 - - Election of Directors” of our proxy statement for the Annual Meeting of Shareholders to be held on April 28, 2004. 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.

The information in the proxy statement set forth under the caption: “Section 16(a) Beneficial Reporting Compliance” is incorporated herein by reference.

We have adopted the Parker Drilling Code of Corporate Conduct (“CCC”) which include a code of financial ethics that is applicable to our chief executive officer, chief financial officer, controller and other senior financial personnel as required by the Securities and Exchange Commission (“Commission”). We have recently amended the CCC to include provisions that will ensure compliance with the minimum requirements under the new corporate governance listing standards of the NYSE. The CCC is publicly available on our 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 we amend the CCC, we will disclose the nature of the waiver or amendment on our web site and in a report on Form 8-K.”

ITEM 11. EXECUTIVE COMPENSATION

Notwithstanding the foregoing, in accordance with the instructions to Item 402 of Regulations S-K, the information contained in the Company’s proxy statement under the sub-heading “Compensation Committee Report on Executive Compensation” and “Performance Graph” shall not be deemed to be filed as part of or incorporated by reference into this Form 10-K.

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

The information required by this item is hereby incorporated by reference from the information appearing under the captions “Principal Stockholders and Security Ownership of Management” and “Equity Compensation Plan Information” in the Company’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 28, 2004, to be filed with the Commission within 120 days of the end of the Company’s year ended December 31, 2003.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by this item is hereby incorporated by reference to such information appearing under the caption “Other Information” and “Related Transactions” in the Company’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 28, 2004, to be filed with the Commission within 120 days of the end of the Company’s year ended December 31, 2003.

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” in the Company’s definitive proxy statement for the Annual Meeting of Shareholders to be held April 28, 2004, to be filed with the Commission within 120 days of the end of the Company’s year ended December 31, 2003.

PART IV

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K

(a) The following documents are filed as part of this report:

(1)	Financial Statements of Parker Drilling Company and subsidiaries which are included in Part II, Item 8:


		PAGE
	Report of Independent Accountants		37
	Consolidated Statement of Operations for the years ended December 31, 2003, 2002 and 2001		38
	Consolidated Balance Sheet as of December 31, 2003 and 2002		39
	Consolidated Statement of Cash Flows for the years ended December 31, 2003, 2002 and 2001		41
	Consolidated Statement of Stockholders’ Equity for the years ended December 31, 2003, 2002 and 2001		43
	Notes to the Consolidated Financial Statements		44

(2)	Financial Statement Schedule:
	Schedule II - Valuation and qualifying accounts		85

(3)	Exhibits:


EXHIBIT NUMBER		DESCRIPTION
3(a)	-	Corrected Restated Certificate of Incorporation of the Company, as amended on September 21, 1998 (incorporated by reference to Exhibit 3(c) to the Company’s Annual Report on Form 10-K for the fiscal year ended August 31, 1998).

3(b)	-	Rights Agreement dated as of July 14, 1998 between the Company and Norwest Bank Minnesota, N.A., as rights agent (incorporated by reference to Form 8-A filed July 15, 1998.)

3(c)	-	Amendment No. 1 to the Rights Agreement dated as of September 22, 1998 between the Company and Norwest Bank Minnesota, N.A., as rights agent.

3(d)	-	By-laws of the Company, as amended January 31, 2003.

4(a)	-	Indenture dated as of May 2, 2002 between the Company and JPMorgan Chase Bank, as Trustee, respecting the 10.125% Senior Notes due 2009 (incorporated by reference to Exhibit 4.1 to the Company’s S-4 Registration Statement No. 333-91708).

4(b)	-	Indenture dated as of July 25, 1997, between the Company and JPMorgan Chase Bank, as Trustee, respecting the 5.5% Convertible Subordinated Notes due 2004 (incorporated by reference to Exhibit 4.7 to the Company’s S-3 Registration Statement No. 333-30711).

4(c)	-	First Supplemental Indenture dated as of May 2, 2002, between Parker Drilling Company and Subsidiary Guarantors and JPMorgan Chase Bank as Trustee, respecting the 10.125% Senior Notes due 2009.

4(d)	-	Second Supplemental Indenture dated as of February 1, 2003, between Parker Drilling Company and Subsidiary Guarantors and JPMorgan Chase Bank as Trustee, respecting the 10.125% Senior Notes due 2009.

4(e)	-	Third Supplemental Indenture dated as of October 7, 2003, between Parker Drilling Company and Subsidiary Guarantors and JPMorgan Chase Bank as Trustee, respecting the 10.125% Senior Notes due 2009.

4(f)	-	Fourth Supplemental Indenture dated as of October 10, 2003, between Parker Drilling Company and Subsidiary Guarantors and JPMorgan Chase Bank as Trustee, respecting the 10.125% Senior Notes due 2009.

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K (continued)

(3) Exhibits: (continued)


4(g)	-	Indenture dated as of October 10, 2003 between the Company, as issuer, certain Subsidiary Guarantors (as defined therein) and JPMorgan Chase Bank, as Trustee, respecting the 9.625% Senior Notes due 2013 (incorporated by reference to the Company’s S-4 Registration Statement No. 333-110374 dated November 10, 2003).

10(a)	-	Amended and Restated Parker Drilling Company Stock Bonus Plan, effective as of January 1, 1999 (incorporated herein by reference to Exhibit 10(a) to the Company’s Quarterly Report on Form 10-Q for the three months ended March 31, 1999).*

10(b)	-	1994 Parker Drilling Company Deferred Compensation Plan (incorporated herein by reference to Exhibit 10(h) to Annual Report on Form 10-K for the year ended August 31, 1995).*

10(c)	-	1994 Non-Employee Director Stock Option Plan (incorporated herein by reference to Exhibit 10(i) to Annual Report on Form 10-K for the year ended August 31, 1995).*

10(d)	-	1994 Executive Stock Option Plan (incorporated herein by reference to Exhibit 10(j) to Annual Report on Form 10-K for the year ended August 31, 1995).*

10(e)	-	Third Amended and Restated 1997 Stock Plan effective July 24, 2002.*

10(f)	-	Parker Drilling Company and Subsidiaries 1991 Stock Grant Plan (Incorporated herein by reference to Exhibit 10(c) to Annual Report on Form 10-K for the year ended August 31, 1992).*

10(g)	-	Form of Indemnification Agreement entered into between Parker Drilling Company and each director and executive officer of Parker Drilling Company, dated on or about October 15, 2002.*

10(h)	-	Form of Employment Agreement entered into between Parker Drilling Company and each executive officer of Parker Drilling Company.*

10(i)	-	Separation Agreement and Release entered into between Thomas L. Wingerter and Parker Drilling Company effective September 30, 2003.*

21	-	Subsidiaries of the Registrant.

23	-	Consent of Independent Accountants.

31.1	-	Robert L. Parker Jr., President and Chief Executive Officer, Rule 13a-14(a)/15d-14(a) Certification.

31.2	-	James W. Whalen, Senior Vice President and Chief Financial Officer, Rule 13a-14(a)/15d-14(a) Certification.

32.1	-	Robert L. Parker Jr., President and Chief Executive Officer, Section 1350 Certification.

32.2	-	James W. Whalen, Senior Vice President and Chief Financial Officer, Section 1350 Certification.

		* Management Contract, Compensatory Plan or Agreement

(b) Reports on Form 8-K: None.

PARKER DRILLING COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Dollars in Thousands)


Column A	Column B		Column C			Column D		Column E
	Balance		Charged
	at		to cost					Balance
	beginning		and					at end of
Classifications	of period		expenses			Deductions		period
Year ended December 31, 2003:
Allowance for doubtful accounts and notes	$	4,763	$	420		$	451	$	4,732
Reduction in carrying value of rig materials and supplies	$	3,443	$	2,400		$	1,162	$	4,681
Deferred tax valuation allowance	$	7,009	$	11,858		$	—	$	18,867

Year ended December 31, 2002:
Allowance for doubtful accounts and notes	$	2,988	$	1,904		$	129	$	4,763
Reduction in carrying value of rig materials and supplies	$	2,406	$	2,400		$	1,363	$	3,443
Deferred tax valuation allowance	$	9,936	$	(2,927	)	$	—	$	7,009

Year ended December 31, 2001:
Allowance for doubtful accounts and notes	$	3,755	$	360		$	1,127	$	2,988
Reduction in carrying value of rig materials and supplies	$	2,491	$	1,455		$	1,540	$	2,406
Deferred tax valuation allowance	$	24,939	$	(9,593	)	$	5,410	$	9,936

SIGNATURES

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


PARKER DRILLING COMPANY

By:	/s/ Robert L. Parker Jr.	Date: March 10, 2004

	Robert L. Parker Jr.
	President and Chief Executive Officer and Director

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.


Signature		Title	Date
By:	/s/ Robert L. Parker	Chairman of the Board and Director	March 10, 2004

	Robert L. Parker

By:	/s/ Robert L. Parker Jr.	President and Chief Executive Officer and Director	March 10, 2004
	Robert L. Parker Jr.	(Principal Executive Officer)

By:	/s/ James W. Whalen	Senior Vice President and	March 10, 2004
		Chief Financial Officer
	James W. Whalen	(Principal Financial Officer)

By:	/s/ Robert F. Nash	Senior Vice President and	March 10, 2004
		Chief Operating Officer
	Robert F. Nash

By:	/s/ W. Kirk Brassfield	Vice President and Controller	March 10, 2004
		(Principal Accounting Officer)
	W. Kirk Brassfield

By:	/s/ James E. Barnes	Director	March 10, 2004

	James E. Barnes

By:	/s/ Bernard J. Duroc-Danner	Director	March 10, 2004

	Bernard J. Duroc-Danner

By:	/s/ Dr. Robert M. Gates	Director	March 10, 2004

	Dr. Robert M. Gates

By:	/s/ John W. Gibson	Director	March 10, 2004

	John W. Gibson

By:	/s/ R. Rudolph Reinfrank	Director	March 10, 2004

	R. Rudolph Reinfrank


(MARK ONE)
	[X]	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003

	[ ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		FOR THE TRANSITION PERIOD FROM _______ TO _______


Delaware		73-0618660

(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)


Title of each class		Name of each exchange on which registered:

Common Stock, par value $0.16 2/3 per share		New York Stock Exchange


PART I
	Item 1. BUSINESS
	ITEM 2. PROPERTIES
	ITEM 3. LEGAL PROCEEDINGS
	ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
	ITEM 4A. EXECUTIVE OFFICERS
PART II
	ITEM 5. MARKET FOR REGISTRANT’S COMMON STOCK AND RELATED STOCKHOLDER MATTERS
	Item 6. SELECTED FINANCIAL DATA
	Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
	Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
	Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
	Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
	Item 9A. CONTROLS AND PROCEDURES
PART III
	Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
	Item 11. EXECUTIVE COMPENSATION
	Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
	Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
	Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
PART IV
	Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE AND REPORTS ON FORM 8-K
SIGNATURES
INDEX TO EXHIBITS
Second Supplemental Indenture
Separation Agreement - James Davis
Subsidiaries of the Registrant
Consent of Independent Accountants
Cert.of President & CEO Pursuant to Section 302
Cert. of Senior VP & CFO Pursuant to Section 302
Cert.of President & CEO Pursuant to Section 906
Cert.of Senior VP & CFO Pursuant to Section 906


				Year Built		Maximum
				or Last		Drilling
U.S.		Horsepower		Refurbished		Depth (Feet)

Deep drilling:
	Rig No. 15		1,000		1998		15,000
	Rig No. 50		2,000		2001		25,000
	Rig No. 51		2,000		2003		25,000
	Rig No. 53		1,600		1995		20,000
	Rig No. 54		2,000		1996		25,000
	Rig No. 55		2,000		2001		25,000
	Rig No. 56		2,000		1992		25,000
	Rig No. 57		1,500		1997		20,000
	Rig No. 76		3,000		1997		30,000

Intermediate drilling:
	Rig No. 8		1,000		1995		14,000
	Rig No. 17		1,000		1993		13,000
	Rig No. 20		1,000		2001		12,500
	Rig No. 21		1,200		2001		13,000
	Rig No. 23		1,000		1993		11,500

Workover and shallow drilling:
	Rig No. 6 (1)		700		1995		—
	Rig No. 9 (1)		650		1996		—
	Rig No. 12		1,100		1990		14,000
	Rig No. 16		800		1994		8,500
	Rig No. 24		1,000		1992		11,500
	Rig No. 25		1,000		1993		11,500
	Rig No. 26 (1)		650		1996		—



		PART I	PAGE
Item	1.	Business		2
Item	2.	Properties		11
Item	3.	Legal Proceedings		14
Item	4.	Submission of Matters to a Vote of Security Holders		14
Item	4A.	Executive Officers		14
		PART II
Item	5.	Market for Registrant’s Common Stock and Related Stockholder Matters		16
Item	6.	Selected Financial Data		16
Item	7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		18
Item	7A.	Quantitative and Qualitative Disclosures about Market Risk		36
Item	8.	Financial Statements and Supplementary Data		37
Item	9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		81
Item	9A.	Controls and Procedures		81
		PART III
Item	10.	Directors and Executive Officers of the Registrant		82
Item	11.	Executive Compensation		82
Item	12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		82
Item	13.	Certain Relationships and Related Transactions		82
Item	14.	Principal Accounting Fees and Services		82
		PART IV
Item	15.	Exhibits, Financial Statement Schedule and Reports on Form 8-K		83
		Signatures		86


		Drilling Depth Rating in Feet

		10,000		10,000		Over
Region		or Less		to 25,000		25,000		Total

Asia Pacific			1		11		—		12
CIS (1)			—		5		3		8
Africa			1		1		—		2

	Total		2		17		3		22


		Year Ended December 31,

Transition Zone Rig Data		2003			2002

U.S. barge deep drilling:
	Rigs available for service (1)		9.0			9.0
	Utilization rate of rigs available for service (2)		78	%		78	%

U.S. barge intermediate drilling:
	Rigs available for service (1)		5.0			5.0
	Utilization rate of rigs available for service (2)		30	%		38	%

U.S. barge workover and shallow drilling:
	Rigs available for service (1)		7.8			8.0
	Utilization rate of rigs available for service (2)		31	%		32	%

International barge drilling:
	Rigs available for service (1)		5.0			5.0
	Utilization rate of rigs available for service (2)		76	%		85	%

International Land Rig Data

	Rigs available for service (1):		23.8			24.0
	Utilization rate of rigs available for service (2):		41	%		55	%


(1)		During the first quarter of 2003, the Company determined that pursuant to the provisions of EITF No. 01-14, “Income Statement Characterization of Reimbursements Received for Out-of-Pocket Expenses Incurred,” amounts received as reimbursements should have been reported as revenues, with the corresponding amounts reported as operating expenses. In prior years, the Company netted the reimbursement with the cost in the statement of operations. Accordingly, the Company has revised its previously issued statement of operations to reflect this new presentation. The effect of making this change was an increase in both total drilling and rental revenues and total drilling and rental operating expenses for continuing operations of $32.6 million, $37.6 million, $20.8 million and $8.1 million for the years ended December 31, 2002, 2001, 2000 and 1999, respectively, and $4.9 million, $7.1 million, $9.7 million and $10.4 million for discontinued operations for the years ended December 31, 2002, 2001, 2000 and 1999, respectively. This revision has no effect on total operating income, net income, cash flows or any balance sheet amount presented.


	U.S. Jackup			Latin
	and Platform			America
	Drilling			Drilling
	(Dollars in Thousands)
Year Ended December 31, 2003

Discontinued operations operating income (loss)	$	(3,497	)	$	93
Depreciation and amortization		9,817			4,789

Drilling gross margin	$	6,320		$	4,882

Year Ended December 31, 2002

Discontinued operations operating income (loss)	$	(19,336	)	$	666
Depreciation and amortization		21,135			9,414

Drilling gross margin	$	1,799		$	10,080


	U.S. Drilling		International Drilling		Rental Tools

Year Ended December 31, 2002	(Dollars in Thousands)

Drilling and rental operating income	$	6,296	$	38,529	$	13,018
Depreciation and amortization		19,559		35,713		12,682

Drilling and rental gross margin	$	25,855	$	74,242	$	25,700

Year Ended December 31, 2001

Drilling and rental operating income	$	24,972	$	34,809	$	29,943
Depreciation and amortization		25,681		29,527		12,681

Drilling and rental gross margin	$	50,653	$	64,336	$	42,624

(1)		Long-term debt includes the principal and interest cash obligations of the 9.625% Senior Notes, the 10.125% Senior Notes, the 5.5% Convertible Subordinated Notes and the secured 10.1278% promissory note. The unamortized premiums of $0.8 million at December 31, 2003 related to the 10.125% Senior Notes are not included in the contractual cash obligations schedule.

(2)		Operating leases consist of lease agreements in excess of one year for office space, equipment, vehicles and personal property.

(3)		We have a $50.0 million revolving credit facility with an available borrowing base of $44.7 million. As of December 31, 2003, none has been drawn down, but $10.6 million of availability has been used to support letters of credit that have been issued. The revolving credit facility expires on October 10, 2006.


Note 9 -	Reconciliation of Income and Number of Shares Used to Calculate Basic and Diluted Earnings Per Share (EPS)

(1)		U.S. drilling segment includes $7.3 million in revenues from ChevronTexaco Corporation; International drilling segment includes $56.2 million, $53.1 million and $10.3 million in revenues from Royal Dutch Shell, Tengizchevroil and ChevronTexaco Corporation respectively; Rental tools segment includes $7.1 million in revenues from ChevronTexaco Corporation.

(2)		Includes assets related to discontinued operations.

	•		a severance payment equal to two times the sum of the highest salary and bonus over the previous three years, except for Mr. Brassfield, Mr. Gass 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, Mr. Gass 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”).


	2003				2002

Quarter	High		Low		High		Low

First	$	2.56	$	1.91	$	4.82	$	3.10
Second		3.12		1.83		4.74		2.95
Third		3.15		1.65		3.50		1.40
Fourth		2.93		2.22		2.65		1.73


ITEM 9.	*CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE*


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