HORIZON OFFSHORE INC - 10-K Annual Report

Offices Held

Bill J. Lam

President, Chief Executive Officer and Director

David W. Sharp

Executive Vice President and Chief Financial Officer

R. Clay Etheridge

Executive Vice President and Chief Operating Officer

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

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes þ No o

The aggregate market value of the voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold as of the last business day of the registrant’s most recently completed second fiscal quarter (June 28, 2002), was approximately $186 million.

The number of shares of the registrant’s common stock, $1.00 par value per share, outstanding as of March 3, 2003 was 26,397,068.

Portions of the registrant’s definitive Proxy Statement prepared in connection with the registrant’s 2003 annual meeting of stockholders have been incorporated by reference into Part III of this Form 10-K.

We provide marine construction services to the offshore oil and gas industry in the U.S. Gulf of Mexico, Latin America, Southeast Asia and West Africa. Our fleet consists of thirteen vessels, twelve of which are currently operational. Our primary services include:


	•	installing pipelines;

	•	providing pipebury, hook-up and commissioning services;

	•	installing production platforms and other structures;

	•	disassembling and salvaging production platforms and other structures; and

	•	performing pipe spooling services.

We have our principal executive offices at 2500 CityWest Boulevard, Suite 2200, Houston, Texas 77042. Our telephone number is (713) 361-2600. Our Internet address is www.horizonoffshore.com. Copies of the annual, quarterly and current reports we file with the SEC, and any amendments to those reports, are available on our web site free of charge. The information posted on our web site is not incorporated into this Annual Report.

Our operating results are directly tied to industry demand for our services, and, to a lesser degree, seasonal impact. The demand for our services depends on the level of capital expenditures by oil and gas companies for developmental construction. Due to the time required to drill a well and fabricate a production platform, demand for our services usually lags exploratory drilling by nine to eighteen months and sometimes longer.

The marine construction industry in the U.S. Gulf of Mexico historically has been highly seasonal with contracts typically awarded in the spring and early summer and performed before the onset of adverse weather conditions in the winter. The scheduling of much of our work is affected by weather conditions and many projects are performed within a relatively short period of time. We believe that the seasonality of our core operations in the U.S. Gulf of Mexico and Latin America should be offset by our continuing efforts to expand our operations in international areas, such as offshore Southeast Asia and West Africa, where marine construction services historically have been less seasonal. The locations of these regions and the timing of customers’ awards should provide a counter-seasonal balance to our operations in the U.S. Gulf of Mexico. International construction projects also typically have longer lead times with extended job durations of up to one to two years.

We are a leading provider of marine construction services in the U.S. Gulf of Mexico and offshore Mexico. Profit margins in the U.S. Gulf of Mexico have been reduced by continued highly competitive conditions during 2002 due to reductions in capital expenditures by oil and gas companies for developmental construction caused by the general slow down of the U.S. economy, and concerns over U.S. natural gas pricing trends.

During 2002, we laid 278 miles of pipe of various diameters in various depths. We can install and bury pipelines with an outside diameter (including concrete coating) of up to 48 inches. Also in 2002, we performed a total of 70 pipeline construction contracts, and installed or removed 31 offshore platforms. We can install platforms of up to 1,200 tons using our derrick barges.

We completed two projects for Petroleos Mexicanos (Pemex) utilizing the Atlantic Horizon, Lone Star Horizon and Pearl Horizon during 2002. We began another project for Pemex in May 2002 that was completed during the first quarter of 2003. The Brazos Horizon arrived in Nigerian waters in the fourth quarter of 2002, and began work on a major portion of Chevron Nigeria Ltd.’s Escravos Offshore Pipeline and Structural Installation two year program in February 2003. During 2002, we also successfully completed several pipeline and installation projects in Southeast Asia. We completed a subcontract in 2002 for the installation and burial of a 20-inch pipeline for TotalFinaElf in Indonesia utilizing the Sea Horizon for all aspects of the installation. In the domestic sector, we mobilized the Gulf Horizon to begin construction of a pipeline installation and burial project in Long Island Sound, New York in May 2002. We were awarded the contract to install 35 miles of 24-inch diameter pipe to transport natural gas from Northport, Long Island to Hunts Point, New York via the Long Island Sound and East River. Preparations for the project included extensive environmental training of personnel. The Gulf Horizon was upgraded for inclement weather conditions and for the addition of automatic welding equipment. This pipeline installation also included the design, fabrication and use of a 110-ton plow to bury the 24-inch pipeline below the seabed and riverbed. Construction activities commenced in November 2002, and we expect to substantially complete the project during the second quarter of 2003.

We completed the construction of a spooling facility at our marine base in Port Arthur, Texas in the first quarter of 2002. We successfully completed two spooling projects and commenced a third spool job in December 2002 that was successfully completed in the first quarter of 2003.

Our fleet of seven pipelay and pipebury vessels install and bury pipelines of various diameters. Our pipelay vessels employ conventional S-lay technology which is appropriate for operating on the U.S. continental shelf and the international areas where we currently operate. Conventional pipeline installation involves the sequential assembly of pieces of pipe through an assembly line of welding stations that run the length of the pipelay vessel. Welds are then inspected and coated on the deck of the pipelay barge. The pipe is then supported off the stern and into the water via a ramp that is referred to as a “pontoon” or “stinger.” The ramp supports the pipe to some distance under the water and prevents over-stressing as it curves into a horizontal position toward the sea floor. The barge is then moved forward by its anchor winches and the pipeline is laid on the sea floor. The suspended pipe forms an elongated “S” shape as it undergoes a second bend above the contact point. During the pipelay process, divers regularly inspect the pipeline to ensure that the ramp is providing proper support and that the pipeline is settling correctly.

Pipelines installed on the U.S. continental shelf or located in water depths of 200 feet or less are required by the regulations of the United States Department of Interior’s Minerals Management Service to be buried at least three feet below the sea floor. Jet sleds towed behind pipelay/pipebury barges are used to bury pipelines on smaller pipe installation projects. Towed jet sleds are less likely to damage the pipeline being laid or any existing pipelines that the pipeline may cross. Towed jet sleds use a high-pressure stream of air and water which is pumped from the barge to create a trench into which the pipe settles. For larger pipe burying projects, or where deeper trenching is required, we use the Canyon Horizon, our dedicated bury barge. It is one of only two dedicated pipebury barges operating in the U.S. Gulf of Mexico and can bury pipelines more efficiently and to greater depths than any other vessel in the Gulf. We match our burying approach to the requirements of each specific contract by using the Canyon Horizon for larger projects and our towed jet sleds behind pipelay barges for smaller projects. We also use the Pecos Horizon for larger pipebury projects.

Our fleet also includes the Pearl Horizon, a multi-purpose vessel. This vessel performs diving support services such as connecting pipelines to platforms and other pipelines (tie-ins) and filling pipelines with water under pressure to test the integrity of the system. The Pearl Horizon’s capabilities have also been expanded to permit it to tow other vessels. Our dynamically positioned diving support vessel, the Stephaniturm, was under charter in the North Sea throughout 2002. The Stephaniturm is currently undergoing scheduled maintenance and is available for charter hire.

We install and remove or salvage offshore fixed platforms. We have substantially expanded our operating capabilities in this market area in the last three years. We have three derrick barges equipped with cranes designed to lift and place platforms, structures or equipment into position for installation. In addition, they are

used to disassemble and remove platforms and prepare them for salvage or refurbishment. We acquired and upgraded a derrick barge, the Pacific Horizon, with a lift capacity of 1000 tons to complement the Atlantic Horizon that has a 550 ton lift capacity. The Sea Horizon is also utilized to install and remove offshore fixed platforms and its lift capacity was recently upgraded from 800 tons to 1200 tons. The Sea Horizon is 360 feet long and 100 feet wide and has both pipelay and derrick capabilities. It was deployed early in 2002 and has successfully completed several projects in Southeast Asia.

Our alliance with Cal Dive International, Inc. (Cal Dive) in the U.S. Gulf of Mexico includes surface diving, which is done to inspect the pipeline as it is being laid, monitor the pipebury activities, connect pipelines to production platforms and assist derrick barges in the installation and removal of structures. We believe that having Cal Dive perform our surface diving allows us to concentrate on our core activities and improve efficiencies.

Our customers award contracts by means of a highly competitive bidding process. In preparing a bid, we must consider a variety of factors, including estimated time necessary to complete the project, the recovery equipment and the location and duration of current and future projects. We have placed a strong emphasis on attempting to sequentially structure scheduled work in adjacent areas. Sequential scheduling reduces mobilization and demobilization time and costs associated with each project and increases profitability. We employ core groups of experienced offshore personnel that work together on particular types of projects to increase our bidding accuracy. We often obtain the services of workers outside our core employee groups by subcontracting with other parties. Our management examines the results of each bid submitted, reevaluates bids, and implements a system of controls to maintain and improve the accuracy of the bidding process. The accuracy of the various estimates in preparing a bid is critical to our profitability.

Our contracts are typically of short duration in the U.S. Gulf of Mexico, being completed in periods as short as several days to periods of up to several months for projects involving our larger pipelay vessels. International construction projects, such as our projects offshore Mexico with Pemex, have longer lead times and extended job duration. We perform most of our projects on a fixed-price or “lump sum” basis, although a few projects are performed on a cost-plus basis. Under a fixed-price contract, the price stated in the contract is subject to adjustment only for change orders placed by the customer. As a result, we are responsible for all cost overruns. Furthermore, our profitability under a fixed-price contract is reduced when the contract takes longer to complete than estimated. Similarly, our profitability will be increased if we can perform the contract ahead of schedule. Under cost-plus arrangements, we receive a specified fee in excess of direct labor and material cost and are protected against cost overruns, but do not benefit directly from improved performance.

We own all of our marine vessels and have placed mortgages on them to collateralize our debt. See Note 5 of our notes to our consolidated financial statements and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.” Under governmental regulations and our insurance policies, we are required to maintain the vessels in accordance with standards of seaworthiness, safety and health prescribed by governmental regulations and applicable vessel classification societies. We believe we are in compliance with all governmental regulations and insurance policies regarding the operation and maintenance of our vessels.

In the normal course of our operations, we also lease or charter other vessels, such as diving support vessels, tugboats, cargo barges, utility boats and support vessels.

On September 20, 2002, the pipelay barge, Lone Star Horizon, sustained electrical damage due to a fire while at anchor off Ciudad Del Carmen, Mexico. Repairs to the Lone Star Horizon were completed during the fourth quarter of 2002 at a cost of $5.0 million. We maintain hull and machinery insurance to cover physical damage to our vessels. This insurance coverage provides for both a $0.5 million occurrence deductible and a $1.5 million annual aggregate deductible. During 2002, we recorded this $2.0 million loss as other expense, and we believe the insurance will cover the cost to repair the damage. As of December 31, 2002, we included the $3.0 million insurance claim in current assets. We collected an initial reimbursement of $1.2 million in February 2003.

In March 2001, we formed a joint venture, 50% owned by us, with Cal Dive to perform small diameter, deepwater reel pipelaying projects in the U.S. Gulf of Mexico with the Intrepid, a vessel owned by Cal Dive. Operations of the joint venture would be jointly managed and staffed. If both Cal Dive and Horizon decide to commence joint venture operations, we would be required to contribute approximately $8 million for the design, construction and installation of reel pipelaying equipment on the Intrepid that was completed in 2002. Based on current market conditions, we do not know when, or if, the joint venture will become operational.

We are concerned with the safety and health of our employees and maintain a stringent safety assurance program to reduce the possibility of costly accidents. Our health, safety and environmental department establishes guidelines to ensure compliance with all applicable state, federal and foreign safety regulations. We also provide training and safety education through new employee orientations, which include first aid and CPR training. In addition, prospective and current employees must submit to alcohol and drug testing. After each accident or other health or safety occurrence, we promptly collect data concerning the incident, perform further investigations, and evaluate our safety procedures to help prevent similar incidents.

In the third quarter of 2002, our health, safety and environmental management system received OHSAS-18001 certification from the Norwegian classification society Det Norske Veritas (DNV). This internationally recognized certification is applicable to our health, safety and environmental management system for our worldwide operations. Additionally, we were awarded ISO 9001:2000 accreditation by DNV for our Houston-based international operational support activities and marine operations in Southeast Asia. ISO 9001:2000 is an internationally recognized accreditation for demonstrating that a company’s Quality Management System has the ability to consistently provide products and services meeting customer and applicable regulatory requirements, and with the additional goal of enhancing customer satisfaction. We believe that our safety program and commitment to quality are vital to attracting and retaining customers and employees, and controlling costs.

We have domestic and international operations in one industry, the marine construction service industry to offshore oil and gas companies. Our customers in the U.S. have primarily been the oil and gas companies operating on the U.S. outer continental shelf. In 2002, we provided offshore marine construction services to approximately 41 customers. Our single largest customer during the last three years was Pemex. We completed one major project for a subsidiary of Pemex in 2001 and completed two major projects for Pemex in 2002, and we completed another project during the first quarter of 2003. Pemex accounted for 30.6% of our revenues for the year 2002, compared to 52.2% of revenues for 2001 and 36.1% of revenues for 2000. In addition, Iroquois Gas Transmission System LP accounted for 19.7% of consolidated revenues for the year 2002. There were no other customers accounting for more than 10% of consolidated revenues for 2002, 2001 or 2000.

Cumulative revenues recognized from 2000 through 2002 on all Pemex projects in Mexico total $286.8 million, including $57.0 million of claims made under three Pemex contracts for extra work related to interferences, interruptions and other delays. Of the $57.0 million of claims, $54.2 million relates to our second major project for Pemex, which was completed during the fourth quarter of 2002. The remaining $2.8 million of claims relates to two more recent projects for Pemex. Unapproved claims related to the Pemex projects developed primarily from client delays and changes in the initial scope of work.

The level of construction services required by a customer depends on the size of its capital expenditure budget for construction for the year and our ability to bid for and be awarded its projects. Consequently, customers that account for a significant portion of contract revenues in one year may represent an immaterial portion of contract revenues in subsequent years. Most of our U.S. contracts are typically of short duration, being completed in periods as short as several days to periods of up to several months. Many of our international construction projects have longer lead times and extended job durations.

As of December 31, 2002, our backlog supported by written agreements totaled approximately $123.6 million, compared to our backlog at December 31, 2001 of approximately $63.0 million. Our backlog has typically been lower in the first and fourth quarters of the year due to the seasonality and weather conditions in the U.S. Gulf of Mexico during the winter months. As we increase the scope of our international operations, where projects tend to have longer lead times and result in earlier awards, our backlog may increase. We do not consider backlog amounts to be a reliable indicator of annual revenues.

The marine construction industry in the U.S. Gulf of Mexico historically has been highly seasonal with contracts being awarded in the spring and early summer and performed before the onset of adverse weather conditions in the winter. The scheduling of much of our work is affected by weather conditions and other factors, and many projects are performed within a relatively short period of time. We have attempted to offset the seasonality of our core operations in the U.S. Gulf of Mexico and Latin America by expanding our operations to international areas, such as offshore Southeast Asia and West Africa, where marine construction services historically have been less seasonal. We believe the locations of these regions and the timing of customers’ awards provide a counter-seasonal balance to our domestic operations, which we believe offset adverse weather conditions in the U.S. Gulf of Mexico in the first and fourth quarters.

The level and volatility of oil and gas prices have a strong effect on exploration and production activities offshore which ultimately affect the demand for our services. Capital expenditures of oil and gas companies are influenced by:


	•	the price of oil and gas and industry perception of future prices;

	•	the ability of the oil and gas industry to access capital;

	•	the cost of exploring for, producing and developing oil and gas reserves;

	•	sale and expiration dates of offshore leases in the United States and abroad;

	•	discovery rates of new oil and gas reserves in offshore areas; and

	•	local and international political and economic conditions.

Our operations are subject to the inherent risks of offshore marine activity, including accidents resulting in the loss of life or property, environmental mishaps, mechanical failures and collisions. We insure against these risks at levels we believe are consistent with industry standards. Our insurance premiums required to cover these risks significantly increased during 2001 and 2002 due to losses in the insurance industry. In addition, the terrorist attacks that took place on September 11, 2001 further contributed to losses in the insurance industry and may impact our ability to renew our existing coverage in the future.

We believe that our insurance is adequate to cover the cost of replacing any of our vessels that are lost and most other offshore risks. However, certain risks are either not insurable or insurance is available only at rates that are not economical. We cannot assure that any such insurance will be sufficient or effective under all circumstances or against all hazards to which we may be subject.

The marine construction industry is highly competitive. Competition is influenced by such factors as price, availability and capability of equipment and personnel, and reputation and experience of management. Contracts for work in the U.S. Gulf of Mexico are typically awarded on a competitive bid basis one to three months prior to commencement of operations. Customers usually request bids from companies they believe are technically qualified to perform the project. Our marketing staff contacts offshore operators known to have projects scheduled to ensure an opportunity to bid for these projects. Although we believe customers consider, among other things, the availability and technical capabilities of equipment and personnel, the condition of equipment and the efficiency and safety record of the contractor, price is the primary factor in determining which qualified contractor is awarded the contract. Because of the lower degree of complexity and capital costs involved in shallow water marine construction activities, there are a number of companies with one or more pipelay barges capable of installing pipelines in shallow water. We currently compete in the Gulf in water depths of 200 feet or less primarily with Global Industries, Ltd., Torch Offshore, Inc. and a few other smaller contractors. In projects in water depths of 200 feet or more or where a higher degree of complexity is involved, competition generally is limited to Global Industries and from time to time other international companies that

may have vessels operating in the U.S. Gulf of Mexico. We compete primarily with Global Industries and Offshore Specialty Fabricators, Inc. for the installation and removal of production platforms. We believe that our reputation, experienced management and competitive pricing are key advantages.

Internationally, the marine construction industry is dominated by a small number of major international construction companies and government owned or controlled companies that operate in specific areas or on a joint venture basis with one or more of the major international construction companies.

Many aspects of the offshore marine construction industry are subject to extensive governmental regulation. Our United States operations are subject to the jurisdiction of the United States Coast Guard, the National Transportation Safety Board and the Customs Service, as well as private industry organizations such as the American Bureau of Shipping. The Coast Guard and the National Transportation Safety Board set safety standards and are authorized to investigate vessel accidents and recommend improved safety standards, and the Customs Service is authorized to inspect vessels at will.

We are required by various governmental and quasi-governmental agencies to obtain permits, licenses and certificates in connection with our operations. We believe that we have obtained or will be able to obtain, when required, all permits, licenses and certificates necessary to conduct our business.

In addition, we depend on the demand for our services from the oil and gas industry and, therefore, our business is affected by laws and regulations, as well as changing taxes and policies relating to the oil and gas industry. In particular, the exploration and development of oil and gas properties located on the continental shelf of the United States is regulated primarily by the Minerals Management Service. The Minerals Management Service must approve and grant permits in connection with drilling and development plans submitted by oil and gas companies. Delays in the approval of plans and issuance of permits by the Minerals Management Service because of staffing, economic, environmental or other reasons could adversely affect our operations by limiting demand for services.

Certain of our employees are covered by provisions of the Jones Act, the Death on the High Seas Act and general maritime law. These laws make liability limits under state workers’ compensation laws inapplicable and permit these employees to bring suit for job related injuries with generally no limits on our potential liability.

Our operations are affected by numerous federal, state and local laws and regulations relating to protection of the environment, including the Outer Continental Shelf Lands Act, the Federal Water Pollution Control Act of 1972 and the Oil Pollution Act of 1990. The technical requirements of these laws and regulations are becoming increasingly complex and stringent, and compliance is becoming increasingly difficult and expensive. Certain environmental laws provide for “strict liability” for remediation of spills and releases of hazardous substances and some provide liability for damages to natural resources or threats to public health and safety. Sanctions for noncompliance may include revocation of permits, corrective action orders, administrative or civil penalties, and criminal prosecution. It is possible that changes in the environmental laws and enforcement policies, or claims for damages to persons, property, natural resources or the environment could result in substantial costs and liabilities. Our insurance policies provide liability coverage for sudden and accidental occurrences of pollution and/or clean-up and containment of the foregoing in amounts that we believe are comparable to policy limits carried by others in the offshore construction industry.

As of January 31, 2003, we had approximately 717 employees, including 501 operating personnel and 216 corporate, administrative and management personnel. We are employing approximately 32 union laborers for our project in Long Island Sound, New York, pursuant to a project specific labor agreement. Our remaining

Our ability to expand operations and meet any increased demand for our services depends on our ability to increase our workforce. A significant increase in the wages paid by competing employers could result in a reduction in the skilled labor force, and/or increases in the wage rates paid. If either of these circumstances takes place to the extent that such wage increases could not be passed on to our customers, our growth and profitability could be impaired.

Our corporate headquarters is located in Houston, Texas, in approximately 94,000 square feet of leased space under leases expiring from 2006 to 2008. In addition, we lease approximately 37,000 square feet of office space in various international locations under leases expiring from 2003 to 2006.

We own and operate a marine support base and storage facility (for marine structures that may be salvaged by our marine fleet) from approximately 23 acres with approximately 6,000 feet of waterfront on a peninsula in Sabine Lake near Port Arthur, Texas with direct access to the Gulf. The facility has more than 3,000 feet of deepwater access for docking barges and vessels. We also own and operate a marine support and spool base located on 26 acres of waterfront property in Sabine, Texas. This marine base includes 1,700 feet of bulkhead, 59,000 square feet of office and warehouse space, and two heliports. We also lease approximately 19,000 square feet of land in Morgan City, Louisiana for inventory storage on a month-to-month basis.

Certain statements made in this Annual Report that are not historical facts are intended to be “forward-looking statements.” Such forward-looking statements may include statements that relate to:


	•	our business plans or strategies, and projected or anticipated benefits or other consequences of such plans or strategies;

	•	our objectives;

	•	projected or anticipated benefits from future or past acquisitions; and

	•	projections involving anticipated capital expenditures or revenues, earnings or other aspects of capital projects or operating results.

Also, you can generally identify forward-looking statements by such terminology as “may,” “will,” “expect,” “believe,” “anticipate,” “project,” “estimate” or similar expressions. We caution you that such statements are only predictions and not guarantees of future performance or events. In evaluating these statements, you should consider various risk factors, including but not limited to the risks listed below. These risk factors may affect the accuracy of the forward-looking statements and the projections on which the statements are based.

All phases of our operations are subject to a number of uncertainties, risks and other influences, many of which are beyond our control. Any one of such influences, or a combination, could materially affect the results of our operations and the accuracy of forward-looking statements made by us. Some important factors that could cause actual results to differ materially from the anticipated results or other expectations expressed in our forward-looking statements include the following:


	•	Pemex’s approval of claims and the outcome of these claims, and our ability to manage our liquidity needs pending the timing of collection of our receivables and claims from Pemex;

	•	industry volatility, including the level of capital expenditures by oil and gas companies due to fluctuations in the price and perceptions of the future price of oil and gas;

	•	risks of growth strategy, including the risks of rapid growth;


	•	operating hazards, including the unpredictable effect of natural occurrences on operations and the significant possibility of accidents resulting in personal injury and property damage;

	•	the highly competitive nature of the marine construction business;

	•	dependence on the continued strong working relationships with significant customers operating in the U.S. Gulf of Mexico;

	•	seasonality of the offshore construction industry in the U.S. Gulf of Mexico;

	•	ability to realize carrying values of salvaged structures;

	•	the need for additional financing;

	•	contract bidding risks;

	•	percentage-of-completion accounting;

	•	successful negotiation and collection of contract claims;

	•	continued active participation of our executive officers and key operating personnel;

	•	the effect on our performance of regulatory programs and environmental matters;

	•	risks involved in the expansion of our operations into international offshore oil and gas producing areas;

	•	risks involved in joint venture operations, including difficulty in resolving disputes with present partners or reaching agreements with future partners; and

	•	a terrorist attack and a prolonged war with Iraq.

Many of these factors are beyond our ability to control or predict. We caution investors not to place undue reliance on forward-looking statements. We disclaim any intent or obligation to update the forward-looking statements contained in this report, whether as a result of receiving new information, the occurrence of future events or otherwise.

Our receivables from Pemex continue to impact our liquidity and operating cash flows. As of December 31, 2002, we have recognized contract receivables of $14.2 million and costs in excess of billings of $62.7 million from Pemex totaling $76.9 million. The significant delays between the completion of the work and when it is billed and collected are caused by Pemex’s rigid requirements on the submission, review and approval of invoices and documentation prior to their payment of contract claims and change orders. As of December 31, 2002, there were $57.0 million of claims, which we have recognized as revenue, made under three Pemex contracts for extra work related to interferences, interruptions and other delays, with the majority of this amount related to our second major contract that was completed in the fourth quarter of 2002.

During November 2002, we engaged a consulting firm in Mexico to assist us in the administration of the claims to be made against Pemex. After considering the time necessary for the consultants to comply with Pemex’s requirements and communication with new Pemex management, we believe that it will take longer to process and collect these claims than previously expected. We now expect to formally submit these claims in accordance with Pemex’s requirements through the second quarter of 2003, with collections expected by the end of the third quarter of 2003. The unapproved claims we have included as revenue through December 31, 2002 are expected to be substantially less than the actual claims to be presented to Pemex, and we believe we will collect more than the claim amounts recorded. However, there is a risk that the unapproved claims we have recognized as revenue may not be collected in full. Should these unapproved claims become uncollectible based upon subsequent events, we will recognize a loss in our financial statements at that time. There may be factors other than the submission, review and approval of our claims which are outside our control that may

impact the ultimate collectibility of these amounts. We have considered factors including changes that have occurred related to Pemex employees involved in the project, the operating structure of Pemex, and the political and economic conditions in Mexico in assessing the collectibility of these amounts.

Our ability to service our existing debt, provide working capital and fund our capital expenditure requirements will be affected by our ability to collect our Pemex receivables and claims. We believe that our cash on hand, together with cash provided by operations and available borrowings under our revolving credit facilities, will be sufficient to fund our debt service requirements, working capital and capital expenditures for at least the next year barring any unforeseen circumstances. If current activity levels continue in the U.S. Gulf of Mexico or if we are unsuccessful in collecting our Pemex receivables and claims as expected, it would require us to depend more heavily on our existing revolving credit facilities and possibly refinance some or all of our indebtedness in order to increase our total borrowing capability if we cannot obtain additional financing from our existing lenders. We cannot assure you that we will be able to refinance any of our indebtedness, including our existing revolving credit facilities, on commercially reasonable terms or at all.

The demand for our services depends on the level of capital expenditures by oil and gas companies for developmental construction. As a result, the cyclical nature of the oil and gas industry has a significant effect on our revenues and profitability. Historically, prices of oil and gas, as well as the level of exploration and developmental activity, have fluctuated substantially. Any significant decline in the worldwide demand for oil and gas, or prolonged low oil or gas prices in the future, will likely depress development activity. We are unable to predict future oil and gas prices or the level of oil and gas industry activity. A prolonged low level of activity in offshore drilling and exploration will adversely affect our revenues and profitability.

We have undergone rapid growth both internally and through acquisitions of additional barges and vessels. Future acquisitions of other complementary businesses and marine equipment are key elements of our growth strategy. If we are unable to purchase additional equipment or other vessels on favorable financial or other terms or to manage acquired businesses or vessels, this could adversely affect our revenues and profitability. We cannot assure that we will be able to identify or acquire equipment or businesses. In addition, any such future acquisitions may involve potential delays and increased costs. If we acquire new vessels, we may need to upgrade or refurbish the vessels. If we experience delays or cost increases in upgrading or refurbishing the vessels, our operating results will be negatively affected.

Offshore construction involves a high degree of operational risk. Risks of vessels capsizing, sinking, grounding, colliding and sustaining damage from severe weather conditions are inherent in offshore operations. These hazards may cause significant personal injury or property damage, environmental damage, and suspension of operations. In addition, we may be named as a defendant in lawsuits involving potentially large claims as a result of such occurrences. Our insurance premiums required to cover these risks significantly increased during 2001 and 2002 due to losses in the insurance industry. In addition, the terrorist attacks that took place on September 11, 2001 further contributed to losses in the insurance industry and may impact our ability to renew our existing coverage in the future. We maintain what we believe is prudent insurance protection. However, we cannot assure that our insurance will be sufficient or effective under all circumstances. A successful claim for which we are not fully insured may have a material adverse effect on our revenues and profitability.

Our business is highly competitive because construction companies operating offshore compete vigorously for available projects, which are typically awarded on a competitive bid basis. This competitive bid process

Several of our competitors and potential competitors are larger and have greater financial and other resources. Competitors with greater financial resources may be willing to sustain losses on certain projects to prevent further market entry by other competitors. In addition, marine construction vessels have few alternative uses and high maintenance costs, whether they are operating or not. As a result, some companies may bid contracts at rates below our rates. These factors may adversely affect the number of contracts that are awarded to us and the profit margins on those contracts which are awarded to us. Additionally, as a result of the competitive bidding process, our significant customers vary over time.

Historically, the greatest demand for marine construction services in the U.S. Gulf of Mexico has been during the period from May to September. This seasonality of the construction industry in the U.S. Gulf of Mexico is caused both by weather conditions and by the historical timing of capital expenditures by oil and gas companies which accompanies this. As a result, revenues are typically higher in the summer months and lower in the winter months. Although we are in the process of offsetting U.S. Gulf of Mexico seasonality by pursuing business opportunities in international areas, we cannot assure that such expansion will offset the seasonality of our operations in the U.S. Gulf of Mexico.

Our acquisition strategy may require significant amounts of additional capital. We may have to issue additional equity securities or incur additional debt in connection with such acquisitions.

Substantially all of our projects are performed on a fixed-price basis. Changes in offshore job conditions and variations in labor and equipment productivity may affect the revenue and costs on a contract. These variations may affect our gross profits. In addition, typically during the summer construction season, and occasionally during the winter season, we bear the risk of delays caused by adverse weather conditions.

Since our contract revenues are recognized on a percentage-of-completion basis, we periodically review contract revenue and cost estimates as the work progresses. Accordingly, adjustments are reflected in income in the period when such revisions are determined. These adjustments could result in a reduction of previously reported profits, which may be significant.

Our success depends on, among other things, the continued active participation of our executive officers and certain of our other key operating personnel. Our officers and personnel have extensive experience in the marine construction industry, both domestic and international. The loss of the services of any one of these persons could adversely impact our ability to implement our expansion strategy.

Our operations are subject to various governmental regulations, violations of which may result in civil and criminal penalties, injunctions, and cease and desist orders. In addition, some environmental statutes may impose liability without regard to negligence or fault. Although our cost of compliance with such laws has to date been immaterial, such laws are changed frequently. Accordingly, it is impossible to predict the cost or impact of such laws on our future operations.

We depend on demand for our services from the oil and gas industry, and this demand may be affected by changing tax laws and oil and gas regulations. As a result, the adoption of laws which curtail oil and gas

A key element of our expansion strategy has been to expand our operations into selected international oil and gas producing areas, which we will continue to do. These international operations are subject to a number of risks inherent in any business operating in foreign countries including, but not limited to:


	•	political, social, and economic instability;

	•	potential seizure or nationalization of assets;

	•	increased operating costs;

	•	modification or renegotiating of contracts;

	•	import-export quotas; and

	•	other forms of government regulation which are beyond our control.

Our international operations have not yet been affected materially by such conditions or events, but if our international operations expand, the exposure to these risks will increase. As a result, we could, at any one time, have a significant amount of our revenues generated by operating activity in a particular country. Therefore, our results of operations could be susceptible to adverse events beyond our control that could occur in the particular country in which we are conducting such operations.

Additionally, our competitiveness in international areas may be adversely affected by regulations, including but not limited to regulations requiring:


	•	the awarding of contracts to local contractors;

	•	the employment of local citizens; and

	•	the establishment of foreign subsidiaries with significant ownership positions reserved by the foreign government for local citizens.

We anticipate entering into joint ventures with entities as we expand into other international areas. We cannot assure that we will undertake such joint ventures or, if undertaken, that such joint ventures will be successful.

The terrorist attacks that took place on September 11, 2001 in the U.S. were unprecedented events that have created many economic and political uncertainties, and highlight the impact that future similar terrorist attacks could have on broader economic and political factors that indirectly affect our business and demand for marine construction services. The potential for future terrorist attacks, the national and international response to terrorist attacks, including a prolonged war with Iraq, and other acts of war or hostility have created many economic and political uncertainties, which could adversely affect our business for the short or long-term in ways that cannot presently be predicted.

We are involved in various routine legal proceedings primarily involving claims for personal injury under the Jones Act and general maritime laws which we believe are incidental to the conduct of our business. We believe that none of these proceedings, if adversely determined, would have a material adverse effect on our business or financial condition.

Listed below are the names, ages and offices held by our executive officers as of March 1, 2003.

Our executive officers are appointed by our board of directors, subject to their rights under employment agreements.

Bill J. Lam is our President, Chief Executive Officer and a Director. Mr. Lam has served as our President and Chief Executive Officer since December 1997. From July 1997 to November 1997, Mr. Lam was our Vice President — Operations. Prior to being employed by us, Mr. Lam held various supervisory positions for the following providers of marine construction services to the offshore oil and gas industry: Lowe Offshore, Inc. (from January 1997 to July 1997), J. Ray McDermott, S.A. (from January 1995 to January 1997), and OPI International, Inc. (from August 1990 to January 1995).

David W. Sharp is an Executive Vice President and our Chief Financial Officer. Mr. Sharp has served as our Executive Vice President and Chief Financial Officer since December 1997. From October 1996 to November 1997, Mr. Sharp was Vice President — Finance. He held various positions from January 1995 to October 1996 with McDermott, including world-wide project leader for the implementation of accounting and financial systems. He was controller-Atlantic Division and Director of Management Information of OPI International from November 1990 to January 1995.

R. Clay Etheridge is an Executive Vice President and our Chief Operating Officer. Mr. Etheridge has served as our Executive Vice President and Chief Operating Officer since September 1999. Prior to joining us, Mr. Etheridge served as Vice President of International Operations for Global Industries from March 1997 to September 1999. Mr. Etheridge has held executive management positions with McDermott in Southeast Asia, and OPI International, with responsibility for U.S. Gulf of Mexico and West African operations, and served as operations manager for Heerema Marine Contractors.

Our common stock is traded on the NASDAQ National Market under the symbol “HOFF”. At March 3, 2003, we had approximately 30 holders of record of our common stock.

The following table sets forth the high and low closing bid prices per share of our common stock, as reported by the NASDAQ National Market, for the periods indicated.

We intend to retain all of the cash our business generates to fund future growth and meet our working capital requirements. We do not plan to pay cash dividends on our common stock in the foreseeable future. In addition, our debt agreements currently prevent us from paying dividends or making other distributions to our stockholders.

The following table provides information regarding common stock authorized for issuance under our equity compensation plans as of December 31, 2002:


(1)	Our equity compensation program does not include any equity compensation plans (including individual compensation arrangements) under which common stock is authorized for issuance that were adopted without the approval of shareholders.

(2)	Of the shares remaining for issuance under our equity compensation plans, no more than 200,000 shares may be issued as restricted stock or other stock based awards (which awards are valued in whole or in part on the value of the shares of common stock under each plan).

The selected financial data for the five-year period ended December 31, are derived from our audited financial statements. You should read the information below together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and notes thereto included in this Annual Report.

The Consolidated Financial Statements for 1998 through 2001 were audited by Arthur Andersen LLP (Andersen), which has ceased operations. A copy of the auditor’s report previously issued by Andersen on our financial statements as of December 31, 2001 and 2000 and for each of the three years in the period ended December 31, 2001 is included elsewhere in this report. Andersen did not reissue its report.

(1)

Horizon calculates EBITDA (earnings before interest, income taxes, depreciation and amortization) as net income or loss excluding extraordinary loss and cumulative effect of accounting change, income taxes, net interest expense, depreciation and amortization, and non-cash impairment. Earnings includes revenues for services for which non-cash consideration is received (approximately $6.8 million in 2002). EBITDA is a supplemental financial measurement we use to evaluate our business. We believe that EBITDA provides supplemental information about our ability to meet future requirements for debt service, capital expenditures and working capital. It is not intended to depict funds available for reinvestment or other discretionary uses. We believe factors that should be considered by investors in evaluating EBITDA include, but are not limited to, trends in EBITDA as compared to cash flow from operations, debt service requirements and capital expenditures. Our measurement of EBITDA may not be comparable to EBITDA as calculated by other companies. Further, you should not consider EBITDA in isolation as an alternative to, or more meaningful than, net income, cash flow provided by (used in) operations or any other measure of performance determined in accordance with generally accepted accounting principles as an indicator of our profitability or liquidity.

You should read the following discussion and analysis together with our consolidated financial statements and notes thereto included in this Annual Report. The following information contains forward-looking statements, which are subject to risks and uncertainties. Should one or more of these risks or uncertainties materialize, actual results may differ from those expressed or implied by the forward-looking statements. See “Cautionary Statements.”

We provide marine construction services to the offshore oil and gas industry in the U.S. Gulf of Mexico, Latin America, Southeast Asia and West Africa. Our marine fleet consists of thirteen vessels, twelve of which are currently operational.


	•	installing pipelines;

	•	providing pipebury, hook-up and commissioning services;

	•	installing production platforms and other structures;

	•	disassembling and salvaging production platforms and other structures; and

	•	performing pipe spooling services.

The demand for offshore construction services depends largely on the condition of the oil and gas industry and, in particular, the level of capital expenditures by oil and gas companies for developmental construction. These expenditures are influenced by:


	•	the price of oil and gas and industry perception of future prices;

	•	the ability of the oil and gas industry to access capital;

	•	expectations about future demand and prices;

	•	the cost of exploring for, producing and developing oil and gas reserves;

	•	sale and expiration dates of offshore leases in the United States and abroad;

	•	discovery rates of new oil and gas reserves in offshore areas;

	•	local and international political and economic conditions;

	•	governmental regulations; and

	•	the availability and cost of capital.

Historically, oil and gas prices and the level of exploration and development activity have fluctuated substantially, impacting the demand for pipeline and marine construction services. Factors affecting our profitability include competition, equipment and labor productivity, contract estimating, weather conditions and other risks inherent in marine construction. The marine construction industry in the U.S. Gulf of Mexico is highly seasonal as a result of weather conditions with the greatest demand for these services occurring during the second and third calendar quarters of the year.

Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements. The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Management must apply significant judgments in this process. Among the factors, but not fully inclusive of all factors, that may be considered by management in these processes are: the range of accounting policies permitted by accounting principles generally accepted in the United States; management’s understanding of our business; expected rates of business and operational change; sensitivity and volatility associated with the assumptions used in developing estimates; and whether historical trends are expected to be representative of future trends. Among the most subjective judgments employed in the preparation of these financial statements are estimates of expected costs to complete construction projects, the collectibility of contract receivables and claims, the fair value of salvage inventory, the depreciable lives of and future cash flows to be provided by our equipment, the period and extent of maintenance and repairs for drydocking activity and certain judgments regarding the nature of income and expenditures for tax purposes. We review all significant estimates on a recurring basis and record the effect of any necessary adjustments prior to publication of our financial statements. Adjustments made with respect to the use of estimates often relate to

We consider certain accounting policies to be critical policies due to the significant judgments, estimation processes and uncertainties involved for each in the preparation of our consolidated financial statements. We believe the following represent our critical accounting policies.

Contract revenues for construction contracts are recognized on the percentage-of-completion method, measured by the percentage of costs incurred to date to the total estimated costs at completion for each contract. This percentage is applied to the estimated revenue at completion to calculate revenues earned to date. We consider the percentage-of-completion method to be the best available measure of progress on these contracts. Changes in job performance, job conditions and estimated profitability, including those arising from claims and final contract settlements, may result in revisions to estimated costs and revenues and are recognized in the period in which the revisions are determined. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. Revenue also includes amounts earned upon the completion of salvage services. Revenues from salvage projects include non-cash values assigned to structures that are received from time to time as partial consideration.

Costs of contract revenues include all direct material and labor costs and certain indirect costs, such as supplies, tools, repairs and depreciation, which are allocated to contracts based on asset utilization. Selling, general and administrative costs are charged to expense as incurred.

We have significant investments in billed and unbilled receivables as of December 31, 2002. We have historically not experienced any significant losses on receivables, but significant losses could be material to our financial position and results of operations. At December 31, 2002, we had $14.2 million in contract receivables and $62.7 million in costs in excess of billings from Pemex, including $57.0 million in claims related to weather and other delays, totaling $76.9 million. We believe our receivables are realizable; however, any changes will be recognized in the period in which they are determined.

We use the units-of-production method to calculate depreciation on our major barges and vessels to accurately reflect the wear and tear of normal use. The annual depreciation based on utilization of each vessel will not be less than 25% of annual straight-line depreciation, and the cumulative depreciation based on utilization of each vessel will not be less than 50% of cumulative straight-line depreciation. The useful lives of our major barges and vessels range from 15 years to 18 years. Major additions and improvements to barges, boats and related equipment are capitalized and depreciated over the useful life of the vessel. Maintenance and repairs are expensed as incurred. When equipment is sold or otherwise disposed of, the cost of the equipment and accumulated depreciation are removed from the accounts and any gain or loss is reflected in income.

We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such asset may not be recoverable. Based on our analysis of the estimated future cash flows for our long-term assets, we recognized a $9.9 million impairment loss related to the Phoenix Horizon under SFAS No. 144 for the year ended December 31, 2002. Our planned use of the Phoenix Horizon changed during the fourth quarter of 2002 based on capital requirements and the projected utilization of our operating fleet to meet current market demands, which we expect to continue for at least the first half of 2003. During the fourth quarter, management determined not to invest in the improvements required to place the Phoenix Horizon into service due to the availability of other operational assets to address current market demands. No impairments were recognized for the years ended December 31, 2001 and 2000.

Dry-dock costs are direct costs associated with scheduled major maintenance on the marine construction vessels. Costs incurred in connection with dry-dockings are deferred and amortized over the five-year cycle to the next scheduled dry-docking. On June 29, 2001, the American Institute of Certified Public Accountants (AICPA) issued an exposure draft of a proposed Statement of Position (SOP), “Accounting for Certain Costs and Activities Related to Property, Plant, and Equipment.” If adopted, we would be required to expense regulatory maintenance cost on our vessels as incurred. We incurred and capitalized dry-dock costs of $5.8 million in 2002, $7.1 million in 2001 and $2.0 million in 2000. As of December 31, 2002, deferred dry-dock costs totaled $12.9 million. Expensing dry-dock costs would likely result in greater variability of our quarterly earnings as a substantial portion of our dry-dock activities take place during the first and fourth quarters.

Inventory consists of production platforms and other marine structures received from time to time as partial consideration from salvage projects performed in the U.S. Gulf of Mexico. These structures are held for resale. In 2002 and 2001, we sold inventory structures for $0.7 million and $0.9 million with related cost of sales of $0.7 million and $0.6 million, respectively. The inventory is valued at amounts not in excess of the fair value of services provided. Horizon assesses the net realizable value of its inventory items at each balance sheet date. Inventory is classified as long-term due to the uncertain timing of the sale of inventory.

The discussion below describes our results of operations. Our 2002 results reflect the ongoing competitive nature of marine construction services in the U.S. Gulf of Mexico. Our profit margins in the U.S. Gulf of Mexico remained under competitive pressure during 2002 due to reduced industry demand for our services. Our work in international areas continued to grow in 2002 with the expansion of our operations into Southeast Asia and West Africa. We believe these international areas will provide opportunities for improved profit margins compared to current market conditions in the U.S. Gulf of Mexico.

Our profit margins were adversely impacted by weather conditions during the fourth quarter of 2002. We experienced lower margins on vessels operating in the northern U.S. Gulf of Mexico because of downtime due to unusually adverse weather conditions during the fourth quarter of 2002. The inclement winter weather conditions in the Northeastern United States affected our profitability related to the pipeline installation and burial project in Long Island Sound even though that project remains on schedule. We believe our expansion into Southeast Asia and West Africa will provide a counter-seasonal balance to the effect of adverse winter weather conditions in the U.S. Gulf of Mexico and Latin America.

During 2002, we completed two projects for Pemex utilizing the Atlantic Horizon, Lone Star Horizon and Pearl Horizon. We began another project for Pemex in May 2002 which we completed during the first quarter of 2003. Pemex accounted for 30.6% of consolidated revenues for 2002 compared with 52.2% for 2001 and 36.1% for 2000. Our receivables from Pemex continue to impact our liquidity and operating cash flows. As of December 31, 2002, we had $76.9 million of Pemex receivables, consisting of contract receivables of $14.2 million and costs in excess of billings of $62.7 million.

We follow the guidance of AICPA SOP 81-1, “Accounting for Performance of Construction-Type and Certain Production-Type Contracts” relating to use of the percentage-of-completion method, estimating costs and claim recognition for construction contracts. Contract revenue reflects the original contract price adjusted for agreed upon change orders and unapproved claims. We recognize unapproved claims only when the collection is deemed probable and if the amount can be reasonably estimated for purposes of calculating total profit or loss on long-term contracts. We record revenue for claims to the extent of costs incurred and include no profit on claims recorded.

interferences, interruptions and other delays. Of the $57.0 million of claims, $54.2 million relates to our second major project for Pemex, EPC 64, which was completed during the fourth quarter of 2002. The remaining $2.8 million of claims relates to two more recent projects for Pemex. Unapproved claims related to the Pemex projects arise primarily from client delays and changes in the initial scope of work.

A summary of the balance of claims remaining in costs in excess of billings related to the Pemex projects are as follows (in millions):

Subsequent to December 31, 2002, we have collected $8.4 million of contract receivables related to the Pemex projects.

We completed the construction of a spooling facility at our marine base in Port Arthur, Texas in the first quarter of 2002. The facility can be used to provide pipe spooling services to other contractors and to our joint venture with Cal Dive. We successfully completed two spooling projects in 2002 and commenced a third spool job in December 2002 that was successfully completed in the first quarter of 2003. The joint venture, which has not commenced operations, was formed to charter from Cal Dive the Intrepid, a 374-foot dynamically positioned multi-service vessel, with reel pipelaying equipment. Operations of the joint venture would be jointly managed and staffed. If both Cal Dive and Horizon decide to commence joint venture operations, we would be required to contribute approximately $8 million for the design, construction and installation of reel pipelaying equipment on the Intrepid that was completed in 2002. Based on current market conditions, we do not know when, or if, the joint venture will become operational.

The Brazos Horizon arrived in Nigerian waters in October 2002, and began work on a major portion of Chevron Nigeria Ltd.’s Escravos Offshore Pipeline and Structural Installation two year program in February 2003. During 2002, we successfully completed several structural projects in Indonesian waters. We completed

a subcontract in 2002 for the installation and burial of a 20-inch pipeline for TotalFinaElf in Indonesia utilizing the Sea Horizon for all aspects of the installation. We will continue to pursue international construction projects in Mexico, Latin America, Southeast Asia and West Africa.

We mobilized the Gulf Horizon to begin construction of a pipeline installation and burial project in Long Island Sound, New York in May 2002. We were awarded the contract to install 35 miles of 24-inch diameter pipe to transport natural gas from Northport, Long Island to Hunts Point, New York via the Long Island Sound and East River. Preparations for the project included extensive environmental training of personnel. The Gulf Horizon was upgraded for inclement weather conditions and for the addition of automatic welding equipment. This pipeline installation also included the design, fabrication and use of a 110-ton plow to bury the 24-inch pipeline below the seabed and riverbed. Construction activities commenced in November 2002, and we expect to substantially complete the project during the second quarter of 2003.

As of March 7, 2003, our backlog totaled approximately $100.0 million compared to our backlog at December 31, 2002 and 2001 of approximately $123.6 million and $63.0 million, respectively. This change is attributable to work performed during that period.

Contract revenues were $283.4 million for 2002, compared to $272.2 million for 2001. Revenues increased 4.1% compared with last year. Our projects in Mexico contributed approximately $86.7 million in revenues during 2002, compared with $142.2 million during 2001. The decline in revenues from the projects in Mexico was offset by revenues of $55.9 million from the pipeline installation and burial project in Long Island Sound and by revenues from other international projects. Revenues recognized in 2002 and 2001 included $43.4 million and $23.3 million, respectively, from salvage and installation projects in the U.S. Gulf of Mexico. Of the $43.4 million in revenues recognized in 2002, approximately $6.8 million represents values assigned to structures received as partial consideration for salvage projects performed. No significant non-cash consideration was received in 2001.

Gross profit was $30.4 million (10.7% of contract revenues) for 2002 compared with gross profit of $35.0 million (12.9% of contract revenues) for 2001. Excluding the effect of the claims on the Pemex projects for which revenues were recognized to the extent of actual costs incurred, gross profit as a percentage of revenues was 11.3% for 2002 compared with 15.3% for 2001. The decline was due to lower margins bid on jobs as a result of competitive market conditions. In addition, unusually adverse weather conditions during the fourth quarter of 2002, and resulting downtime and revenues recorded for such events, lowered the overall profit margin.

Selling, general and administrative expenses were $21.8 million (7.7% of contract revenues) for 2002, compared with $13.8 million (5.1% of contract revenues) for 2001. The increase was primarily due to our international expansion and costs associated with our Pemex claims.

We recognized a $9.9 million impairment loss related to the Phoenix Horizon under SFAS No. 144 for the year ended December 31, 2002. During the fourth quarter of 2002, we determined that we would not invest in the improvements required to place the barge into service under the current market conditions. The impairment loss was based upon the cost of the Phoenix Horizon in excess of its estimated fair value based upon estimated discounted future cash flows. No impairments were recognized for the year ended December 31, 2001.

Interest expense for 2002 was $4.6 million, net of $1.6 million of capitalized interest. Interest expense for 2001 was $5.4 million, net of $1.3 million of capitalized interest. Total outstanding debt was $98.3 million at December 31, 2002 compared with $119.1 million at December 31, 2001. The decrease in interest expense was due to lower average interest rates, lower average outstanding debt balances as a result of the April 2002 equity offering and an increase in interest capitalization in 2002 related to our increased capital spending.

Interest income includes interest from cash investments for the years ended December 31, 2002 and 2001 of $0.1 million and $0.4 million, respectively. The decrease was primarily due to lower interest rates and lower average cash balances for 2002.

Included in other income (expense) for 2002 is a $2.0 million loss related to a fire on the Lone Star Horizon, $0.8 million of foreign currency loss due to activity denominated in Mexican pesos and a decline of the Mexican peso compared to the U.S. dollar, and approximately $31,000 of miscellaneous expense.

We use the liability method of accounting for income taxes. We recorded a federal income tax benefit of $(3.1) million, at a net effective rate of 35.7% on a pre-tax loss of $(8.6) million for 2002. We recorded a federal income tax provision of $4.8 million, at a net effective rate of 30.0% on a pre-tax income before extraordinary loss of $16.1 million for 2001. The difference from the statutory rate is due to the application of the extraterritorial income exclusion for income earned primarily in Mexico and parts of Southeast Asia. The exclusion allows us to exclude a qualifying portion of income earned outside the United States for tax purposes. The impact of this exclusion on future periods will vary depending upon the amount of qualifying income earned outside the United States and changes in tax rules.

In March of 2001, we recorded an extraordinary loss of $(0.6) million, or $(0.03) per share-diluted, net of taxes of $(0.3) million related to a penalty on the early extinguishment of debt. See Note 2 of our notes to consolidated financial statements. We had no such event in 2002.

Net loss was $(5.5) million, or $(0.22) per share-diluted, for 2002, compared to net income for 2001 of $10.7 million, or $0.46 per share-diluted, which includes the effect of an extraordinary loss of $(0.6) million, or $(0.03) per share-diluted, related to the early extinguishment of debt.

Contract revenues were $272.2 million for 2001 compared with $160.5 million for 2000. Our revenues for 2001 increased 69.6% compared with the same period last year, primarily due to our ongoing projects offshore Mexico. Our two projects in Mexico contributed approximately $142.2 million in revenues during 2001, as

compared to $57.9 million in 2000. Revenues recognized in 2001 and 2000, included $23.3 million and $55.4 million, respectively, from salvage and installation projects in the U.S. Gulf of Mexico. No significant non-cash consideration was received in 2001 and 2000.

Gross profit was $35.0 million (12.9% of contract revenues) for 2001 compared with gross profit of $24.4 million (15.2% of contract revenues) for 2000. Gross profit as a percentage of revenues decreased due to lower margins previously bid on jobs as a result of the competitive market conditions in the U.S. Gulf of Mexico. In addition, weather and other delay related claims on the Pemex projects, for which revenues recognized of $42.8 million in 2001 approximate the actual costs incurred, lowered the overall profit margin.

Selling, general and administrative expenses were $13.8 million (5.1% of contract revenues) for 2001 compared with $9.4 million (5.9% of contract revenues) for 2000. The increase is due to additional expenses associated with our international expansion. The percentage decrease was primarily due to the increase in revenues with a lower corresponding increase in selling, general and administrative expenses in 2001.

Interest expense for 2001 was $5.4 million, net of $1.3 million of capitalized interest. Interest expense for 2000 was $7.7 million, net of $0.3 million of capitalized interest. The decrease in interest expense was due to both lower average interest rates and lower average outstanding balances on our debt.

Interest income includes interest from cash investments for the years ended December 31, 2001 and 2000 of $0.4 million and $0.7 million, respectively. The decrease was primarily due to lower interest rates and lower average cash balances for 2001.

Included in other income (expense) for the year ended December 31, 2001 is $(164,000) of other net expenses associated with foreign currency transaction losses and $(10,000) of net expenses related to our Cal Dive joint venture. We recognized $(39,000) of equity losses related to the DSND joint venture and $29,000 of revenue earned from billings to the DSND joint venture for administrative services in 2001. The DSND joint venture was dissolved in February 2001. Other income (expense) for the year ended December 31, 2000 consisted of equity losses of $(221,000) related to the DSND joint venture, $122,000 of revenue earned from billings to the DSND joint venture for administrative services and $15,000 of miscellaneous income.

We use the liability method of accounting for income taxes. We recorded a federal income tax provision of $4.8 million, at a net effective rate of 30.0% on a pre-tax income of $16.1 million for 2001, excluding $(0.3) million of deferred tax benefit attributable to the extraordinary loss. We recorded a federal income tax provision of $2.9 million, at a net effective rate of 36.8% on a pre-tax income of $7.9 million for 2000, excluding $0.7 million of deferred tax provisions attributable to the accounting change in 2000. The decrease in our effective tax rate is due to the effect of the application of the extraterritorial income exclusion in 2001 for income earned primarily in Mexico from October 1, 2000 to December 31, 2001. The exclusion allows us to exclude a qualifying portion of income earned outside the United States for tax purposes. The impact of this exclusion on future periods will vary depending upon the amount of qualifying income earned outside the United States and changes in tax rules.

Net income was $10.7 million, or $0.46 per share-diluted, for 2001, which includes the effect of an extraordinary loss of $(0.6) million, or $(0.03) per share-diluted, related to the early extinguishment of debt. Net income for 2000 was $6.4 million, or $0.33 per share-diluted, which includes the effect of a cumulative adjustment of $1.4 million, or $0.07 per share, related to a change in accounting principle.

In April 2002, we sold 3,000,000 shares of common stock in a public offering. We received $30.8 million after deducting the underwriting discount and expenses. We used $20.0 million to reduce indebtedness under our revolving credit facilities and the remainder was used for general corporate purposes.

Our primary liquidity needs are to provide working capital to support our projects and other operations and to fund acquisitions and improvements to the fleet necessary to expand operations. We had $30.4 million of working capital at December 31, 2002, compared to $78.1 million of working capital at December 31, 2001. The decrease in working capital was attributable to an increase in accounts payable and the use of funds for capital expenditures and to reduce of our long-term debt.

Our receivables from Pemex continue to impact our liquidity and operating cash flows. As of December 31, 2002, we had contract receivables of $14.2 million and costs in excess of billings of $62.7 million from Pemex totaling $76.9 million. The significant delays between the completion of the work and when it is billed and collected are caused by Pemex’s rigid requirements on the submission, review and approval of invoices and documentation prior to their payment of contract claims and change orders. As of December 31, 2002, there were $57.0 million of claims made under three Pemex contracts for extra work related to interferences, interruptions and other delays.

Of the $57.0 million of claims, $54.2 million of claims relate to our most significant contract with Pemex, the EPC 64 contract in the Cantarell field. Pemex extended the EPC 64 contract, which had an original value of $41.0 million, in scope to $194.4 million of total revenue recognized. This extension substantially increased the period of our operations in the Cantarell field, and as a result, this project was subject to greater interruptions due to weather conditions and standby time as other contractors completed their work. The claims on the EPC 64 contract could not be submitted in accordance with Pemex requirements until all work was completed in the fourth quarter of 2002.

Cash provided by operations was $47.5 million for 2002 compared to $44.0 million of cash used in operations for 2001. During 2002, costs in excess of billings decreased $17.9 million compared to an increase of $78.8 million in 2001 that related principally to contracts with Pemex. The decrease in 2002 was based upon billing and subsequent collection of accounts receivable related to Pemex, the project in Long Island Sound and the Amistad Development project in Golfo de Guayaquil, Ecuador. Additionally, cash flows from operating activities included increases in accounts payable and accrued liabilities of approximately $26.3 million in 2002 and $38.5 million in 2001 related to extensions in the timing of payments by us.

At December 31, 2002, we had approximately $98.3 million of total outstanding debt. This represents an approximate net decrease of $20.8 million from December 31, 2001 primarily due to the use of $20.0 million in equity offering proceeds to pay down our loans. Of the $98.3 million of outstanding debt, $30.9 million represents borrowings on our three revolving credit facilities and $67.4 million represents borrowings on seven term-debt facilities. At December 31, 2002, we had $31.4 million available under our three revolving credit facilities. At March 15, 2003, we had $15.1 million available under our three revolving credit facilities. Interest rates vary from Libor plus 2.5% to Prime plus 0.5%. Our weighted average interest rate was 4.21% at December 31, 2002, and our term-debt borrowings currently require $680,000 in monthly principal payments.

Our loans require that certain conditions be met in order for us to obtain advances. Our loans are collateralized by mortgages on our vessels and accounts receivable. Advances under our revolving credit facilities may be obtained in accordance with a borrowing base defined as a percentage of accounts receivable balances and costs in excess of billings. The loans contain customary defaults and some require us to maintain certain financial ratios. The loan agreements also contain certain covenants that limit our ability to incur additional debt, pay dividends, create certain liens, sell assets and make capital expenditures.

In September and December 2002, we amended one of our revolving credit facilities to increase the financial ratio related to our financial leverage of debt to EBITDA (earnings before interest, taxes, depreciation, amortization) for periods ending on or before June 30, 2003. We have experienced a reduction in our EBITDA primarily due to reduced demand, lower margins on projects and the $2.0 million loss related to the Lone Star Horizon in the third quarter of 2002. We were in compliance with all of our amended debt covenants at December 31, 2002.

We also incurred debt to fund our working capital requirements in Mexico due to the timing of collections related to our Pemex claims. We may need to borrow additional funds to meet working capital requirements for 2003 contingent upon the timing and magnitude of collection of our Pemex receivables and claims. If we are required to make additional borrowings in excess of our current debt facilities, we will be required to amend financial covenants under our revolving credit facilities. Although we can provide no assurance, we believe that we will be able to borrow additional funds secured by mortgages on our vessels and amend financial covenants as required.

We have fixed debt service and lease payment obligations under notes payable and operating leases for which we have material contractual cash obligations. Interest rates on our debt vary from Libor plus 2.5% to prime plus 0.5%. The following table summarizes our long-term material contractual cash obligations (in millions):

Current maturities of long-term debt were $8.3 million as of December 31, 2002. Planned capital expenditures for 2003 are estimated to range from approximately $20.0 million to $24.0 million largely related to vessel improvements. Our strategy, however, is to make other acquisitions, to expand our operating capabilities and expand into additional selected international areas. To the extent we are successful in identifying acquisition and expansion opportunities and have expanded our market share in those areas, we may require additional equity or debt financing depending on the size of any transaction.

Our market risk exposures primarily include interest rate and exchange rate fluctuation on financial instruments as detailed below. Our market risk sensitive instruments are classified as “other than trading.” The following sections address the significant market risks associated with our financial activities during 2002. Our exposure to market risk as discussed below includes “forward-looking statements” and represents estimates of possible changes in fair values and future earnings or cash flows that would occur assuming hypothetical future movements in foreign currency exchange rates or interest rates.

As of December 31, 2002 the carrying value of our debt, including $0.1 million of accrued interest, was approximately $98.4 million. The fair value of this debt approximates the carrying value because the interest rates are based on floating rates identified by reference to market rates. A hypothetical 1% increase in the applicable interest rates as of December 31, 2002 would increase annual interest expense by approximately $1.0 million.

In Mexico, we collect a portion of our revenues and pay local expenses in foreign currency. We manage foreign currency risk by attempting to contract as much foreign revenue as possible in U.S. dollars. Approximately 80% of our current contracts with Pemex is denominated in U.S. dollars. We receive payment in Mexican pesos equivalent to the U.S. dollars billed, which is converted to U.S. dollars that day or the following day. Our contracts in Mexico also typically provide some protection from declining exchange rates on the portion of the contract revenues denominated in foreign currency. We recognized a $0.8 million foreign currency loss due to activity denominated in Mexican pesos and a decline of the Mexican peso compared to the U.S. dollar for 2002. We monitor the exchange rate of our foreign currencies in order to mitigate the risk from foreign currency fluctuations. Additional exposure could occur as we expand internationally.

The level of construction services required by a customer depends on the size of their capital expenditure budget for construction for the year. Consequently, customers that account for a significant portion of contract revenues in one year may represent an immaterial portion of contract revenues in subsequent years.

Our consolidated financial statements and supplementary data appear on pages 30 through 53 in this report and are incorporated herein by reference. See Index to consolidated financial statements on page 28.

On June 14, 2002, upon the recommendation of the audit committee of our board of directors, the board of directors dismissed Arthur Andersen LLP (Andersen) as our independent public accountants. We selected PricewaterhouseCoopers LLP (PwC) as our new independent accountants. The decision to select PwC was recommended by the audit committee and approved by the board of directors. During the two fiscal years ended December 31, 2001 and the subsequent interim period preceding such selection, neither we nor anyone on our behalf consulted PwC regarding either (1) the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on our financial statements, nor did PwC provide to us a written report or oral advice regarding such principles or audit opinion; or (2) any matter that was either the subject of a disagreement or a reportable event.

None of Andersen’s reports on our consolidated financial statements for the past two fiscal years contained an adverse opinion or disclaimer of opinion, nor was any such report qualified or modified as to uncertainty, audit scope or accounting principles.

During each of our two most recent fiscal years and through the date of this report there were: (i) no disagreements with Andersen on any matter of accounting principle practice, financial statement disclosure, or auditing scope or procedures, which disagreements, if not resolved to Andersen’s satisfaction, would have caused them to make reference to the subject matter in connection with their report on our consolidated financial statements for such years; and (ii) no reportable events as defined in Item 304(a)(1)(v) of Regulation S-K.

Information concerning our directors and executive officers called for by this item will be included in our definitive Proxy Statement prepared in connection with the 2003 annual meeting of stockholders and is incorporated herein by reference. For additional information regarding executive officers, see “Executive Officers of the Registrant” of this Annual Report.

Information concerning the compensation of the executive officers called for by this item will be included in our definitive Proxy Statement prepared in connection with the 2003 annual meeting of stockholders and is incorporated herein by reference.

Information concerning security ownership of certain beneficial owners and management called for by this item will be included in our definitive Proxy Statement prepared in connection with the 2003 annual meeting of stockholders and is incorporated herein by reference.

Information concerning certain relationships and related transactions called for by this item will be included in our definitive Proxy Statement prepared in connection with the 2003 annual meeting of stockholders and is incorporated herein by reference.

Within the 90-day period prior to the filing of this Annual Report, an evaluation was performed under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 13a-14(c) of the rules promulgated under the Securities Exchange Act of 1934, as amended. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective. There have been no significant changes in our internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.


	Schedules have not been included because they are not applicable, immaterial or the information required has been included in the financial statements or notes thereto.


	(a) Exhibits

	See Index to Exhibits on page 57. We will furnish to any eligible stockholder, upon written request, a copy of any exhibit listed upon payment of a reasonable fee equal to our expenses in furnishing such exhibit.

	(b) Reports on Form 8-K

On October 9, 2002, we filed a report on Form 8-K, reporting under Item 7, announcing the award of a major portion of Chevron Nigeria Ltd.’s Escravos Offshore Pipeline and Structural Installation two year program.

On October 16, 2002, we filed a report on Form 8-K, reporting under Item 7, announcing the award of a contract to our subsidiary, Horizon Offshore Contractors, Inc., by Williams Oil Gathering, LLC to install pipeline in the U.S. Gulf of Mexico.

On October 28, 2002, we filed a report on Form 8-K, reporting under Item 7, announcing the award of a contract to our subsidiary, Horizon Marine Construction, Ltd., by Brunei Shell Petroleum Company Sdn. Bhd.

On October 30, 2002, we filed a report on Form 8-K, reporting under Item 7, reporting earnings for the quarter ended September 30, 2002.

In our opinion, the accompanying consolidated balance sheet as of December 31, 2002 and the related consolidated statements of operations, stockholders’ equity, and cash flows present fairly, in all material respects, the financial position of Horizon Offshore, Inc. (a Delaware Corporation), and subsidiaries at December 31, 2002 and the results of their operations and their cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these 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 audit provides a reasonable basis for our opinion. The financial statements of Horizon Offshore, Inc. as of December 31, 2001, and for each of the two years in the period ended December 31, 2001, were audited by other independent accountants who have ceased operations. Those independent accountants expressed an unqualified opinion on those financial statements in their report dated February 28, 2002.

The following audit opinion is a copy of the opinion issued by Arthur Andersen LLP on February 28, 2002. This opinion has not been reissued by Arthur Andersen LLP. Note that only the Consolidated Balance Sheet as of December 31, 2001 and the Consolidated Statements of Operations, Stockholders’ Equity and Cash Flows for the years ended December 31, 2001 and 2000 covered by this report below are included in this set of consolidated financial statements.

We have audited the accompanying consolidated balance sheets of Horizon Offshore, Inc. (a Delaware corporation), and subsidiaries as of December 31, 2001 and 2000, and the related consolidated statements of operations, stockholders’ equity and cash flows for the years ended December 31, 2001, 2000 and 1999. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Horizon Offshore, Inc., and subsidiaries as of December 31, 2001 and 2000, and consolidated results of their operations and their cash flows for the years ended December 31, 2001, 2000 and 1999, in conformity with accounting principles generally accepted in the United States.

The accompanying notes are an integral part of these consolidated financial statements.

Horizon Offshore, Inc. (a Delaware corporation) and its subsidiaries (Horizon), provides marine construction services for the offshore oil and gas industry. These services generally consist of laying and burying marine pipelines for the transportation of oil and gas, and installing and salvaging production platforms and other marine structures. Work is performed primarily on a fixed-price or day-rate basis or a combination thereof.

Our level of activity depends largely on the condition of the oil and gas industry and, in particular, the level of capital expenditures by oil and gas companies for developmental construction. These expenditures are influenced by prevailing oil and gas prices, expectations about future demand and prices, the cost of exploring for, producing and developing oil and gas reserves, the discovery rates of new oil and gas reserves, sale and expiration dates of offshore leases in the United States and abroad, political and economic conditions, governmental regulations and the availability and cost of capital. Historically, oil and gas prices and the level of exploration and development activity have fluctuated substantially, impacting the demand for pipeline and marine construction services.

A prolonged weakness in energy prices or a prolonged period of lower levels of offshore drilling and exploration could adversely affect our future revenues, profitability and liquidity. Our 2002 results reflect the competitive nature and low demand for marine construction services in the U.S. Gulf of Mexico. Profit margins in the U.S. Gulf of Mexico have decreased during 2002 due to the reduced level of capital expenditures by oil and gas companies for developmental construction and the general slow down of the U.S. and other economies in the region.

Factors affecting our profitability include competition, equipment and labor productivity, contract estimating, weather conditions and the other risks inherent in marine construction. The marine construction industry in the U.S. Gulf of Mexico is highly seasonal as a result of weather conditions, with the greatest demand for these services occurring during the second and third quarters of the year. Full year results are not a direct multiple of any quarter or combination of quarters because of this seasonality.

We have domestic and international operations in one industry segment, the marine construction service industry to offshore oil and gas companies. Our customers in the U.S. have primarily been the oil and gas companies operating on the U.S. outer continental shelf. In 2002, we provided offshore marine construction services to approximately 41 customers. Our single largest customer during the last three years was Pemex. We completed one major project for a subsidiary of Pemex in 2001 and completed two major projects for Pemex in 2002, and we completed another project during the first quarter of 2003. Pemex accounted for 30.6% of our revenues for the year 2002 compared to 52.2% of revenues for 2001 and 36.1% of revenues for 2000. Our receivables from Pemex continue to impact our liquidity and operating cash flows. As of December 31, 2002, we have recognized contract receivables of $14.2 million and costs in excess of billings of $62.7 million from Pemex totaling $76.9 million.

The consolidated financial statements include the accounts of Horizon and its subsidiaries. All significant intercompany balances and transactions have been eliminated.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the reporting period. Management must apply significant judgments in this process. Among the factors, but not fully inclusive of all factors, that may be considered by management in these processes are: the range of accounting policies permitted by accounting principles generally accepted in the United States; management’s understanding of our business; expected rates of business and operational change; sensitivity and volatility associated with the assumptions used in developing estimates; and whether historical trends are expected to be representative of future trends. Among the most subjective judgments employed in the preparation of these financial statements are estimates of expected costs to complete construction projects, the collectibility of contract receivables and claims, the fair value of salvage inventory, the depreciable lives of and future cash flows to be provided by our equipment, the period and extent of maintenance and repairs for dry-docking activity and certain judgments regarding the nature of income and expenditures for tax purposes. We review all significant estimates on a recurring basis and record the effect of any necessary adjustments prior to publication of our financial statements. Adjustments made with respect to the use of estimates often relate to improved information not previously available. Because of the inherent uncertainties in this process, actual future results could differ from those expected at the reporting date.

Construction contract revenues are recognized on the percentage-of-completion method, measured by the percentage of costs incurred to date to the total estimated costs for each construction contract. We consider the percentage-of-completion method to be the best available measure of progress on these contracts. We follow the guidance of American Institute of Certified Public Accountants (AICPA) Statement of Position (SOP) 81-1, “Accounting for Performance of Construction-Type and Certain Production-Type Contracts,” for our accounting policy relating to use of the percentage-of-completion method, estimating costs and claim recognition for construction contracts. Contract revenue reflects the original contract price adjusted for agreed upon change orders and unapproved claims. We recognize unapproved claims only when the collection is deemed probable and if the amount can be reasonably estimated for purposes of calculating total profit or loss on long-term contracts. We record revenue and the unbilled receivable for claims to the extent of costs incurred and include no profit on claims recorded. Changes in job performance, job conditions and estimated profitability, including those arising from final contract settlements, may result in revisions to costs and revenues and are recognized in the period in which the revisions are determined. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are determined. The asset “Costs in excess of billings” represents revenues recognized in excess of amounts billed as determined on an individual contract basis. The liability “Billings in excess of costs” represents amounts billed in excess of revenues recognized as determined on an individual contract basis.

For service contracts, revenues are recognized under Staff Accounting Bulletin (SAB) No. 101, “Revenue Recognition in Financial Statements,” when all of the following criteria are met; persuasive evidence of an arrangement exists; delivery has occurred or services have been rendered; the seller’s price is fixed or determinable; and collectability is reasonably assured.

Cost of contract revenues includes all direct material and labor costs and certain indirect costs, which are allocated to contracts based on utilization, such as supplies, tools, repairs and depreciation. Selling, general and administrative costs are charged to expense as incurred.

Interest is capitalized on the average amount of accumulated expenditures for equipment that is undergoing major modifications and refurbishment prior to being placed into service. Interest is capitalized using an effective rate based on related debt until the equipment is placed into service. Interest expense for 2002 was net of $1.6 million of capitalized interest compared with $1.3 million in 2001 and $0.3 million in 2000. Net interest expense was $4.6 million, $5.4 million and $7.7 million for 2002, 2001 and 2000, respectively.

We consider all cash in banks and highly liquid investments with original maturity dates of three months or less to be cash equivalents.

Inventory consists of production platforms and other marine structures received from time to time as partial consideration from salvage projects performed in the U.S. Gulf of Mexico. During 2002, revenue of $6.8 million was recognized representing the non-cash values assigned to the structures received as partial consideration for performing salvage projects. No significant non-cash consideration was received during 2001 and 2000. These structures are held for resale. The inventory is valued at amounts not in excess of the fair value of services provided. Horizon assesses the net realizable value of its inventory items at each balance sheet date. Inventory is classified as long-term due to the uncertain timing of the sale of inventory.

We use the units-of-production method to calculate depreciation on our major barges, vessels and related equipment to accurately reflect the wear and tear of normal use. The useful lives of our major barges and vessels range from 15 years to 18 years. Major additions and improvements to barges, boats and related equipment are capitalized and depreciated over the useful life of the vessel. Maintenance and repairs are expensed as incurred. When equipment is sold or otherwise disposed of, the cost of the equipment and accumulated depreciation are removed from the accounts and any gain or loss is reflected in income.

Depreciation on our other fixed assets is provided using the straight-line method based on the following estimated useful lives:

On January 1, 2000, we changed depreciation methods from the straight-line method to the units-of-production method on our major barges and vessels to more accurately reflect the wear and tear of normal use. We believe that the units-of-production method is best suited to reflect the actual deterioration of our marine equipment. Depreciation expense calculated under the units-of-production method may be different than depreciation expense calculated under the straight-line method in any period. The annual depreciation based on utilization of each vessel will not be less than 25% of annual straight-line depreciation, and the cumulative depreciation based on utilization of each vessel will not be less than 50% of cumulative straight-line depreciation. For the year ended December 31, 2000, we recorded the cumulative effect of a $1.4 million adjustment, or $0.07 per share, which is net of taxes of $0.7 million, related to changing depreciation methods from the straight-line method to the units-of-production method.

As of December 31, 2002, fixed assets totaling $17.5 million, excluding land, are not being depreciated as some of these assets are under construction and others have not been placed into service.

cash flows for our long-term assets, we recognized a $9.9 million impairment loss related to the Phoenix Horizon under Statement of Financial Accounting Standards (SFAS) No. 144 for the year ended December 31, 2002. We believe that the Phoenix Horizon would require improvements and upgrades in order to place it into service. Our planned use of the Phoenix Horizon changed during the fourth quarter of 2002 based on capital requirements and the projected utilization of our operating fleet in the current market conditions, which we expect to continue for at least the first half of 2003. We determined that we would not invest in the improvements required to place the barge into service under current conditions. The impairment loss was based upon the cost of the Phoenix Horizon in excess of its estimated fair value based upon estimated discounted future cash flows. No impairments were recognized for the years ended December 31, 2001 and 2000.

Other assets consist principally of deferred dry-dock costs, goodwill, prepaid loan fees and deposits. Deposits consist of security deposits on office leases as of December 31, 2002 and 2001. Loan fees paid in connection with the loan facilities are amortized over the term of the loans. See Note 5.

In August 2002, Horizon acquired the remaining 51% equity interest in an entity in Mexico for $1.0 million cash. Horizon previously had a 49% equity interest in this entity and included its accounts in Horizon’s consolidated financial statements as Horizon exercised effective control over the entity’s operations. As a result of this acquisition, Horizon will be qualified to bid on and perform projects reserved for national companies in Mexico without a locally domiciled partner. We recorded $1.0 million of goodwill in connection with acquiring the equity interest, which is nondeductible for tax purposes. The related goodwill is included in other long-term assets at December 31, 2002.

We use the liability method of accounting for income taxes. Under the liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to temporary differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period enacted.

At December 31, 2002, we had two stock-based employee compensation plans, which are described more fully in Note 9. We account for those plans under the recognition and measurement principles of Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related Interpretations. No stock-based employee compensation cost is reflected in net income (loss), as all options

granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income (loss) and earnings per share if we had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-Based Compensation,” to stock-based employee compensation.

To determine pro forma information as if we had accounted for the employee stock options under the fair value method as defined by SFAS No. 123, we used the Black-Scholes method and assumed no dividends, as well as the following additional weighted average assumptions included in the following table.

The carrying values of cash, receivables, accounts payable and accrued liabilities approximate fair value due to the short term maturity of those instruments.

As of December 31, 2002 the carrying value of our debt, including $0.1 million of accrued interest, was approximately $98.4 million. The fair value of this debt approximates the carrying value because the interest rates are based on floating rates identified by reference to market rates. A hypothetical 1% increase in the applicable interest rates as of December 31, 2002 would have increased annual interest expense by approximately $1.0 million.

We have domestic and international operations in one industry segment, the marine construction service industry for offshore oil and gas companies. We completed one major project for a subsidiary of Pemex in 2001 and completed two major projects for Pemex in 2002, and we completed another project during the first quarter of 2003. Pemex accounted for 30.6% of our revenues for the year 2002, as compared to 52.2% of revenues for 2001 and 36.1% of revenues for 2000.

In addition to Pemex, we had one other customer accounting for more than 10% of consolidated revenues for the year ended December 31, 2002. This domestic customer accounted for 19.7% of consolidated revenues for the year ended December 31, 2002. There were no other customers accounting for more than 10% of consolidated revenues for the year ended December 31, 2002, 2001 or 2000.

revenues in one year may represent an immaterial portion of contract revenues in subsequent years. Based upon our interpretation of the requirements of SFAS No. 131, “Disclosures About Segments of an Enterprise and Related Information,” Horizon has domestic and international operations in one industry segment, the marine construction service industry for offshore oil and gas companies. Geographic information has been provided in Note 12 of these consolidated financial statements.

Earnings per share data for all periods presented has been computed pursuant to SFAS No. 128, “Earnings Per Share,” that requires a presentation of basic earnings per share (basic EPS) and diluted earnings per share (diluted EPS). Basic EPS excludes dilution and is determined by dividing income available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted EPS reflects the potential dilution that could occur if securities and other contracts to issue common stock were exercised or converted into common stock.

We have no items representing other comprehensive losses under SFAS No. 130, “Reporting Comprehensive Income.”

Certain prior period amounts have been reclassified to conform to the presentation shown in the consolidated financial statements as of December 31, 2002. Reclassifications in 2001 and 2000 had no effect on net income or total stockholders’ equity and relate to the classification of dry-docking expenditures and borrowings and payments on our revolving credit facilities in the consolidated statements of cash flows. For the year ended December 31, 2001, cash used in operating activities was increased by $7.1 million and cash used in investing activities was reduced by $7.1 million. For the year ended December 31, 2000, cash provided by operating activities was reduced by $2.0 million and cash used in investing activities was reduced by $2.0 million.

In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 141, “Business Combinations,” and SFAS No. 142, “Goodwill and Other Intangible Assets.” The new rules apply to goodwill and intangible assets acquired after June 30, 2001 and to existing goodwill and intangible assets upon adoption of SFAS No. 141 and SFAS No. 142. The new rules establish one method of accounting for all business combinations and the resulting goodwill and other intangible assets. Under SFAS No. 142, intangible assets with a finite life will generally continue to be amortized over their lives while intangibles without a finite life, including goodwill, will no longer be amortized. However, tests for impairment will be performed annually or upon the occurrence of a triggering event. We adopted SFAS No. 142 on January 1, 2002, and there was no significant impact to our financial statements upon adoption.

In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” The provisions of SFAS No. 143 apply to all entities that incur obligations associated with the retirement of tangible long-lived assets and establishes an accounting standard requiring the recording of the fair value of liabilities associated with the retirement of long-term assets in the period in which the liability is incurred. SFAS No. 143 is effective for financial statements issued for fiscal years beginning after June 15, 2002. The adoption of this standard will not have a significant impact on our consolidated financial statements.

In August 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” The FASB’s new rules on asset impairment supersede SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of”, and was effective for our fiscal year beginning January 1, 2002. We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of any such asset may not be recoverable. We record impairment losses on long-lived assets used in operations when the cash flows estimated to be generated by

those assets are less than the carrying amount of those items. The net carrying value of assets not fully recoverable is reduced to fair value. Our estimate of fair value represents our best estimate based on industry trends and reference to market transactions and is subject to variability. Based on our analysis of the estimated discounted future cash flows for our long-term assets, we recognized a $9.9 million impairment loss related to the Phoenix Horizon under SFAS No. 144 for the year ended December 31, 2002.

In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections,” which revises current guidance with respect to gains and losses on early extinguishment of debt. Under SFAS No. 145, gains and losses on early extinguishment of debt will no longer be treated as extraordinary items unless they meet the criteria for extraordinary treatment in APB Opinion No. 30. Horizon will be required to adopt SFAS No. 145 effective January 1, 2003. Upon adoption, we will be required to reclassify the extraordinary loss on early extinguishment of debt from the year ended December 31, 2001, as this amount will no longer qualify for extraordinary treatment under SFAS No. 145.

In November 2002, the FASB issued FASB Interpretation No. 45 (FIN 45), “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” FIN 45 elaborates on the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. FIN 45 does not prescribe a specific approach for subsequently measuring the guarantor’s recognized liability over the term of the related guarantee. It also incorporates, without change, the guidance in FASB Interpretation No. 34, “Disclosure of Indirect Guarantees of Indebtedness of Others”, which is being superseded. We will apply the recognition and measurement provisions of FIN 45 on a prospective basis to guarantees issued or modified after December 31, 2002. We are currently evaluating the recognition and measurement provisions of FIN 45 and have not determined the impact this statement will have on our consolidated financial position or results of operations. The disclosure requirements in this interpretation are effective beginning with the December 31, 2002 financial statements.

In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure — an amendment of SFAS No. 123.” SFAS No. 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation,” to provide alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation. In addition, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. SFAS No. 148 does not permit the use of the original SFAS No. 123 prospective method of transition for changes to the fair value based method made in fiscal years beginning after December 15, 2003. The adoption of this standard will not have a significant impact on our consolidated financial statements.

On June 29, 2001, the AICPA issued an exposure draft of a proposed SOP, “Accounting for Certain Costs and Activities Related to Property, Plant, and Equipment.” This proposed SOP would change, among other things, the method by which companies would account for normal, recurring or periodic repairs and maintenance costs related to “in service” fixed assets. It would require that these types of expenses be recognized when incurred rather than recognizing expense for these costs while the asset is productive. If adopted, we would be required to expense regulatory maintenance cost on our vessels as incurred. We currently capitalize a significant portion of these costs and amortize them over the future periods they are expected to benefit. We incurred dry-dock costs of $5.8 million in 2002, $7.1 million in 2001 and $2.0 million in 2000. As of December 31, 2002, deferred dry-dock costs totaled $12.9 million. Expensing dry-dock costs would likely result in greater variability of our quarterly earnings as a substantial portion of our dry-dock activities take place during the first and fourth quarters.

In March 2001, we paid $30.0 million to reduce the outstanding principal balance under our term loan, which was subject to a penalty of $0.9 million ($0.6 million net of taxes of $0.3 million), or $0.03 per share-diluted, for the early extinguishment of debt. The penalty was recorded as an extraordinary loss in 2001. Upon adoption of SFAS No. 145, we will be required to reclassify the extraordinary loss to other expense for the year ended December 31, 2001.

Contract receivables are generally billed upon the completion of small contracts and are progress billed on larger contracts in accordance with contract terms and milestones. Costs in excess of billings solely represent costs incurred and estimated earnings on jobs in progress.

We have not experienced material losses from uncollected receivables. Our principal customers are national oil companies, and major and independent oil and gas companies and their affiliates. The concentration of customers in the energy industry may impact our overall credit exposure, either positively or negatively, since these customers may be similarly affected by changes in economic or other conditions. Billed and unbilled receivables from Pemex totaled $76.9 million at December 31, 2002. Accordingly, there is significant concentration of risk with that single customer.

A summary of the balance of claims remaining in costs in excess of billings related to the Pemex projects are as follows (in millions):

At December 31, 2002, we had approximately $98.3 million in total outstanding debt. This represents an approximate decrease of $20.8 million from December 31, 2001. This decrease in debt is due to the use of $20.0 million in equity offering proceeds to pay down our loans. Of the $98.3 million of outstanding debt, $30.9 million represents borrowings on our three revolving credit facilities and $67.4 million represents borrowing on the seven term-debt facilities. At December 31, 2002, we had $31.4 million available under our three revolving facilities. Interest rates vary from Libor plus 2.5% to prime plus 0.5%. Our average interest rate at December 31, 2002 was 4.21%, and our term-debt borrowings currently require $680,000 in total monthly principal payments.

Our loans require that certain conditions be met in order for us to obtain advances. Our loans are collateralized by mortgages on our vessels and by accounts receivable. Advances under our revolving credit facilities may be obtained in accordance with a borrowing base defined as a percentage of accounts receivable balances and costs in excess of billings. The loans contain customary default provisions and some require us to maintain certain financial ratios. The loan agreements also contain certain covenants that limit our ability to incur additional debt, pay dividends, create certain liens, sell assets and make capital expenditures.

In September and December 2002, we amended one of our revolving credit facilities to increase the financial ratio related to our financial leverage of debt to EBITDA (earnings before interest, taxes, depreciation, amortization) for periods ending on or before June 30, 2003. We have experienced a reduction in our EBITDA primarily due to reduced demand, lower margins on projects and the $2.0 million casualty loss related to the Lone Star Horizon in the third quarter of 2002. We were in compliance with all of our amended debt covenants at December 31, 2002.

We incurred debt to fund our working capital requirements in Mexico due to the timing of collections related to our Pemex claims. Also, we may be required to borrow funds to meet working capital requirements for 2003 contingent upon the timing of the collection of our Pemex receivables and claims. If we are required to make additional borrowings in excess of our current debt facilities, we will be required to amend financial covenants under our revolving credit facilities. Although there can be no assurance, we believe that we will be able to borrow additional funds collateralized by mortgages on our vessels, refinance debt and amend financial covenants as required.

Maturities of long-term debt for each of the years ending December 31 are as follows (in thousands):

Our provision for income taxes in the statement of operations excludes $306,000 of deferred tax benefit that is presented in the extraordinary loss for 2001 and $743,000 of deferred tax provision that is presented in the cumulative effect of a change in accounting principle for 2000. Total tax expense (benefit) for the years ended December 31, 2002, 2001 and 2000 consists of (in thousands):

The income tax expense (benefit) for the years ended December 31, 2002, 2001 and 2000 differs from the amount computed by applying the U.S. statutory federal income tax rate of 34 percent to consolidated income before income taxes as follows (dollars in thousands):

The decrease in our effective tax rate and difference from the statutory rate for 2001 is due primarily to the cumulative effect of the initial application of the extraterritorial income exclusion for income primarily earned in Mexico from October 1, 2000 to December 31, 2001. The exclusion for 2002 consists of income earned in Mexico and parts of Southeast Asia from January 1, 2002 to December 31, 2002. The exclusion allows us to exclude a qualifying portion of income earned outside the United States for tax purposes. The impact of this exclusion on future periods will vary depending upon the amount of qualifying income earned outside the United States.

The tax effects of the temporary differences that give rise to the significant portions of the deferred tax assets and liabilities are presented below (in thousands):

The realization of a significant portion of deferred tax assets is based in part on our estimates of the timing of reversals of certain temporary differences and on the generation of taxable income before such reversals. The net operating loss carryforwards of approximately $86.5 million at December 31, 2002 begin to expire in the year 2012. Our ability to utilize the net operating loss carryforwards could be limited by a change in ownership as defined by federal income tax regulations.

We are involved in various routine legal proceedings primarily involving claims for personal injury under the Jones Act and general maritime laws which we believe are incidental to the conduct of our business. We believe that these proceedings, individually and in the aggregate, if adversely determined, would not have a material adverse effect on our financial position and results of operations.

We lease office space at various locations under operating leases that expire through 2008. Our operating leases for our corporate office are subject to increases for variable operating expenses. Rental expense was $2.4 million for 2002, $1.5 million for 2001 and $1.0 million for 2000. Future minimum non-cancelable lease commitments under these agreements for the years ending December 31 are as follows (in thousands):

We participate in a retrospectively rated insurance agreement. In our opinion, we have adequately accrued for all liabilities arising from these agreements based upon the total incremental amount that would be paid based upon the with-and-without calculation assuming experience to date and assuming termination.

We have entered into employment agreements with three executive officers that expire in 2004, and we have purchased $5.0 million in “key-man” life insurance with respect to our Chief Executive Officer, for which Horizon is the named beneficiary.

We have a 401(k) plan for all eligible employees and we make annual contributions to the plan, at the discretion of management. We contributed $406,000, $331,000 and $247,000 of common stock to the plan during 2002, 2001 and 2000, respectively. We intend to continue to make future contributions with Horizon common stock.

In February 2001, we sold 3,800,000 shares of common stock in a secondary offering. We received $66.0 million after deducting the underwriting discount and expenses. We used $30.0 million to reduce indebtedness, and $5.6 million for the initial purchase of the Pecos Horizon. The remainder was used for general corporate purposes.

On January 11, 2001, our board of directors adopted a stockholders’ rights plan. In connection with the plan, the board of directors approved the authorization of 100,000 shares of $1.00 par value per share, designated the Series A Participating Cumulative Preferred Stock. Under the plan, preferred stock purchase rights were distributed as a dividend at a rate of one right for each share of our common stock held as of record as of the close of business on January 11, 2001. Additional rights will be issued in respect of all shares of common stock issued while the rights plan is in effect. Each right entitles stockholders of common stock to buy a fraction of a share of the new series of preferred stock at an exercise price of $50. The rights will become exercisable and detach from the common stock, only if a person or group acquires 20% or more of the outstanding common stock, or announces a tender or exchange offer that, if consummated, would result in a person or group beneficially owning 20% or more of the outstanding common stock. Once exercisable, each right will entitle the holder (other than the acquiring person) to acquire common stock with a value of twice the exercise price of the rights. Horizon will generally be able to redeem the rights at $.001 per right at any time until the close of business on the tenth day after the rights become exercisable. The rights will expire on January 11, 2011, unless redeemed or exchanged at an earlier date.

In January 1998, the board of directors and the stockholders approved the Stock Incentive Plan (the Plan). The Plan provides for the granting of stock options to directors, executive officers, other employees and certain non-employee consultants. The amended Plan has 3.15 million shares available for issuance as

optioned shares and terminates in April 2009. The terms of the option awards (including vesting schedules) are established by the Compensation Committee of the board of directors, but generally vest ratably over three years and unexercised options expire ten years from the date of issue. In May 2002, the board of directors and the stockholders approved the 2002 Stock Incentive Plan (the 2002 Plan). The 2002 Plan has 2.3 million shares available for issuance as optioned shares and shall remain in effect until all awards granted under the 2002 Plan have been satisfied. This plan has the same characteristics as the Plan approved in 1998. At December 31, 2002, we had options for 2.3 million shares of common stock remaining to be issued in aggregate under both plans.

The following table summarizes activity under both plans for the years ended December 31, 2002, 2001 and 2000:

The following table summarizes information on stock options outstanding and exercisable as of December 31, 2002, pursuant to both plans:

As of December 31, 2002, treasury stock consisted of 912,207 shares at a cost of $6.0 million, following the issuance of 61,298 and 29,895, shares for the Company’s 401(k) contributions in 2002 and 2001, respectively. Treasury stock is stated at the average cost basis.

The following table presents information necessary to calculate earnings per share for the three years ended December 31, 2002 (in thousands, except per share amounts):

As of December 31, 2002, we had outstanding options covering an aggregate of 2,718,220 shares of common stock, of which 1,924,133 shares were exercisable. Excluded from the computation of diluted earnings per share are options to purchase 2,718,220 shares of common stock outstanding as of December 31, 2002 at a weighted average price of $8.59 per share, 166,800 shares of common stock as of December 31, 2001 at a weighted average price of $19.06 per share and no shares in 2000, as they would be antidilutive.

In August 1998, we entered into a master services agreement with Odyssea Marine, Inc. (Odyssea), an entity wholly-owned by Elliott Associates, L.P. and Elliott International, L.P., collectively our largest stockholder, to charter certain marine vessels from Odyssea. As of December 31, 2002, we owed Odyssea $4.2 million for charter services compared to $0.6 million at December 31, 2001. Odyssea billed Horizon and Horizon paid Odyssea for services rendered under the agreement as follows (in millions):

We have loaned $332,000 to three of our executive officers. In October 2000, we loaned $142,000 to R. Clay Etheridge, Executive Vice President and Chief Operations Officer. The principal amount remains outstanding. In April and May 2002, we loaned $110,000 to Bill J, Lam, President and Chief Executive Officer and $80,000 to David W. Sharp, Executive Vice President and Chief Financial Officer, respectively. Both of these loan amounts have been paid in full.

On September 20, 2002, the pipelay barge, Lone Star Horizon, sustained electrical damage due to a fire while at anchor off Ciudad Del Carmen, Mexico. Repairs to the Lone Star Horizon were completed during the fourth quarter of 2002 at a cost of $5.0 million. We maintain hull and machinery insurance to cover physical damage to our vessels. This insurance coverage provides for both a $0.5 million occurrence deductible and a $1.5 million annual aggregate deductible. During 2002, we recorded this $2.0 million loss as other expense, and we believe the insurance will cover the cost of the repairs. As of December 31, 2002, we included the $3.0 million insurance claim in current assets. We collected an initial reimbursement of $1.2 million in February 2003.

Horizon operates in the marine construction services industry. Geographic information relating to Horizon’s operations follows (in millions):


(1)	Unallocated costs include support costs and operational overhead costs included in cost of contract revenues.

(2)	Long-lived assets include vessels, property and related marine equipment. Amounts reflect the location of the assets at December 31, 2002 and 2001. Equipment location changes as necessary to meet working requirements. Other identifiable assets include inventory and other long-term assets, and are primarily located in the Domestic geographic segment. Goodwill is located in the Latin America geographic segment.

The marine construction industry in the U.S. Gulf of Mexico is seasonal, with contracts being awarded in the spring and early summer and the work being performed before the onset of adverse weather conditions in the winter. Seasonality and adverse weather conditions historically have resulted in lower revenues in the first and fourth quarters. Full year results are not a direct multiple of any quarter or combination of quarters because of this seasonality.

The following table sets forth selected quarterly information for 2002 and 2001 (in thousands, except per share data). We believe that all necessary adjustments have been included in the amounts stated below to present fairly the results of such periods.


(1)	Operating loss and net loss for the quarter ending December 31, 2002 includes a $9.9 million impairment pre-tax loss related to the Phoenix Horizon.

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 our behalf by the undersigned, thereunto duly authorized on March 28, 2003.


	By:	/s/ DAVID W. SHARP



	David W. Sharp
	Executive Vice President and
	Chief Financial Officer

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.

2. Based on my knowledge, this Annual Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Annual Report;

3. Based on my knowledge, the financial statements, and other financial information included in this Annual Report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this Annual Report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:


	(a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Annual Report is being prepared;

	(b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this Annual Report (the “Evaluation Date” ); and

	(c) presented in this Annual Report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):


	(a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

	(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this Annual Report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.


	/s/ BILL J. LAM

	Bill J. Lam
	President and Chief Executive Officer
	(Principal Executive Officer)


	(a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Annual Report is being prepared;

	(b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this Annual Report (the “Evaluation Date”); and

	(c) presented in this Annual Report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;


	(a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

	(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and


	/s/ DAVID W. SHARP

	David W. Sharp
	Executive Vice President and
	Chief Financial Officer
	(Principal Financial Officer)


	(1)	Incorporated by reference to the Company’s Registration Statement on Form S-1 (Registration Statement No. 333-43965).

	(2)	Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000.

	(3)	Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2000.

	(4)	Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2000.

	(5)	Incorporated by reference to the Company’s Annual Report on Form 10-K for the year ended December 31, 1999.

	(6)	Incorporated by reference to the Company’s Annual Report on Form 10-K for the year ended December 31, 1998.


	(7)	Incorporated herein by reference to Exhibits 1, 2, 3 and 4 to the Company’s Registration Statement on Form 8-A12B, filed with the Commission on January 18, 2002.

	(8)	Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2001.

	(9)	Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2001.


(10)	Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2001.

(11)	Incorporated by reference to the Company’s Annual Report on Form 10K-405 for the year ended December 31, 2001.

(12)	Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002

(13)	Incorporated by reference to Exhibit A to our Definitive Schedule 14A filed on April 8, 2002.

(14)	Incorporated by reference to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2002.

(15)	Filed herewith.


(Mark One)
þ		ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 for the fiscal year ended December 31, 2002

o		TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


Delaware		76-0487309
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

2500 CityWest Boulevard Suite 2200 Houston, Texas		77042
(Address of principal executive offices)		(Zip Code)


PART I
	Items 1. and 2. Business And Properties
	Item 3. Legal Proceedings
	Item 4. Submission of Matters to a Vote of Security Holders
	Item 4A. Executive Officers of the Registrant
PART II
	Item 5. Market for Registrant’s Common Equity 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
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. Controls and Procedures
PART IV
	Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
REPORT OF INDEPENDENT ACCOUNTANTS
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
SIGNATURES
CERTIFICATIONS PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002
EXHIBIT INDEX
Fifth Amendment to Loan Agreement
Fourth Amendment to EXIM Guaranteed Loan Agreement
Employment & Non-Competition Agmt - J Louis Frank
Amended Employment Agreemet - James Devine
Loan Agreement
Subsidiaries of the Company
Consent of PricewaterhouseCoopers LLP
Certification of Bill J. Lam Pursuant to Sec.906
Certification of David W. Sharp - Section 906


PART I
Item 1. and 2.		Business and Properties
Item 3.		Legal Proceedings
Item 4.		Submission of Matters to a Vote of Security Holders
Item 4A.		Executive Officers of the Registrant
PART II
Item 5.		Market for Registrant’s Common Equity 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 Disclosure About Market Risk
Item 8.		Financial Statements and Supplementary Data
Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
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.		Controls and Procedures
PART IV
Item 15.		Exhibits, Financial Statement Schedules and Reports on Form 8-K
Financial Statements
Signatures
Certifications Pursuant to the Sarbanes-Oxley Act of 2002
Exhibit Index



	2002				2001

Fiscal Quarter	High		Low		High		Low

First	$	11.82	$	6.05	$	25.00	$	16.50
Second	$	13.12	$	7.77	$	25.05	$	12.54
Third	$	8.15	$	4.21	$	14.02	$	5.30
Fourth	$	6.14	$	4.62	$	8.59	$	5.43


						Maximum
				Maximum		Pipelay
		Length		Derrick Lift		Diameter
Vessel	Vessel Type	(feet)		(tons)		(inches)

American Horizon	Pipelay/Pipebury		180		—		20
Cajun Horizon	Pipelay/Pipebury		140		—		12
Lone Star Horizon	Pipelay/Pipebury		320		—		48
Gulf Horizon	Pipelay/Pipebury		350		—		42
Brazos Horizon	Pipelay/Pipebury		210		—		36
Pecos Horizon	Pipelay/Pipebury		250		—		36
Sea Horizon	Derrick/Pipelay		360		1,200		36
Pearl Horizon	Diving Support Vessel		184		—		—
Stephaniturm	Diving Support Vessel		230		—		—
Canyon Horizon	Pipebury		330		—		—
Atlantic Horizon	Derrick Barge		420		550		—
Pacific Horizon	Derrick Barge		350		1,000		—
Phoenix Horizon(1)	Derrick/Pipelay		300		250		24


	*The approval and timing of collection of receivables and claims from Pemex may adversely affect our liquidity and financing requirements*


	*Industry volatility may adversely affect results of operations*


	*Operating hazards may increase our operating costs; we have limited insurance coverage*


	*The seasonality of the marine construction industry may adversely affect our operations*


	*Our acquisition growth strategy may require additional financing*


	*We may incur additional expenditures to comply with governmental regulations*


	*Our international operations are subject to significant risks*


	*There are risks associated with our joint venture operations*


Item 4.	*Submission of Matters to a Vote of Security Holders*


	Marine Equipment


	*Environmental Regulation*


Item 3.	*Legal Proceedings*


Item 6.	*Selected Financial Data*


Item 5.	*Market for Registrant’s Common Equity and Related Stockholder Matters*



		Year Ended December 31,

		2002			2001		2000		1999		1998


		(In thousands, except per share data)
INCOME STATEMENT DATA:
Contract revenues		$	283,410		$	272,208	$	160,532	$	89,015	$	119,802
Cost of contract revenues			253,016			237,175		136,146		72,181		91,961

	Gross profit		30,394			35,033		24,386		16,834		27,841
Selling, general and administrative expenses			21,845			13,771		9,401		9,043		8,120
Impairment of property and equipment			9,852			—		—		—		—

	Operating income (loss)		(1,303	)		21,262		14,985		7,791		19,721



			December 31,

			2002			2001

BALANCE SHEET DATA:
Working capital			$	30,385		$	78,055
Property and equipment, net				257,847			221,446
Total assets				420,533			393,584
Long-term debt, net of current maturities				90,062			111,414
Stockholders’ equity				211,675			185,690

OTHER NON-GAAP FINANCIAL DATA:
EBITDA(1)			$	21,677		$	33,991	$	24,498		$	15,533	$	24,206

EBITDA calculation is as follows:
	Net income (loss)		$	(5,549	)	$	10,693	$	6,374		$	1,679	$	12,460
		Extraordinary loss and cumulative effect of accounting change		—			568		(1,381	)		—		—
		Income tax provision (benefit)		(3,079	)		4,817		2,902			1,001		4,485
		Net interest expense		4,494			4,978		7,012			5,279		2,813
		Depreciation and amortization		15,959			12,935		9,591			7,574		4,448
		Non-cash impairment of property and equipment		9,852			—		—			—		—

		EBITDA	$	21,677		$	33,991	$	24,498		$	15,533	$	24,206


Item 7.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations*


Claims included in 2001 revenue		$	42.8
Claims included in 2002 revenue			14.2

	Total claims		57.0
Claims billed to Pemex			(4.0	)

	Claims included in costs in excess of billings as of December 31, 2002	$	53.0


	*Year Ended December 31, 2002 Compared to the Year Ended December 31, 2001*


	*Year Ended December 31, 2001 Compared to the Year Ended December 31, 2000*


	2003		2004		2005		2006		2007		Thereafter

Principal and interest payments on debt	$	12,467	$	42,170	$	25,300	$	15,063	$	3,363	$	11,509
Operating leases		2,684		2,510		2,504		2,341		2,347		2,489

	$	15,151	$	44,680	$	27,804	$	17,404	$	5,710	$	13,998


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 10.	*Directors and Executive Officers of the Registrant*


Item 12.	*Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters*


Item 13.	*Certain Relationships and Related Transactions*


Item 15.	*Exhibits, Financial Statement Schedules and Reports on Form 8-K*


Reports of Independent Accountants			30
Consolidated Balance Sheets as of December 31, 2002 and 2001			32
Consolidated Statements of Operations for the Years Ended December 31, 2002, 2001 and 2000			33
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2002, 2001 and 2000			34
Consolidated Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000			35
Notes to Consolidated Financial Statements			36



		Common Stock				Additional					Treasury Stock						Total
						Paid-in		Retained									Stockholders’
		Shares		Amount		Capital		Earnings			Shares			Amount			Equity

BALANCE, December 31, 1999			19,826	$	9,119	$	87,872	$	6,835			1,025		$	(6,726	)	$	97,100
	Stock options exercised		43		43		271		—			—			—			314
	401(k) contributions in company stock		—		—		102		—			(22	)		145			247
	Net income before cumulative effect of accounting change		—		—		—		4,993			—			—			4,993
	Cumulative effect of accounting change, net of taxes of $743		—		—		—		1,381			—			—			1,381

BALANCE, December 31, 2000			19,869		9,162		88,245		13,209			1,003			(6,581	)		104,035
	Issuance of common stock, net of offering costs		3,800		3,800		62,219		—			—			—			66,019
	Issuance of common stock to purchase assets		250		250		1,355		—			—			—			1,605
	Stock options exercised		325		325		2,682		—			—			—			3,007
	401(k) contributions in company stock		—		—		135		—			(29	)		196			331
	Net income		—		—		—		10,693			—			—			10,693

BALANCE, December 31, 2001			24,244		13,537		154,636		23,902			974			(6,385	)		185,690
	Issuance of common stock, net of offering costs		3,000		3,000		27,844		—			—			—			30,844
	Stock options exercised		46		46		238		—			—			—			284
	401(k) contributions in company stock		—		—		4		—			(62	)		402			406
	Net (loss)		—		—		—		(5,549	)		—			—			(5,549	)

BALANCE, December 31, 2002			27,290	$	16,583	$	182,722	$	18,353			912		$	(5,983	)	$	211,675


1.	Organization and Summary of Significant Accounting Policies


Buildings			15 years
Machinery and equipment			8-10 years
Office furniture and equipment			5 years
Leasehold improvements			3-10 years