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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Form 10-K

Commission file no. 1-13071

12001 North Houston Rosslyn, Houston, Texas 77086

Registrant’s telephone number, including area code:

Securities registered pursuant to Section 12(b)of the Act:

Securities registered pursuant to 12(g) of the Act:

      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.     o

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

      The aggregate market value of the Common Stock of the registrant held by non-affiliates as of June 30, 2003 was $659,857,000. For purposes of this disclosure, common stock held by persons who hold more than 5% of the outstanding voting shares and common stock held by executive officers and directors of the registrant have been excluded in that such persons may be deemed to be “affiliates” as that term is defined under the rules and regulations promulgated under the Securities Act of 1933. This determination of affiliate status is not necessarily a conclusive determination for other purposes. With respect to persons holding more that 5% of our outstanding voting shares and common stock, we have relied upon statement filed by such persons on or prior to June 30, 2003 pursuant to Section 13(d) or 13(g) of the Securities Exchange Act of 1934, as amended.

      Number of shares of the Common Stock of the registrant outstanding as of March 19, 2004: 85,536,605 shares.

DOCUMENTS INCORPORATED BY REFERENCE

      Portions of the Registrant’s definitive proxy statement for the 2004 Annual Meeting of Stockholders to be held in 2004, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2003, are incorporated by reference into Part III.

      The Index to Exhibits begins on page 72.

HANOVER COMPRESSOR COMPANY

TABLE OF CONTENTS

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PART I

SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

      Certain matters discussed in this Annual Report on Form 10-K are “forward-looking statements” intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995 and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements can generally be identified as such because the context of the statement will include words such as we “believe”, “anticipate”, “expect”, “estimate” or words of similar import. Similarly, statements that describe the Company’s future plans, objectives or goals or future revenues or other financial metrics are also forward-looking statements. Such forward-looking statements are subject to certain risks and uncertainties that could cause our actual results to differ materially from those anticipated as of the date of this report. These risks and uncertainties include:

	•	our inability to renew our short-term leases of equipment with our customers so as to fully recoup our cost of the equipment;
	•	a prolonged substantial reduction in oil and natural gas prices, which could cause a decline in the demand for our compression and oil and natural gas production equipment;
	•	reduced profit margins or the loss of market share resulting from competition or the introduction of competing technologies by other companies;
	•	legislative changes or changes in economic or political conditions in the countries in which we do business;
	•	the inherent risks associated with our operations, such as equipment defects, malfunctions and failures and natural disasters;
	•	our inability to implement certain business objectives, such as:

	•	integrating acquired businesses,
	•	implementing our new enterprise resource planning systems,
	•	generating sufficient cash,
	•	accessing capital markets,
	•	refinancing existing or incurring additional indebtedness to fund our business, and
	•	executing our exit and sale strategy with respect to assets classified on our balance sheet as discontinued operations and held for sale;

	•	governmental safety, health, environmental and other regulations, which could require us to make significant expenditures; and
	•	our inability to comply with covenants in our debt agreements and the decreased financial flexibility associated with our substantial debt.

      Other factors in addition to those described in this Form 10-K could also affect our actual results. You should carefully consider the risks and uncertainties described above and those discussed in Item 1 “Business” and in Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Factors That May Affect Our Financial Condition and Future Results,” of this Form 10-K in evaluating our forward-looking statements.

      You should not unduly rely on these forward-looking statements, which speak only as of the date of this Form 10-K. We undertake no obligation to publicly revise any forward-looking statement to reflect circumstances or events after the date of this Form 10-K or to reflect the occurrence of unanticipated events. You should, however, review the factors and risks we describe in the reports we file from time to time with the SEC after the date of this Form 10-K. All forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement.

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General

      Hanover Compressor Company, (“we”, “Hanover”, or the “Company”) a Delaware corporation, together with its subsidiaries, is a global market leader in the full service natural gas compression business and is also a leading provider of service, fabrication and equipment for oil and natural gas processing and transportation applications. We sell and rent this equipment and provide complete operation and maintenance services, including run-time guarantees, for both customer-owned equipment and our fleet of rental equipment. Hanover was founded as a Delaware corporation in 1990, and has been a public company since 1997. Our customers include both major and independent oil and gas producers and distributors as well as national oil and gas companies in the countries in which we operate. Our maintenance business, together with our parts and service business, provides solutions to customers that own their own compression and surface production and processing equipment, but want to outsource their operations. We also fabricate compressor and oil and gas production and processing equipment and provide gas processing and treating, gas measurement and oilfield power generation services, primarily to our domestic and international customers as a complement to our compression services. In addition, through our subsidiary, Belleli Energy S.r.l. (“Belleli”), we provide engineering, procurement and construction services primarily related to the manufacturing of heavy wall reactors for refineries and construction of desalination plants, primarily for use in Europe and the Middle East.

      Substantially all of our assets and operations are owned or conducted by our wholly-owned subsidiary, Hanover Compression Limited Partnership (“HCLP”). In December 2001 and 2002, HCLP and its subsidiaries completed various internal restructuring transactions pursuant to which certain of the domestic subsidiaries of HCLP were merged, directly or indirectly, with and into HCLP.

      We believe that we are currently the largest natural gas compression company in the United States on the basis of aggregate rental horsepower, with approximately 6,071 rental units in the United States having an aggregate capacity of approximately 2,588,000 horsepower at December 31, 2003. In addition, we estimate that we are one of the largest providers of compression services in the Latin American and Canadian markets, operating approximately 835 units internationally with approximately 925,000 horsepower at December 31, 2003. As of December 31, 2003, approximately 74% of our natural gas compression horsepower was located in the United States and approximately 26% was located elsewhere, primarily in Latin America and Canada.

      Our products and services are essential to the production, processing, transportation and storage of natural gas and are provided primarily to energy producers and distributors of oil and natural gas. Our decentralized operating structure, technically experienced personnel and high-quality compressor fleet have allowed us to successfully provide reliable and timely customer service.

Industry trends

      We compete primarily in the market for transportable natural gas compression units of up to 4,500 horsepower. The market for rental compression has experienced significant growth over the past decade. Although recently we have not experienced any significant growth in domestic rentals or purchases of equipment and services by our customers, which we believe is primarily a result of the lack of a significant increase in U.S. natural gas production levels, we believe that the U.S. gas compression market will continue to grow due to the increased demand for natural gas, the continued aging of the natural gas reserve base and the attendant decline of wellhead pressures, the discovery of new reserves and the continuing interest in outsourcing compression by independent producers. However, because the majority of oil and gas reserves are located outside of the United States, we believe that international markets will be a primary source of our growth opportunities in the gas compression market in the years to come.

      As of December 31, 2003, the rental portion of the domestic gas compression market was estimated by industry sources to be approximately 5.0 million horsepower, which we estimate accounts for approximately 30% of aggregate U.S. horsepower, having doubled since 1996. Growth of the rental

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Recent Events

      Securities Class Actions. On October 23, 2003, we entered into a Stipulation of Settlement, which settled all of the claims underlying the putative securities class action, the putative ERISA class action and the shareholder derivative actions which were filed against the Company and are more fully described in Item 3 “Legal Proceedings” in this Form 10-K. The terms of the settlement provide for us to: (1) make a cash payment of approximately $30 million (of which $26.7 million was funded by payments from Hanover’s directors and officers insurance carriers), (2) issue 2.5 million shares of our common stock, and (3) issue a contingent note with a principal amount of $6.7 million. The note is payable, together with accrued interest, on March 31, 2007 but will be extinguished (with no money owing under it) if our common stock trades at or above the average price of $12.25 per share for 15 consecutive trading days at any time between March 31, 2004 and March 31, 2007. In addition, upon the occurrence of a change of control that involves us, if the change of control or shareholder approval of the change of control occurs before February 9, 2005, which is twelve months after final court approval of the settlement, we will be obligated to contribute an additional $3 million to the settlement fund.

      As part of the settlement, we have also agreed to implement corporate governance enhancements, including allowing shareholders owning more than 1% but less than 10% of our outstanding common stock to participate in the process to appoint two independent directors to our board of directors (pursuant to which on February 4, 2004 we appointed Margaret K. Dorman and Stephen M. Pazuk to our board of directors) and making certain changes to our code of conduct.

      GKH Investments, L.P. and GKH Private Limited (collectively “GKH”), which, as of December 31, 2003, together owned approximately 10% of our outstanding common stock and which sold shares in our March 2001 secondary offering of common stock, are parties to the settlement and have agreed to settle claims against them that arise out of that offering as well as other potential securities, ERISA, and derivative claims. The terms of the settlement provide for GKH to transfer 2.5 million shares of our common stock from their holdings or from other sources to the settlement fund.

      We received a letter on March 11, 2004 from the administrative trustee of the GKH Liquidating Trust indicating it and one of its affiliates had decided to distribute 5.8 million shares of the 8.3 million shares of Hanover common stock owned by the GKH Liquidating Trust (formerly held by GKH) and its affiliate to the relevant beneficiaries. The remaining 2.5 million shares held by GKH will be paid as part of the global shareholder litigation settlement.

      On February 9, 2004, the United States District Court for the Southern District of Texas entered three Orders and Final Judgments, approving the settlement on the terms agreed upon in the Stipulation of Settlement with respect to all of the claims described above. The court also entered an Order and Final Judgment approving the plans of allocation with respect to each action, as well as an Order and Final

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      SEC Settlement. In December 2003, we entered into a settlement with the Securities and Exchange Commission (“SEC”), concluding the previously disclosed SEC investigation into the transactions underlying, and other matters relating to, the restatement of our financial statements for fiscal years 1999, 2000 and 2001. Without admitting or denying any of the SEC’s findings, we consented to the entry of a cease and desist order requiring future compliance with certain periodic reporting, record keeping and internal control provisions of the securities laws. The settlement did not impose any monetary penalty on us and required no additional restatements of our historical financial statements.

      Debt Refinancings. In December 2003, we issued under our shelf registration statement $200.0 million aggregate principal amount of our 8.625% Senior Notes due 2010, which are fully and unconditionally guaranteed on a senior subordinated basis by HCLP. The net proceeds from this offering were used to repay the outstanding indebtedness and minority interest obligations of $194.0 million and $6.0 million, respectively, under our 1999A equipment lease that was to expire in June 2004.

      Also in December 2003, we issued under our shelf registration statement $143.8 million aggregate principal amount of our 4.75% Convertible Senior Notes due 2014. We may redeem these convertible notes beginning in 2011 under certain circumstances. The convertible notes are convertible into shares of our common stock at an initial conversion rate of 66.6667 shares of our common stock per $1,000 principal amount of the convertible notes (subject to adjustment in certain events) at any time prior to the stated maturity of the convertible notes or the redemption or repurchase of the convertible notes by us. The net proceeds from this offering were used to repay a portion of the outstanding indebtedness under our bank credit facility.

      New Bank Credit Facility. Effective December 15, 2003, we entered into a new $350 million bank credit facility having a maturity date of December 29, 2006 and made conforming amendments related to the compression equipment lease obligations that we entered into in 2000. Our prior $350 million bank credit facility that was scheduled to mature in November 2004, was terminated upon closing of the new facility. The new bank credit facility modified certain covenants that were contained in the prior facility and eliminated certain covenants entirely. The new agreement prohibits us (without the lenders’ prior approval) from declaring or paying any dividend (other than dividends payable solely in our common stock or in options, warrants or rights to purchase such common stock) on, or making similar payments with respect to, our capital stock. The new agreement clarifies and provides certain thresholds with respect to our ability to make investments in our foreign subsidiaries. In addition, under the new agreement, we granted the lenders a security interest in the inventory, equipment and certain other property of Hanover and its domestic subsidiaries (with certain exceptions), and pledged 66% of the equity interest in certain of our foreign subsidiaries. We believe that this new bank credit facility will provide flexibility in accessing the capacity under the facility to support our short-term liquidity needs.

      Panoche/ Gates Dispositions. In May 2003, we announced that we had agreed to sell our 49% membership interest in Wellhead Power Panoche, LLC (“Panoche”) and our 92.5% membership interest in Wellhead Power Gates, LLC (“Gates”) to Hal Dittmer and Fresno Power Investors Limited Partnership, who owned the remaining interests in Panoche and Gates. Panoche and Gates own gas-fired peaking power plants of 49 megawatts and 46 megawatts, respectively. The Panoche transaction closed in June 2003 and the Gates transaction closed in September 2003. Total consideration for the transactions was approximately $27.2 million consisting of approximately $6.4 million in cash, $2.8 million in notes that mature in May 2004, a $0.5 million note that matures in September 2005 and the release of our obligations under a capital lease from GE Capital to Gates that had an outstanding balance of

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      PIGAP II Restructuring and Our Zero Coupon Subordinated Notes due March 31, 2007. On May 14, 2003, we entered into an agreement with Schlumberger Limited to terminate our right to put our interest in the PIGAP II joint venture to Schlumberger. As a result, we retained our interest in PIGAP II. We had previously given notice of our intent to exercise the PIGAP put in January 2003. PIGAP II is a joint venture, currently owned 70% by a subsidiary of Williams Companies Inc. and 30% by Hanover, which operates a natural gas compression facility in Venezuela. The natural gas processed by PIGAP II is re-injected into oil reservoirs for enhanced oil recovery.

      Also on May 14, 2003, we agreed with Schlumberger Surenco, an affiliate of Schlumberger, to the modification of the repayment terms of a $58.0 million obligation that was accrued as a contingent liability on our balance sheet since the acquisition of Production Operators Corporation (“POC”) and was associated with the PIGAP II joint venture. The obligation was converted into a non-recourse promissory note (the “PIGAP Note”) payable by Hanover Cayman Limited, our indirect wholly-owned consolidated subsidiary, with a 6% interest rate compounding semi-annually until maturity in December 2053. In October 2003, the PIGAP II joint venture closed on the project’s financing and distributed approximately $78.5 million to Hanover, of which approximately $59.9 million was used to repay the PIGAP Note.

      In connection with the agreement to terminate our right to put our interest in PIGAP II back to Schlumberger, we also agreed with Schlumberger to restructure the $150 million subordinated note that Schlumberger received from Hanover in August 2001 as part of the purchase price for our acquisition of POC’s natural gas compression business, ownership interest in certain joint venture projects in South America (including PIGAP II), and related assets. As of March 31, 2003, the date from which the interest rate was adjusted, the $150 million subordinated note had an outstanding principal balance of approximately $171 million, including accrued interest. We restructured the $150 million subordinated note as our Zero Coupon Subordinated Notes due March 31, 2007, which notes were issued to Schlumberger and were sold by Schlumberger in a registered public offering in December 2003. Original issue discount accretes under the zero coupon notes at a rate of 11.0% per annum for their remaining life, up to a total principal amount of $262.6 million payable at maturity. The notes will accrue additional interest at a rate of 2.0% per annum upon the occurrence and during the continuance of an event of default under the notes. The notes will also accrue additional interest at a rate of 3.0% per annum if our consolidated leverage ratio, as defined in the indenture governing the notes, exceeds 5.18 to 1.0 as of the end of any two consecutive fiscal quarters. Notwithstanding the preceding, in no event will the total additional interest accruing on the notes exceed 3.0% per annum if both of the previously mentioned circumstances occur. The notes also contain a covenant that limits our ability to incur additional indebtedness if our consolidated leverage ratio exceeds 5.6 to 1.0, subject to certain exceptions.

      Belleli Acquisition. In 2002, we increased our ownership of Belleli to 51% from 20.3% by converting $13.4 million in loans, together with approximately $3.2 million in accrued interest thereon, into additional equity ownership and in November 2002 began consolidating the results of Belleli’s operations. Belleli has three manufacturing facilities, one in Mantova, Italy and two in the United Arab Emirates (Jebel Ali and Hamriyah). During 2002, we also purchased certain operating assets used by Belleli for approximately $22.4 million from a bankruptcy estate of Belleli’s former parent and leased these assets to Belleli for approximately $1.2 million per year, for a term of seven years.

      In connection with our increase in ownership in 2002, we entered into an agreement with the minority owner of Belleli that provided the minority owner the right, until June 30, 2003, to purchase our interest for an amount that approximated our investment in Belleli. The agreement also provided us with the right, beginning in July 2003, to purchase the minority owner’s interest in Belleli. In addition, the minority owner historically had been unwilling to provide its proportionate share of capital to Belleli. We believed that our ability to maximize value would be enhanced if we were able to exert greater control through the exercise of our purchase right. Thus, in August 2003, we exercised our option to acquire the remaining 49% interest

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      As a result of the war in Iraq, the strengthening of the Euro and generally unfavorable economic conditions, we believe that the estimated fair value of Belleli declined significantly during 2003. Upon gaining complete control of Belleli and assessing our long-term growth strategy, we determined that these general factors in combination with the specific economic factors impacting Belleli had significantly and adversely impacted the timing and amount of the future cash flows that we expected Belleli to generate. We currently do not expect to realize our original growth expectations for Belleli in the timeframe that we originally forecasted.

      During the performance of our annual goodwill impairment review in the fourth quarter of 2003, we determined the present value of Belleli’s expected future cash flows was less than our carrying value of Belleli. This resulted in a full impairment charge for the $35.5 million in goodwill associated with Belleli. Upon further analysis, it was determined that the factors resulting in the goodwill impairment charge were also present during the third quarter of 2003 and that the exercise of our purchase option in the third quarter of 2003 and the presence of such factors should have resulted in an interim goodwill impairment test under SFAS 142 and an impairment charge at that time. We have adjusted our third quarter results accordingly.

Industry Overview

Gas Compression

      Typically, compression is required at several intervals of the natural gas production cycle: at the wellhead, at the gathering lines, into and out of gas processing facilities, into and out of storage and throughout the transportation systems.

      Over the life of an oil or gas well, natural reservoir pressure and deliverability typically decline as reserves are produced. As the natural reservoir pressure of the well declines below the line pressure of the gas gathering or pipeline system used to transport the gas to market, gas no longer flows naturally into the pipeline. It is at this time that compression equipment is applied to economically boost the well’s production levels and allow gas to be brought to market.

      In addition to such wellhead and gas field gathering activities, natural gas compressors are used in a number of other applications, most of which are intended to enhance the productivity of oil and gas wells, gas transportation lines and processing plants. Compressors are used to increase the efficiency of a low capacity gas field by providing a central compression point from which the gas can be removed and injected into a pipeline for transmission to facilities for further processing. As gas is transported through a pipeline, compression equipment is applied to allow the gas to continue to flow in the pipeline to its destination. Additionally, compressors are used to re-inject associated gas to lift liquid hydrocarbons and thereby increase the rate of crude oil production from oil and gas wells. Furthermore, compression enables gas to be stored in underground storage reservoirs for subsequent extraction during periods of peak demand. Finally, compressors are often used in combination with oil and gas production equipment to process and refine oil and gas into higher value added and more marketable energy sources, as well as used in connection with compressed natural gas vehicle fueling facilities providing an alternative to gasoline.

      Changing well and pipeline pressures and conditions over the life of a well often require producers to reconfigure or change their compressor units to optimize the well production or pipeline efficiency. Due to the technical nature of the equipment, a dedicated local parts inventory, a diversified fleet of natural gas compressors and a highly trained staff of field service personnel are necessary to perform such functions in the most economic manner. These requirements, however, have typically proven to be an extremely inefficient use of capital and manpower for independent natural gas producers and have caused producers,

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      The advent of rental and contract compression roughly 40 years ago made it possible for natural gas producers, transporters and processors to improve the efficiency and financial performance of their operations. We believe compressors leased from specialists generally have a higher rate of mechanical reliability and typically generate greater productivity than those owned by oil and gas operators. Furthermore, because compression needs of a well change over time, outsourcing of compression equipment enables an oil and gas producer to better match variable compression requirements to the production needs throughout the life of the well. Also, certain major domestic oil companies are seeking to streamline their operations and reduce their capital expenditures and other costs. To this end, they have sold certain domestic energy reserves to independent energy producers and are outsourcing facets of their operations. We believe that such initiatives are likely to contribute to increased rentals of compression equipment.

      Natural gas compressor fabrication involves the design, fabrication and sale of compressors to meet the unique specifications dictated by the well pressure, production characteristics and the particular applications for which compression is sought. Compressor fabrication is essentially an assembly operation in which an engine, compressor, control panel, cooler and necessary piping are attached to a frame called a “skid.” A fabricator typically purchases the various compressor components from third-party manufacturers, but employs its own engineers and design and labor force.

      In order to meet customers’ needs, gas compressor fabricators typically offer a variety of services to their customers, including:

	•	engineering, fabrication and assembly of the compressor unit;
	•	installation and testing of the unit;
	•	ongoing performance review to assess the need for a change in compression; and
	•	periodic maintenance and replacement parts supply.

Production and Processing Equipment

      Crude oil and natural gas are generally not marketable as produced at the wellhead and must be processed before they can be transported to market. Production and processing equipment is used to separate and treat oil and gas as it is produced to achieve a marketable quality of product. Production processing typically involves the separation of oil and gas and the removal of contaminants. The end result is “pipeline,” or “sales” quality oil and gas. Further processing or refining is almost always required before oil or gas is suitable for use as fuel or feedstock for petrochemical production. Production processing normally takes place in the “upstream” market, while refining and petrochemical production is referred to as the “downstream” market.

      Wellhead or upstream production and processing equipment includes a wide and diverse range of products. We sell “standard” production equipment primarily into U.S. markets, which is used for processing wellhead production from onshore or shallow-water offshore platform production. In addition, we sell custom-engineered, built-to-specification production and processing equipment, which typically consists of much larger equipment packages than standard equipment, and is generally used in much larger scale production operations. These large projects tend to be in remote areas, such as deepwater offshore sites, and in developing countries with limited oil and gas industry infrastructure.

      The standard production equipment market tends to be somewhat commoditized, with sales following general industry trends. Equipment can be built for inventory based on historical product mix and predicted industry activity. The custom equipment market is driven by global economic and political trends, and the type of equipment that is purchased can vary significantly. Technology, engineering capabilities, project management and quality control standards are the key drivers in the custom equipment market.

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      In addition, through our ownership of Belleli, we provide engineering, procurement and construction services primarily related to the manufacturing of heavy wall reactors for refineries and construction of desalination plants, primarily for use in Europe and the Middle East.

Market Conditions

      We believe that the most fundamental force driving the demand for gas compression and production equipment is the growing global consumption of natural gas. As more gas is consumed, the demand for compression and production equipment increases. In addition, we expect the demand for liquefied natural gas, compressed natural gas and liquefied petroleum gas to continue to increase and result in additional demand for our compression and production equipment and related services.

      Although natural gas has historically been a more significant source of energy in the United States than in the rest of the world, we believe that aggregate foreign natural gas consumption has recently grown. Despite this growth in energy demand, most non-U.S. energy markets have historically lacked the infrastructure necessary to transport natural gas to local markets and natural gas historically has been flared at the wellhead. Given recent environmental legislation and the construction of numerous natural gas-fueled power plants built to meet international energy demand, we believe that international compression markets are experiencing growth.

      We believe that natural gas is considered to be the “fuel of the future” because it provides the best mix of environmental soundness, economy and availability of any energy source. Rising worldwide energy demand, environmental considerations, the further development of the natural gas pipeline infrastructure and the increasing use of natural gas as a fuel source in oilfield power generation are the principal reasons for this growth.

      While gas compression and production and processing equipment typically must be engineered to high specifications to meet demanding and unique customer specifications, the fundamental technology of such equipment has been stable and has not been subject to significant technological change.

Business Segments

      Our revenues and income are derived from five business segments:

	•	Domestic rentals. Our domestic rentals segment primarily provides natural gas compression and production and processing equipment rental and maintenance services to meet specific customer requirements on Hanover-owned assets located within the United States.
	•	International rentals. Our international rentals segment provides substantially the same services as our domestic rentals segment except it services locations outside the United States.
	•	Compressor and accessory fabrication. Our compressor and accessory fabrication segment involves the design, fabrication and sale of natural gas compression units and accessories to meet unique customer specifications.
	•	Production and processing equipment fabrication. Our production and processing equipment fabrication segment includes the design, fabrication and sale of equipment used in the production and treating of crude oil and natural gas; and the engineering, procurement and manufacturing of heavy wall reactors for refineries and the construction of desalination plants.
	•	Parts, service and used equipment. Our parts, service and used equipment segment provides a full range of services to support the surface production needs of customers, from installation and normal maintenance and services to full operation of a customer’s owned assets and surface equipment as well as sales of used equipment.

      The domestic and international compression rentals segments have operations primarily in the United States, Canada and South America. For financial data relating to our business segments and financial data relating to the amount or percentage of revenue contributed by any class of similar products or services

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Compression Rentals, Maintenance Services and Compressor and Accessory Fabrication

      We provide our customers with a full range of compressor and associated equipment sales, rental, maintenance and contract compression services. As of December 31, 2003, our compressor fleet consisted of approximately 6,906 units, ranging from 8 to 4,450 horsepower per unit. The size, type and geographic diversity of this rental fleet enable us to provide our customers with a range of compression units that can serve a wide variety of applications and to select the correct equipment for the job, rather than trying to “fit” the job to our fleet of equipment.

      We base our gas compressor rental rates on several factors, including the cost and size of the equipment, the type and complexity of service desired by the customer, the length of the contract and the inclusion of any other desired services, such as installation, transportation and the degree of daily operation. In early 2003, we began to selectively introduce price increases for our domestic compression rental business. Such price increases, along with a slight improvement in market conditions, resulted in a 3% increase in revenue from our domestic rentals business in the six months ended December 31, 2003 as compared to the six months ended December 31, 2002. Substantially all of our units are operated pursuant to “contract compression” or “rental with full maintenance” agreements under which we perform all maintenance and repairs on such units while under contract. In the U.S. onshore market, compression rental fleet units are generally leased under contract with minimum terms of six months to two years, which convert to month-to-month at the end of the stipulated minimum period. Historically, the majority of our customers have extended the length of their contracts, on a month-to-month basis, well beyond the initial term. Typically, our compression rental units used in offshore and international applications carry substantially longer lease terms than those for onshore domestic applications.

      An essential element of our success is our ability to provide compression services to customers with contractually committed compressor run-times of between 95% and 98%. Historically, our incidence of failing to meet run-time commitments (the penalty for which is paid in credits to the customer’s account) has been insignificant, due largely to our rigorous preventive maintenance program and extensive field service network that permits us to promptly address maintenance requirements. Our team of experienced maintenance personnel performs our rental compression maintenance services both at our facilities and in the field. Such maintenance facilities are situated in close proximity to actual rental fleet deployment to permit superior service response times.

      All rental fleet units are serviced at manufacturers’ recommended maintenance intervals, modified as required by the peculiar characteristics of each job and the actual operating experience of each compressor unit. Prior to the conclusion of any rental job, our field management evaluates the condition of the equipment and, where practical, corrects any problems before the equipment is shipped out from the job site. Although natural gas compressors generally do not suffer significant technological obsolescence, they do require routine maintenance and periodic refurbishing to prolong their useful life. Routine maintenance includes alignment, compression checks and other parametric checks that indicate a change in the condition of the equipment. In addition, oil and wear-particle analysis is performed on all units on an ongoing scheduled basis and prior to their redeployment at specific compression rental jobs. Overhauls are done on a condition-based interval instead of a time-based schedule. In our experience, these rigorous procedures maximize component life and unit availability and minimize avoidable downtime. Typically, we overhaul each rental compressor unit for general refurbishment every 36 to 48 months and anticipate performing a comprehensive overhaul of each rental compressor unit every 60 to 72 months. This maintenance program has provided us with a highly reliable fleet of compressors in excellent condition.

      Our field service mechanics provide all operating and maintenance services for our compression units leased on a contract compression or full maintenance basis and are on-call 24 hours a day. Those field

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      We believe our competitive position has benefited from the managerial parity that our sales and field service organizations enjoy within the company, enabling these two vital organizations to work together in a highly coordinated fashion in order to deliver maximum customer service, responsiveness and reliability. The foundation for our successful field operations effort is the experience and responsiveness of our compressor rental field service and shop staff of compressor mechanics. Our field service mechanics are coordinated and supported by regional operations managers who have supervisory responsibility for specific geographic areas.

      Our compressor and accessory fabrication operations design, engineer and assemble compression units and accessories for sale to third parties as well as for placement in our compressor rental fleet. As of December 31, 2003, we had a compressor unit fabrication backlog for sale to third parties of $28.2 million compared to $29.8 million at December 31, 2002. Substantially all of our compressor and accessory fabrication backlog is expected to be produced within a three-month to six-month period. In general, units to be sold to third parties are assembled according to each customer’s specifications and sold on a turnkey basis. We acquire major components for these compressor units from third-party suppliers.

Compressor Rental Fleet

      The size and horsepower of our compressor rental fleet owned or operated under lease on December 31, 2003 is summarized in the following table.

     Production and Processing Equipment Fabrication

      Through our production and processing equipment fabrication division, we design, engineer, fabricate, sell and rent a broad range of oil and gas production equipment designed to heat, separate, dehydrate and measure crude oil and natural gas. Our product line includes line heaters, oil and gas separators, glycol dehydration units and skid-mounted production packages designed for both onshore and offshore production facilities. We also purchase and recondition used production and processing equipment that is then sold or rented and generally maintain standard product inventories to meet most customers’ rapid response requirements and minimize customer downtime. As of December 31, 2003, we had a production and processing equipment fabrication backlog of $18.1 million (excluding Belleli’s backlog of $106.7 million at December 31, 2003) compared to $56.0 million at December 31, 2002. Substantially all of our production equipment backlog is expected to be produced within a three to thirty-six month period. In addition, through our subsidiary, Belleli, we provide engineering, procurement and construction services

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     Parts, Service and Used Equipment

      We purchase and recondition used gas compression units, oilfield power generation and treating facilities and production equipment that is then sold or rented to customers. In addition, we often provide contract operations and related services for customers that prefer to own their production, gas treating and oilfield power generation or compression equipment. We believe that we are particularly well qualified to provide these services because our highly experienced operating personnel have access to the full range of our compression rental, production processing equipment and oilfield power generation equipment and facilities. As customers look to us to provide an ever-widening array of outsourced services, we will continue to build our core business with emerging business opportunities, such as turnkey gas treatment, gas measurement and oilfield-related power generation sales and services. We maintain parts inventories for our own use and to meet our customers’ needs. As of December 31, 2003, we had approximately $114.1 million in parts and supplies inventories.

     Sources and Availability of Raw Materials

      Our fabrication operations consist of fabricating compressor and production and processing equipment from components and subassemblies, most of which we acquire from a wide range of vendors. These components represent a significant portion of the cost of our compressor and production and processing equipment products. Although our products are generally shipped within 180 days following their order date, increases in raw material costs cannot always be offset by increases in our products’ sales prices. We believe that all materials and components are readily available from multiple suppliers at competitive prices.

     Market and Customers

      Our global customer base consists of U.S. and international companies engaged in all aspects of the oil and gas industry, including major integrated oil and gas companies, national oil and gas companies, large and small independent producers and natural gas processors, gatherers and pipelines. Additionally, we have negotiated strategic alliances or preferred vendor relationships with key customers pursuant to which we receive preferential consideration in customer compressor and oil and gas production equipment procurement decisions in exchange for providing enhanced product availability, product support, automated procurement practices and limited pricing concessions. No individual customer accounted for more than 10% of our consolidated revenues during 2003, 2002 or 2001.

      Our compressor leasing activities are located throughout the continental United States, internationally and in offshore operations. International locations include Argentina, Barbados, Egypt, United Arab Emirates, Equatorial Guinea, India, Venezuela, Colombia, Trinidad, Bolivia, Brazil, Mexico, Peru, Pakistan, Indonesia, Nigeria, United Kingdom, Russia and Canada. In addition, we have representative offices in the Netherlands and the Cayman Islands. As of December 31, 2003, equipment representing approximately 26% of our compressor rental fleet horsepower was being used in international applications.

     Sales and Marketing

      Our salespeople pursue the rental and sales market for compressors and production equipment and other products in their respective territories. Each salesperson is assigned a customer list on the basis of the experience and personal relationships of the salesperson and the individual service requirements of the customer. This customer and relationship-focused strategy is communicated through frequent direct contact, technical presentations, print literature, print advertising and direct mail. Our advertising and promotion strategy is a concentrated approach, tailoring specific messages into a very focused presentation methodology.

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      Additionally, our salespeople coordinate with each other to effectively pursue customers who operate in multiple regions. The salespeople maintain contact with our operations personnel in order to promptly respond to and satisfy customer needs. Our sales efforts concentrate on demonstrating our commitment to enhancing the customer’s cash flow through superior product design, fabrication, installation, customer service and after-market support.

      Upon receipt of a request for proposal or bid by a customer, we assign a team of sales, operations and engineering personnel to analyze the application and prepare a quotation, including selection of the equipment, pricing and delivery date. The quotation is then delivered to the customer and, if we are selected as the vendor, final terms are agreed upon and a contract or purchase order is executed. Our engineering and operations personnel also often provide assistance on complex compressor applications, field operations issues or equipment modifications.

     Competition

      We believe that we are currently the largest natural gas compression company in the United States on the basis of aggregate rental horsepower. However, the natural gas compression services and fabrication business is highly competitive. Overall, we experience considerable competition from companies who may be able to more quickly adapt to changes within our industry and changes in economic conditions as a whole, more readily take advantage of available opportunities and adopt more aggressive pricing policies.

      Because the business is capital intensive, our ability to take advantage of growth opportunities is limited by our ability to raise capital. To the extent that any of our competitors have a lower cost of capital or have greater access to capital than we do, they may be able to compete more effectively, which may allow them to more readily take advantage of available opportunities.

      Compressor industry participants can achieve significant advantages through increased size and geographic breadth. As the number of rental units increases in a rental fleet, the number of sales, engineering, administrative and maintenance personnel required does not increase proportionately.

      One of the significant cost items in the compressor rental business is the amount of inventory required to service rental units. Each rental company must maintain a minimum amount of inventory to remain competitive. As the size of the rental fleet increases, the required amount of inventory does not increase in the same proportion, thus providing economic efficiencies. The larger rental fleet companies can generate cost savings through improved purchasing power and vendor support.

      We believe that we compete effectively on the basis of price, customer service, and flexibility in meeting customer needs and quality and reliability of our compressors and related services. A few major fabricators, some of whom also compete with us in the compressor rental business, continue to be aggressive competitors in the compressor fabrication business. In our production and processing equipment business, we have different competitors in the standard and custom engineered equipment markets. Competitors in the standard equipment market include several large companies and a large number of small, regional fabricators. Competition in the standard equipment market is generally based upon price, availability, the ability to provide integrated projects and level of product support after the sale. Our competition in the custom engineered market usually consists of larger companies. Increasingly, the ability to fabricate these large systems near to the point of end-use is a major competitive issue.

     Government Regulation

      We are subject to various federal, state, local and foreign laws and regulations relating to the environment, health and safety, including regulations and permitting for air emissions, wastewater and stormwater discharges and waste handling and disposal activities. From time to time as part of the regular overall evaluation of our operations, including newly acquired operations, we apply for or amend facility permits with respect to stormwater or wastewater discharges, waste handling, or air emissions relating to manufacturing activities or equipment operations, which subjects us to new or revised permitting conditions that may be onerous or costly to comply with. In addition, certain of our customer service arrangements

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      In connection with our due diligence investigation of potential new properties for acquisition, we typically perform an evaluation to identify potentially significant environmental issues and take measures to have such issues addressed by the seller or ourselves, as appropriate under the circumstances. We cannot be certain, however, that all such possible environmental issues will be identified and fully addressed prior to our acquisition of new properties. Moreover, the handling of petroleum products and other regulated substances is a normal part of our operations and we have experienced occasional minor spills or incidental leakages in connection with our operations. As part of the regular overall evaluation of our operations, including newly acquired facilities, we assess the compliance and permitting status of these operations and facilities with applicable environmental laws and regulations and seek to address identified issues in accordance with applicable law.

      The Comprehensive Environmental Response, Compensation and Liability Act, also known as “CERCLA” or the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the facility or disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances. Under CERCLA and similar state laws, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. Furthermore, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.

      The Resource Conservation and Recovery Act (“RCRA”) and regulations promulgated by it govern the generation, storage, transfer and disposal of hazardous wastes. We must comply with RCRA regulations for any of our operations that involve the generation, management or disposal of hazardous wastes (such as painting activities or the use of solvents). In addition, to the extent we operate underground tanks on behalf of specific customers, such operations may be regulated under RCRA. We believe we are in substantial compliance with RCRA and are not aware of any current claims against us alleging RCRA violations. We cannot provide any assurance, however, that we will not receive such notices of potential liability in the future.

      We currently own or lease, and in the past have owned or leased, a number of properties that have been used in support of our operations for a number of years. Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons, hazardous substances, or other regulated wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such materials have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons, hazardous substances or other regulated wastes was not under our control. These properties and the materials released or disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove or remediate historical property contamination, or to perform remedial plugging or pit closure operations to prevent future contamination. We are not currently under any order requiring that we undertake or pay for any clean-up activities, nor are we aware of any current environmental claims by the government or private parties against us demanding remedial action or alleging that we are liable for remedial costs already incurred. However, we cannot provide any assurance that we will not receive any such claims in the future.

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      The Federal Water Pollution Control Act of 1972, also known as the “Clean Water Act,” and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The EPA also has adopted regulations requiring covered industrial operators to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans. We believe that we are in substantial compliance with requirements under the Clean Water Act.

      The Clean Air Act restricts the emission of air pollutants from many sources, including compressors and operational support facilities. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to remain in compliance. In addition, certain states have or are considering and the federal government has recently passed more stringent air emission controls on off-road engines. These laws and regulations may affect the costs of our operations.

      On June 25, 1999, we notified the Air Quality Bureau of the Environmental Protection Division, New Mexico Environment Department, of potential violations of regulatory and permitting requirements. The potential violations included failure to conduct required performance tests, failure to file required notices and failure to pay fees for compressor units located on sites for more than one year. We promptly paid the required fees and corrected the potential violations. On June 12, 2001, after the potential violations had been corrected, the Director of the Division issued a compliance order to us in connection with the potential violations. The compliance order assessed a civil penalty of $15,000 per day per alleged regulatory violation and permit; no total penalty amount was proposed in the compliance order. On October 3, 2003, the Division notified us that the total proposed penalty would be $759,072. However, since the alleged violations had been self-disclosed, that amount was reduced to $189,768. We have responded to the penalty assessment, challenging some of the calculations, and have proposed an alternative settlement amount. We are currently negotiating with the New Mexico Environment Department on the method of calculation and proposed settlement amounts, and the issue is not yet resolved. A Stipulated Motion for Extension of Time to File Answer has been filed which extends the deadline for filing our response to March 22, 2004.

      We believe that we are currently in substantial compliance with environmental laws and regulations and that the phasing-in of recent more stringent air emission controls on off-road engines and other known regulatory requirements in the time periods currently contemplated by such laws and regulations will not have a material adverse effect on our business, consolidated financial condition, results of operations and cash flows. It is possible that stricter environmental laws and regulations may be imposed in the future, such as more stringent air emission requirements or proposals to make currently non-hazardous wastes subject to more stringent and costly handling, disposal and clean-up requirements. While we may be able to pass on the additional costs of complying with such laws to our customers, there can be no assurance that attempts to do so will be successful. Accordingly, new laws or regulations or amendments to existing laws or regulations might require us to undertake significant capital expenditures and otherwise have a material adverse effect on our business, consolidated financial condition, results of operations and cash flows.

      Our operations outside the United States are potentially subject to similar foreign governmental controls and restrictions pertaining to the environment. We believe our operations are in substantial compliance with existing foreign governmental controls and restrictions and that compliance with these foreign controls and restrictions has not had a material adverse effect on our operations. We cannot provide any assurance, however, that we will not incur significant costs to comply with these foreign controls and restrictions in the future.

International Operations

      We operate in many different geographic markets, some of which are outside the United States. At December 31, 2003, of the approximately 925,000 horsepower of compression we had deployed

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	•	difficulties in managing international operations;
	•	unexpected changes in regulatory requirements;
	•	tariffs and other trade barriers which may restrict our ability to enter into new markets;
	•	changes in political conditions;
	•	potentially adverse tax consequences;
	•	restrictions on repatriation of earnings or expropriation of property;
	•	the burden of complying with foreign laws; and
	•	fluctuations in currency exchange rates and the value of the U.S. dollar.

      Our future plans involve expanding our business in international markets where we currently do not conduct business. Our decentralized management structure and the risks inherent in new business ventures, especially in international markets where local customs, laws and business procedures present special challenges, may affect our ability to be successful in these ventures or avoid losses which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

      We have significant operations that expose us to currency risk in Argentina and Venezuela. To mitigate that risk, the majority of our existing contracts provide that we receive payment in or based on U.S. dollars rather than Argentine pesos and Venezuelan bolivars, thus reducing our exposure to fluctuations in their value.

      Although the operating environment in Argentina has since stabilized, in January 2002, Argentina devalued its peso against the U.S. dollar and imposed significant restrictions on fund transfers internally and outside the country. In addition, the Argentine government enacted regulations to temporarily prohibit enforcement of contracts with exchange rate-based purchase price adjustments. Instead, payment under such contracts could either be made at an exchange rate negotiated by the parties or, if no such agreement were reached, a preliminary payment could be made based on a one dollar to one peso equivalent pending a final agreement. The Argentine government also required the parties to such contracts to renegotiate the price terms within 180 business days of the devaluation. We have renegotiated all of our agreements in Argentina. As a result of these negotiations, we received approximately $11.2 million in reimbursements in 2002 and $0.7 million in 2003. For the year ended December 31, 2003, our Argentine operations represented approximately 5% of our revenue and 9% of our gross profit. During the years ended December 31, 2003 and 2002, we recorded an exchange gain of approximately $0.5 million and an exchange loss of approximately $9.9 million, respectively, for assets exposed to currency translation in Argentina. The economic situation in Argentina is subject to change. To the extent that the situation in Argentina deteriorates, exchange controls continue in place and the value of the peso against the dollar is reduced further, our results of operations in Argentina could be materially and adversely affected which could result in reductions in our net income.

      In December 2002, opponents of Venezuelan President Hugo Chávez initiated a country-wide strike by workers of the national oil company in Venezuela. This strike, a two-month walkout, had a significant negative impact on Venezuela’s economy and temporarily shut down a substantial portion of Venezuela’s oil industry. As a result of the strike, Venezuela’s oil production has dropped substantially. In addition, exchange controls have been put in place which put limitations on the amount of Venezuelan currency that can be exchanged for foreign currency by businesses operating inside Venezuela. In May 2003, after six months of negotiation, the Organization of the American States brokered an accord between the Venezuelan government and its opponents. Although the accord does offer the prospect of stabilizing Venezuela’s economy, if another national strike is staged, exchange controls remain in place, or economic and political conditions in Venezuela continue to deteriorate, our results of operations in Venezuela could

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      During the years ended December 31, 2003 and 2002, we recorded exchange losses of approximately $2.4 million and $5.8 million, respectively, for assets exposed to currency translation in Venezuela. For the year ended December 31, 2003, our Venezuelan operations represented approximately 11% of our revenue and 18% of our gross profit. At December 31, 2003, we had approximately $23.0 million in accounts receivable related to our Venezuelan operations.

      In February 2003, the Venezuelan government fixed the exchange rate to 1,600 bolivars for each U.S. dollar. In February 2004, the government devalued the currency by approximately 17%. The impact of the devaluation on our results will depend upon the amount of our assets (primarily working capital) exposed to currency fluctuation in Venezuela in future periods. As of December 31, 2003, we had approximately $6.0 million in net assets exposed to currency fluctuation in Venezuela. Based on these assets, a 10% change in exchange rates would result in a $0.5 million gain or loss in Venezuela.

      As part of our acquisition of the gas compression business of Schlumberger, we acquired minority interests in three joint ventures in Venezuela. As a minority investor in these joint ventures, we will not be able to control their operations and activities, including, without limitation, whether and when they distribute cash or property to their holders. In January 2003, we gave notice of our intent to exercise our right to put our interest in one of these joint ventures, the PIGAP II joint venture, back to Schlumberger Surenco. If not exercised, the put right would have expired as of February 1, 2003. On May 14, 2003, we entered into an agreement with Schlumberger Surenco to terminate the PIGAP II put and thus have retained our ownership interest in PIGAP II.

      We are involved in a project to build and operate barge-mounted gas compression and gas processing facilities to be stationed in a Nigerian coastal waterway as part of the performance of a contract between an affiliate of The Royal/Dutch Shell Group (“Shell”) and Global Energy and Refining Ltd. (“Global”), a Nigerian company. We have completed the building of the required barge-mounted facilities. We understand that Global must complete a significant financing for part of the project in the near term or Shell would be able to terminate its contract with Global. Global has orally informed us that they have completed a financing, although it is not clear to us whether the funds raised will be sufficient to perform their obligations under the Shell contract. In light of the political environment in Nigeria, Global’s lack of a successful track record with respect to this project and other factors, there is no assurance that Global will be able to comply with its obligations under the Shell contract. We believe that Global is in default with respect to certain agreements they have with us, as a result of which we believe we have certain termination rights.

      If Shell were to terminate its contract with Global for any reason or we were to terminate our involvement in the project, we would be required to find an alternative use for the barge facility which could result in a write-down of our investment. We currently have an investment of approximately $29.8 million associated with the barge facility and approximately $4.1 million associated with advances to, and our investment in, Global.

      For financial data relating to the Company’s geographic concentrations, see Note 23 to the Notes to Consolidated Financial Statements included in Item 15 of this Form 10-K.

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Executive Officers of the Registrant

      The following sets forth, as of March 12, 2004, the name, age and business experience for the last five years of each of our executive officers:

      The following sets forth certain information regarding executive officers of the Company:

      Chad C. Deaton was elected President, Chief Executive Officer and director in August 2002. From 1976 through 1984, Mr. Deaton served in a variety of positions with the Dowell Division of Dow Chemical. Following Schlumberger’s acquisition of Dowell in 1984, Mr. Deaton served in management positions with Schlumberger in Europe, Russia and the United States. Mr. Deaton was executive vice president of Schlumberger Oilfield Services from 1998 to 1999. From September 1999 to September 2001, Mr. Deaton served as a Senior Advisor to Schlumberger Oilfield Services.

      John E. Jackson has served as Senior Vice President and Chief Financial Officer since February 2002. Prior to joining Hanover, Mr. Jackson served as Vice President and Chief Financial Officer of Duke Energy Field Services, a joint venture of Duke Energy and Phillips Petroleum that is one of the nation’s largest producers and marketers of natural gas liquids. Mr. Jackson joined Duke Energy Field Services as Vice President and Controller in April 1999 and was named Chief Financial Officer in February 2001. Prior to joining Duke Energy Field Services, Mr. Jackson served in a variety of treasury, controller and accounting positions at Union Pacific Resources between June 1981 and April 1999.

      Mark S. Berg* has served as Senior Vice President, General Counsel and Secretary since May 2002. From 1997 through 2001, Mr. Berg was an executive officer of American General Corporation, a Fortune 500 diversified financial services company, most recently serving in the position of Executive Vice President, General Counsel and Secretary. Mr. Berg began his career in 1983 as an associate with the Houston-based law firm of Vinson & Elkins L.L.P. and served as a partner from 1990 through 1997.

      Peter G. Schreck has served as Vice President — Treasury and Planning since September 2000. Mr. Schreck was previously employed in various financial positions by Union Pacific Corporation and its affiliated subsidiaries from 1988 through August 2000. Immediately prior to joining Hanover, Mr. Schreck held the position of Treasurer and Director of Financial Services for Union Pacific Resources Company.

      Stephen P. York has served as Vice President and Corporate Controller since April 2002. Prior to joining Hanover, Mr. York served as Director, Payroll Production of Exult, Inc., a provider of web-enabled human resources management services in Charlotte, NC, since 2001. From 1981 to 2000, Mr. York held various management positions with Bank of America Corporation, including Senior Vice President — Personnel Operations, Senior Vice President — Controller/ General Accounting, Senior Vice President — Corporate Accounts Payable/ Fixed Assets, and Vice President — Audit Director. Mr. York was an accountant with KPMG Peat Marwick in Waco, TX, from 1979 to 1981.

* On February 27, 2004, Mr. Berg entered into a Separation Agreement with us and we announced that Mr. Berg plans to step down from his position at Hanover effective March 31, 2004.

Employees

      As of December 31, 2003 we had approximately 5,500 employees, approximately 500 of whom are represented by a labor union. Furthermore, we had approximately 850 contract personnel. We believe that our relations with our employees and contract personnel are satisfactory.

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Electronic Information

      We maintain a website which can be found at http://www.hanover-co.com. We make our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and the amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 available on our website. Also, such information is readily available at the website of the Securities and Exchange Commission, which can be found at http://www.sec.gov.

      A paper copy of any of the above-described filings is also available free of charge from the Company upon request by contacting Hanover Compressor Company, 12001 North Houston Rosslyn Road, Houston, Texas 77086, Attention: Corporate Secretary (281) 405-5175. You may also read and copy any document we file with the SEC at its public reference facilities at Room 1024, 450 Fifth Street, N.W., Washington, D.C. 20549. You can obtain copies of the documents at prescribed rates by writing to the Public Reference Section of the SEC at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference facilities. Our SEC filings are also available at the offices of the New York Stock Exchange, Inc., 11 Wall Street, New York, New York 10005.

      The following table describes the material facilities owned or leased by Hanover and our subsidiaries as of December 31, 2003:

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Our corporate headquarters and compressor fabrication facility in Houston, Texas and our production equipment manufacturing facility in Columbus, Texas are mortgaged to secure the repayment of approximately $2.9 million (as of December 31, 2003) in indebtedness to a commercial bank.

      Our executive offices are located at 12001 North Houston Rosslyn, Houston, Texas 77086 and our telephone number is (281) 447-8787.

      Commencing in February 2002, approximately 15 putative securities class action lawsuits were filed against us and certain of our current and former officers and directors in the United States District Court for the Southern District of Texas. These class actions (together with subsequently filed actions) were consolidated into one case, Pirelli Armstrong Tire Corporation Retiree Medical Benefits Trust, On Behalf of Itself and All Others Similarly Situated, Civil Action No. H-02-0410, naming as defendants Hanover, Mr. Michael J. McGhan, Mr. William S. Goldberg and Mr. Michael A. O’Connor. The complaints asserted various claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and sought unspecified amounts of compensatory damages, interest and costs, including legal fees. The court entered an order appointing Pirelli Armstrong Tire Corporation Retiree Medical Benefits Trust and others as lead plaintiffs on January 7, 2003 and appointed Milberg, Weiss, Bershad, Hynes & Lerach LLP as lead counsel. On September 5, 2003, lead plaintiffs filed an amended complaint in which they sought relief under Sections 10(b) of the Securities Exchange Act and Section 11 of the Securities Act against Hanover, certain former officers and directors and our auditor, PricewaterhouseCoopers LLP, on behalf of themselves and the class of persons who purchased Hanover securities between May 4, 1999 and December 23, 2002.

      In the securities action, the plaintiffs allege generally that the defendants violated the federal securities laws by making misstatements and omissions in Hanover’s periodic filings with the SEC as well as in other public statements in connection with the transactions that were restated in 2002.

      Commencing in February 2002, four derivative lawsuits were filed in the United States District Court for the Southern District of Texas, two derivative lawsuits were filed in state district court for Harris County, Texas (one of which was nonsuited and the second of which was removed to Federal District Court for the Southern District of Texas) and one derivative lawsuit was filed in the Court of Chancery for the State of Delaware in and for New Castle County. These derivative lawsuits, which were filed by certain of our shareholders purportedly on behalf of Hanover, alleged, among other things, that our directors breached their fiduciary duties to shareholders in connection with certain of the transactions that were restated in 2002, and sought unspecified amounts of damages, interest and costs, including legal fees. The derivative lawsuits in the United States District Court for the Southern District of Texas were consolidated on August 19 and August 26, 2002 into the Harbor Finance Partners derivative lawsuit. With that consolidation, the pending derivative lawsuits were:

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     On October 2, 2003, the Harbor Finance Partners derivative lawsuit was consolidated into the Pirelli Armstrong Tire Corporation Retiree Medical Benefits Trust securities class action.

      On and after March 26, 2003, three plaintiffs filed separate putative class actions against Hanover, certain named individuals and other purportedly unknown defendants, in the United States District Court for the Southern District of Texas. The alleged class was composed of persons who participated in or were beneficiaries of The Hanover Companies Retirement and Savings Plan, which was established by Hanover pursuant to Section 401(k) of the United States Internal Revenue Code of 1986, as amended. The purported class action sought relief under ERISA based upon Hanover’s and the individual defendants’ alleged mishandling of Hanover’s 401(k) Plan. The three ERISA putative class actions are entitled: Kirkley v. Hanover, Case No. H-03-1155; Angleopoulos v. Hanover, Case No. H-03-1064; and Freeman v. Hanover, Case No. H-03-1095. On August 1, 2003, the three ERISA class actions were consolidated into the Pirelli Armstrong Tire Corporation Retiree Medical Benefits Trust federal securities class action. On October 9, 2003, a consolidated amended complaint was filed by the plaintiffs in the ERISA class action against Hanover, Michael McGhan, Michael O’Connor and William Goldberg, which included the same allegations as indicated above, and was filed on behalf of themselves and a class of persons who purchased or held Hanover securities in their 401(k) Plan between May 4, 1999 and December 23, 2002.

      These actions alleged generally that, in connection with the transactions that were restated in 2002, we and certain individuals acting as fiduciaries of Hanover’s 401(k) Plan breached our fiduciary duties to the plan participants by offering Hanover common stock as an investment option, failing to provide material information to plan participants regarding the suitability of Hanover common stock as an investment alternative, failing to monitor the performance of plan fiduciaries, and failing to provide material information to other fiduciaries.

      On October 23, 2003, we entered into a Stipulation of Settlement, which settled all of the claims underlying the putative securities class action, the putative ERISA class action and the shareholder derivative actions described above. The terms of the settlement provided for us to: (1) make a cash payment of approximately $30 million (of which $26.7 million was funded by payments from Hanover’s directors and officers insurance carriers), (2) issue 2.5 million shares of our common stock, and (3) issue a contingent note with a principal amount of $6.7 million. The note is payable, together with accrued interest, on March 31, 2007 but will be extinguished (with no money owing under it) if our common stock trades at or above the average price of $12.25 per share for 15 consecutive trading days at any time between March 31, 2004 and March 31, 2007. In addition, upon the occurrence of a change of control that involves us, if the change of control or shareholder approval of the change of control occurs before February 9, 2005, which is twelve months after final court approval of the settlement, we will be obligated to contribute an additional $3 million to the settlement fund. As part of the settlement, we have also agreed to implement corporate governance enhancements, including allowing shareholders owning more than 1% but less than 10% of our outstanding common stock to participate in the process to appoint two independent directors to our board of directors (pursuant to which on February 4, 2004 we appointed Margaret K. Dorman and Stephen M. Pazuk to our board of directors) and making certain changes to our code of conduct.

      GKH Investments, L.P. and GKH Private Limited (collectively “GKH”) which, as of December 31, 2003, together owned approximately 10% of Hanover’s outstanding common stock and which sold shares in our March 2001 secondary offering of common stock, are parties to the settlement and have agreed to settle claims against them that arise out of that offering as well as other potential securities, ERISA, and derivative claims. The terms of the settlement provide for GKH to transfer 2.5 million shares of Hanover common stock from their holdings or from other sources to the settlement fund.

      On October 24, 2003, the parties moved the United States District Court for the Southern District of Texas for preliminary approval of the proposed settlement and sought permission to provide notice to the potentially affected persons and to set a date for a final hearing to approve the proposed settlement. On December 5, 2003, the court held a hearing and granted the parties’ motion for preliminary approval of the proposed settlement and, among other things, ordered that notice be provided to appropriate persons and

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      On February 9, 2004, the United States District Court for the Southern District of Texas entered three Orders and Final Judgments, approving the settlement on the terms agreed upon in the Stipulation of Settlement with respect to all of the claims described above including the dismissal of each of the actions other than the Coffelt Family derivative action filed in the Delaware Chancery Court. The court also entered an Order and Final Judgment approving the plans of allocation with respect to each action, as well as an Order and Final Judgment approving the schedule of attorneys’ fees for counsel for the settling plaintiffs. The time in which these Orders and Final Judgments may be appealed expired on March 10, 2004 without any appeal being lodged. In addition, on March 16, 2004, the Delaware Chancery Court dismissed the Coffelt Family derivative action. The settlement has therefore become final and will be implemented according to its terms. In March 2004, we issued and delivered to the escrow agent for the settlement fund 2.5 million shares of Hanover common stock, as required by the settlement. Our independent auditor, PricewaterhouseCoopers, is not a party to the settlement and remains a party to the securities class action.

      Based on the terms of the settlement agreement and individual components of the settlement, we recorded the cost of the litigation settlement. The details of the litigation settlement charge were as follows (in thousands):

      The $3.6 million estimated fair value of the note to be issued was based on the present value of the future cash flows discounted at borrowing rates currently available to us for debt with similar terms and maturities. Using a market-borrowing rate of 9.3%, the principal value and the stipulated interest rate required by the note of 5% per annum, a discount of $0.8 million was computed on the note to be issued. Upon the issuance of the note, the discount will be amortized to interest expense over the term of the note. Because the note could be extinguished without a payment (if our common stock trades at or above the average price of $12.25 per share for 15 consecutive trading days at any time between March 31, 2004 and March 31, 2007), we will be required to record an asset when the note is issued for the value of the embedded derivative, as required by SFAS 133. We estimated the value of the derivative and reduced the amount we included for the estimate of the value of the note by approximately $2.3 million at December 31, 2003. This asset will be marked to market in future periods with any increase or decrease included in our statement of operations.

      As of December 31, 2003, our accompanying balance sheet included a $33.4 million long-term liability and $32.7 million in accrued liabilities related to amounts that are expected to be paid in the next twelve months. During the second quarter of 2003, the $26.7 million receivable from the insurance carriers and $2.8 million of our portion of the cash settlement was paid into an escrow fund and is included in the accompanying balance sheet as restricted cash. In the first quarter of 2004, we will reclassify $29.8 million, the value accrued for the stock to be paid, from other liabilities to stockholders’ equity and will include the shares in our outstanding shares used for earnings per share calculations.

      On November 14, 2002, the SEC issued a Formal Order of Private Investigation relating to the transactions underlying and, other matters relating to, the restatements of our financial statements. In December 2003, we entered into a settlement with the SEC. Without admitting or denying any of the SEC’s findings, we consented to the entry of a cease and desist order requiring future compliance with

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      As of December 31, 2003, we had incurred approximately $15.1 million in legal related expenses in connection with the internal investigations, the putative class action securities and ERISA lawsuits, the derivative lawsuits and the SEC investigation. Of this amount, we advanced approximately $2.3 million on behalf of certain current and former officers and directors in connection with the above-named proceedings. We intend to advance any litigation costs of our current and former officers and directors, subject to the limitations imposed by Delaware and other applicable law and Hanover’s certificate of incorporation and bylaws. We do not expect additional legal fees and administrative costs in connection with the settlement of the litigation, advances on behalf of current and former officers and directors for legal fees and other related costs to exceed $2.5 million, the remaining balance of the accrual.

      On June 25, 1999, we notified the Air Quality Bureau of the Environmental Protection Division, New Mexico Environment Department, of potential violations of regulatory and permitting requirements. The potential violations included failure to conduct required performance tests, failure to file required notices and failure to pay fees for compressor units located on sites for more than one year. We promptly paid the required fees and corrected the potential violations. On June 12, 2001, after the potential violations had been corrected, the Director of the Division issued a compliance order to us in connection with the potential violations. The compliance order assessed a civil penalty of $15,000 per day per alleged regulatory violation and permit; no total penalty amount was proposed in the compliance order. On October 3, 2003, the Division notified us that the total proposed penalty would be $759,072. However, since the alleged violations had been self-disclosed, that amount was reduced to $189,768. We have responded to the penalty assessment, challenging some of the calculations, and have proposed an alternative settlement amount. We are currently negotiating with the New Mexico Environment Department on the method of calculation and proposed settlement amounts, and the issue is not yet resolved. A Stipulated Motion for Extension of Time to File Answer has been filed which extends the deadline for filing our response to March 22, 2004.

      In the ordinary course of business we are involved in various other pending or threatened legal actions, including environmental matters. While management is unable to predict the ultimate outcome of these actions, it believes that any ultimate liability arising from these actions will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

      No matters were submitted to a vote of our shareholders during the fourth quarter of our fiscal year ended December 31, 2003.

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PART II

      Our common stock is listed on the New York Stock Exchange under the symbol “HC.” As of March 19, 2004, 85,536,605 shares of our common stock were issued and held of record by approximately 700 holders. On March 19, 2004, the last reported sales price of our common stock on the New York Stock Exchange was $10.87. The following table presents, for the periods indicated, the range of high and low quarterly closing sales prices of our common stock, as reported on the New York Stock Exchange.

      We have not paid any cash dividends on our common stock since our formation and do not anticipate paying such dividends in the foreseeable future. The Board of Directors anticipates that all cash flow generated from operations in the foreseeable future will be retained and used to pay down debt, develop and expand our business. Any future determinations to pay cash dividends on our common stock will be at the discretion of the our Board of Directors and will be dependent upon our results of operations and financial condition, credit and loan agreements in effect at that time and other factors deemed relevant by the Board of Directors. Our bank credit facility, with the JPMorgan Chase Bank, as agent, prohibits us (without the lenders’ prior approval) from declaring or paying any dividend (other than dividends payable solely in our common stock or in options, warrants or rights to purchase such common stock) on, or making similar payments with respect to, our capital stock.

      See Item 12 of this report for disclosures regarding securities authorized for issuance under equity compensations plans.

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SELECTED FINANCIAL DATA (HISTORICAL)

      In the table below we have presented certain selected financial data for Hanover for each of the five years in the period ended December 31, 2003. The historical consolidated financial data has been derived from Hanover’s audited consolidated financial statements. The following information should be read together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Form 10-K and the Consolidated Financial Statements in Item 15 of this Form 10-K.

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(1)	During 2002, we announced a series of restatements that ultimately reduced our initially reported pre-tax income by $0.4 million, or 0.3%, for the year ended December 31, 2001, by $14.5 million, or 15.5%, for the year ended December 31, 2000, and by $3.1 million, or 4.9%, for the year ended December 31, 1999, although certain restatements resulted in a larger percentage adjustment on a quarterly basis.
(2)	For a description of significant business acquisitions, see Note 2 in Notes to the Consolidated Financial Statements in Item 15 of this Form 10-K. In the fourth quarter of 2002, we decided to discontinue certain businesses. For a description of the discontinued operations, see Note 3 in Notes to the Consolidated Financial Statements in Item 15 of this Form 10-K.
(3)	In June 2001, the FASB issued Statement of Financial Accounting Standards 142, “Goodwill and Other Intangible Assets” (“SFAS 142”). Under SFAS 142, amortization of goodwill to earnings is discontinued. Instead, goodwill is reviewed for impairment annually or whenever events indicate impairment may have occurred. SFAS 142 was effective for us on January 1, 2002. For financial data relating to our goodwill and other intangible assets, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Note 9 in Notes to the Consolidated Financial Statements in Item 15 of this Form 10-K.
(4)	In accordance with FASB Interpretation No. 46, “Consolidation of Variable Interest Entities, an interpretation of ARB 51” as revised in December 2003 (“FIN 46”), for periods ending after June 30, 2003, we have included in our consolidated financial statements the special purpose entities that lease compression equipment to us. As a result, on July 1, 2003, we added approximately $897 million of compression equipment assets, net of accumulated depreciation, and approximately $1,139.6 million of our compression equipment lease obligations (including approximately $1,105.0 million in debt) to our balance sheet. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Leasing Transactions and Accounting Change for FIN 46” in Item 7 of this Form 10-K.
(5)	On October 23, 2003, we entered into a Stipulation of Settlement, which became final on March 10, 2004 and settled all of the claims underlying the putative securities class action, the putative ERISA class action and the shareholder derivative actions discussed in “Legal Proceedings” in Item 3 of this Form 10-K and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Year Ended December 31, 2003 Compared to Year Ended December 31, 2002 — Provision for Cost of Litigation Settlement” in Item 7 of this Form 10-K.

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      Management’s discussion and analysis of the results of operations and financial condition of Hanover Compressor Company should be read in conjunction with the Consolidated Financial Statements and related Notes thereto.

Overview

      We are a global market leader in the full service natural gas compression business and are also a leading provider of service, fabrication and equipment for oil and natural gas processing and transportation applications. We sell and rent this equipment and provide complete operation and maintenance services, including run-time guarantees, for both customer-owned equipment and our fleet of rental equipment. Hanover was founded as a Delaware corporation in 1990, and has been a public company since 1997. Our customers include both major and independent oil and gas producers and distributors as well as national oil and gas companies in the countries in which we operate. Our maintenance business, together with our parts and service business, provides solutions to customers that own their own compression and surface production and processing equipment, but want to outsource their operations. We also fabricate compressor and oil and gas production and processing equipment and provide gas processing and treating, gas measurement and oilfield power generation services, primarily to our domestic and international customers as a complement to our compression services. In addition, through our subsidiary, Belleli, we provide engineering, procurement and construction services primarily related to the manufacturing of heavy wall reactors for refineries and construction of desalination plants, primarily for use in Europe and the Middle East.

      We experienced rapid growth from 1998 through 2001 primarily as a result of significant acquisitions during 2000 and 2001, during which period our total assets increased from approximately $753 million as of December 31, 1999 to approximately $2.3 billion as of December 31, 2001, and our debt, including compression equipment leases obligations, increased from approximately $572 million at December 31, 1999 to approximately $1,736 million at December 31, 2001.

      In addition to substantially increasing our outstanding debt, our growth exceeded our infrastructure capabilities and strained our internal control environment. During 2002, we announced a series of restatements of certain transactions that occurred in 1999, 2000 and 2001. In November 2002, the SEC issued a Formal Order of Private Investigation relating to the transactions underlying and other matters relating to the restatements. In addition, during 2002, Hanover and certain of its past and present officers and directors were named as defendants in a consolidated action pending in federal court that included a putative securities class action, a putative class action arising under the Employee Retirement Income Security Act and shareholder derivate actions. The litigation related principally to the matters involved in the transactions underlying the restatements of our financial statements. As discussed below, both the SEC investigation and the litigation have recently been settled. For a more detailed discussion of the SEC investigation and the securities litigation, see “Legal Proceedings” in Item 3 of this Form 10–K.

      Our operations depend upon the levels of activity in natural gas development, production, processing and transportation. Such activity levels typically decline when there is a significant reduction in oil and gas prices or significant instability in energy markets. In recent years, oil and gas prices have been extremely volatile. In addition, domestic natural gas consumption fell in 2001 and 2002 as a result of the recent economic slowdown in the United States. Due to a deterioration in market conditions, we experienced a decline in the demand for our products and services in 2002 and 2003, which, along with the distractions associated with our management reorganization, resulted in reductions in the utilization of our compressor rental fleet and our revenues, gross margins and profits in those years.

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      The North American rig count increased by 27% to 1,531 at December 31, 2003 from 1,204 at December 31, 2002, and the twelve-month rolling average North American rig count increased by 28% to 1,404 at December 31, 2003 from 1,097 at December 31, 2002. In addition, the twelve-month rolling average New York Mercantile Exchange wellhead natural gas price increased to $5.39 per Mcf at December 31, 2003 from $3.22 per Mcf at December 31, 2002. Despite the increase in natural gas prices and the recent increase in the rig count, U.S. natural gas production levels have not significantly changed. Recently, we have not experienced any significant growth in domestic rentals or purchases of equipment and services by our customers, which we believe is primarily the result of the lack of a significant increase in U.S. natural gas production levels. However, with several non-operational issues behind us, we are focused on improving our sales success ratio on new bid opportunities and anticipate some revenue growth in 2004.

      During 2002, a number of our executives involved directly or indirectly with the transactions underlying the restatements described above resigned, including our former Chief Executive Officer, Chief Financial Officer, Vice Chairman of our board of directors, Chief Operating Officer and the head of our international operations. During and after 2002, we hired and appointed a new Chief Executive Officer and Chief Financial Officer, hired and appointed our first General Counsel, hired a new Controller, and hired new managers of Human Resources, Financial Reporting and Policy Administration. During 2002, we added three independent directors to our board of directors and elected an independent Chairman of the Board from among the three new directors. In addition, on February 4, 2004, we added two new independent directors to our board of directors. Our new management team has undertaken the following initiatives to improve our operations and our liquidity position.

      Focus on core business. We have built our leading market position through our strengths in compression rentals, compressor fabrication, production and processing equipment rental and fabrication and parts and service. We are focusing our efforts on these businesses and on streamlining operations in our core markets. In connection with these efforts, we have decided to exit and sell certain non-core business lines. In December 2002, our board of directors approved management’s recommendation to exit and sell our non-oilfield power generation assets and certain used equipment business lines. In 2003, we sold our interests in two non-oilfield power generation facilities for approximately $27.2 million, consisting of $6.4 million in cash, $3.3 million in notes that mature in 2004 and 2005 and the release from a capital lease that had an outstanding balance of approximately $17.2 million.

      Enhance return on capital. We are seeking to deploy our capital more effectively in order to improve the total returns from our investments. To achieve this objective, we intend to work to improve our operating performance and profitability by focusing on the following initiatives:

	•	Improve our domestic fleet utilization by limiting the addition of new units, where applicable and permissible under our bank credit facility and the conforming amendments to our compression equipment lease obligations, moving idle domestic units into service in international markets and retiring less profitable units. During 2003, we renewed several key domestic customer alliances involving approximately 300,000 horsepower, retired approximately 41,000 horsepower, moved approximately 36,000 horsepower to international markets and increased compression under contract by approximately 50,000 horsepower. As a result, domestic utilization increased to 76% at December 31, 2003 from 72% at December 31, 2002.
	•	Increase prices selectively for our domestic rental business. In early 2003, we began to selectively introduce price increases for our domestic compression rental business. Such price increases, along with a slight improvement in market conditions, resulted in a 3% increase in revenue from our domestic rentals business in the six months ended December 31, 2003 as compared to the six months ended December 31, 2002.
	•	Improve operating efficiencies by consolidating certain of our operations. During 2003, we shut down six facilities and reduced our U.S. headcount by approximately 550 employees.

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	•	Increase activity in our fabrication sales and parts and service operations to take advantage of our available fabrication capacity and field technician manpower.

      Exploit international opportunities. International markets continue to represent the greatest growth opportunity for our business. We believe that these markets are underserved. In addition, we typically see higher pricing in international markets relative to the domestic market. During 2003, we added approximately 50,000 horsepower to our international rental fleet under contract. We intend to allocate additional resources toward international markets, to open offices abroad, where appropriate, and to move idle domestic units into service in international markets, where applicable. However, our ability to invest capital resources and allocate assets into international markets is restricted by our new bank credit facility and the conforming amendments to our compression equipment lease obligations and by our intentions to reduce outstanding debt as described below.

      Improve our capital discipline. We plan to improve our capital discipline by lowering the working capital we have employed and reducing our substantial level of debt with both excess operating cash flow and proceeds from asset sales. We are also focused on improving the management of our working capital by lowering the number of days outstanding for our accounts receivable and reducing inventory levels. To reduce debt, we are committed to under-spending cash flow, and we are currently planning to allocate approximately $180 million of our operating cash flow generated from 2004 through 2006 to debt repayment.

      As part of our plans to address our substantial level of debt resulting from our growth through acquisitions, we engaged in a number of refinancing transactions in 2003 to address liquidity issues associated with our debt. In December 2003, we issued $200 million aggregate principal amount of our 8.625% Senior Notes due 2010 and $143.8 million aggregate principal amount of our 4.75% Convertible Senior Notes due 2014. The net proceeds from these offerings were used to repay outstanding indebtedness under our 1999A equipment lease notes due June 2004 and a portion of the outstanding indebtedness under our previous bank credit facility. In addition, in December 2003, we entered into a new $350 million bank credit facility that matures in December 2006. The new bank credit facility replaced our previous bank credit facility that matured in November 2004. The new bank credit facility provides additional flexibility to support our short-term liquidity needs. Also, in October 2003, the PIGAP II joint venture, in which we have a 30% interest, engaged in a project financing and distributed approximately $78.5 million to us, of which approximately $59.9 million was used to pay off a non-recourse promissory note issued by one of our subsidiaries that had been secured by our interest in PIGAP II. We also restructured a $150 million subordinated note that had been issued to Schlumberger in connection with an acquisition. We restructured the note as our Zero Coupon Subordinated Notes due March 31, 2007 and reduced the implicit interest rate.

      Resolved pending litigation and investigations. In 2003, we entered into an agreement to settle the pending securities litigation. On February 9, 2004, the United States District Court for the Southern District of Texas entered three Orders and Final Judgments, approving the settlement on the terms agreed upon in the Stipulation of Settlement with respect to all of the pending claims. The court also entered an Order and Final Judgment approving the plans of allocation with respect to each action, as well as an Order and Final Judgment approving the schedule of attorneys’ fees for counsel for the settling plaintiffs. The time in which these Orders and Final Judgments may be appealed expired on March 10, 2004 without any appeal being lodged. The settlement has therefore become final and will be implemented according to its terms.

      The settlement provides for us to (1) make a cash payment of approximately $30 million (of which $26.7 million was funded by payments from our directors and officers insurance carriers), (2) issue 2.5 million shares of our common stock, and (3) issue a contingent note with a principal amount of $6.7 million, which may be extinguished in certain circumstances. In addition, upon the occurrence of a change of control that involves us, if the change of control or shareholder approval of the change of control occurs before February 9, 2005, which is twelve months after final court approval of the settlement, we will be obligated to contribute an additional $3 million to the settlement fund. Also, in December 2003, a

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      Net losses. We recorded a consolidated net loss of $208.3 million for the year ended December 31, 2003, as compared to a consolidated net loss of $116.1 million and consolidated net income of $72.4 million for the years ended December 31, 2002 and 2001, respectively. Our results for each of the last two years have been affected by a number of charges that may not necessarily be indicative of our core operations or our future prospects and impact comparability between years. These special items are discussed in “Results of Operations” below.

      Results by Segment. The following table summarizes revenues, expenses and gross profit margin percentages for each of our business segments (dollars in thousands):

      Belleli Acquisition. In 2002, we increased our ownership of Belleli to 51% from 20.3% by converting $13.4 million in loans, together with approximately $3.2 million in accrued interest thereon, into additional equity ownership and in November 2002 began consolidating the results of Belleli’s operations. Belleli has three manufacturing facilities, one in Mantova, Italy and two in the United Arab Emirates (Jebel Ali and Hamriyah). During 2002, we also purchased certain operating assets used by Belleli for approximately $22.4 million from a bankruptcy estate of Belleli’s former parent and leased these assets to Belleli for approximately $1.2 million per year, for a term of seven years.

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      In connection with our increase in ownership in 2002, we entered into an agreement with the minority owner of Belleli that provided the minority owner the right, until June 30, 2003, to purchase our interest for an amount that approximated our investment in Belleli. The agreement also provided us with the right, beginning in July 2003, to purchase the minority owner’s interest in Belleli. In addition, the minority owner historically had been unwilling to provide its proportionate share of capital to Belleli. We believed that our ability to maximize value would be enhanced if we were able to exert greater control through the exercise of our purchase right. Thus, in August 2003, we exercised our option to acquire the remaining 49% interest in Belleli for approximately $15.0 million in order to gain complete control of Belleli. As a result of these transactions and intervening foreign exchange rate changes, we recorded $4.8 million in identifiable intangible assets, with a weighted average life of approximately 17 years, and $35.5 million in goodwill.

      As a result of the war in Iraq, the strengthening of the Euro and generally unfavorable economic conditions, we believe that the estimated fair value of Belleli declined significantly during 2003. Upon gaining complete control of Belleli and assessing our long-term growth strategy, we determined that their general factors in combination with the specific economic factors impacting Belleli had significantly and adversely impacted the timing and amount of the future cash flows that we expected Belleli to generate. We currently do not expect to realize our original growth expectations for Belleli in the timeframe that we originally forecasted.

      During the performance of our annual goodwill impairment review in the fourth quarter of 2003, we determined the present value of Belleli’s expected future cash flows was less than our carrying value of Belleli. This resulted in a full impairment charge for the $35.5 million in goodwill associated with Belleli. Upon further analysis, it was determined that the factors resulting in the goodwill impairment charge were also present during the third quarter of 2003 and that the exercise of our purchase option in the third quarter of 2003 and the presence of such factors should have resulted in an interim goodwill impairment test under SFAS 142 and an impairment charge at that time. We have adjusted our third quarter results accordingly.

      We had previously announced our plan to reduce our U.S. headcount by approximately 500 employees worldwide and to close four fabrication facilities. During the year ended December 31, 2002, we accrued approximately $2.7 million in employee separation costs related to the reduction in workforce. During the year ended December 31, 2003, we paid approximately $2.0 million in employee separation costs, implemented further cost saving initiatives and closed two additional facilities. We expect to incur an additional $0.7 million in employee separation costs related to the completion of these activities. Since December 31, 2002, our U.S. workforce has decreased by approximately 550 employees.

      During the fourth quarter of 2002, we reviewed our business lines and our board of directors approved management’s recommendation to exit and sell our non-oilfield power generation facilities and certain used equipment business lines. The results from these businesses are reflected as discontinued operations in our consolidated financial statements. Additionally, during 2003 and 2002, we recorded certain write-downs, asset impairments and restructuring costs. A summary of these charges and the related impact on our financial results is discussed below.

Critical Accounting Estimates

      This discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, we evaluate our estimates and accounting policies, including those related to bad debts, inventories, fixed assets, investments, intangible assets, income taxes, warranty obligations, sale leaseback transactions, revenue recognition and contingencies and litigation. We base our estimates on historical experience and on other assumptions that we

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      We maintain allowances for doubtful accounts for estimated losses resulting from the inability of our customers to make required payments. If the financial condition of a customer deteriorates, resulting in an impairment of its ability to make payments, additional allowances may be required. As of December 31, 2003, our largest account receivable from a customer was approximately $10.3 million. During 2003, 2002 and 2001, we recorded approximately $4.0 million, $7.1 million and $4.9 million in additional allowances for doubtful accounts, respectively. A 10% increase in bad debt expense would have resulted in approximately $0.4 million in additional selling, general and administrative expense for 2003.

      We write down our inventory for estimated obsolescence or unmarketable inventory equal to the difference between the cost of inventory and the estimated market value based upon assumptions about future demand and market conditions. If actual market conditions are less favorable than those expected by management, additional inventory write-downs may be required. During 2003, 2002 and 2001, we recorded approximately $3.0 million, $13.9 million and $2.3 million, respectively, in additional reserves for obsolete and slow moving inventory.

      We review for the impairment of long-lived assets, including property, plant and equipment, assets held for sale and investments in non-consolidated affiliates whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss exists when estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. When necessary, an impairment loss is recognized and represents the excess of the asset’s carrying value as compared to its estimated fair value and is charged to the period in which the impairment occurred. The determination of what constitutes an indication of possible impairment, the estimation of future cash flows and the determination of estimated fair value are all significant judgments. During 2003 and 2002, as a result of the review of our rental fleet, we recorded $14.3 million and $34.5 million, respectively, in additional depreciation on equipment that was retired and equipment that was expected to be sold or abandoned.

      In addition, we perform an annual goodwill impairment test, pursuant to the requirements of SFAS 142, in the fourth quarter of each year, to determine if the estimated recoverable value of the reporting unit exceeds the net carrying value of the reporting unit, including the applicable goodwill. We determine the fair value of our reporting units using a combination of the expected present value of future cash flows and the market approach. The present value of future cash flows is estimated using our most recent five-year forecast, the weighted average cost of capital and a market multiple on the reporting units earnings before interest, tax, depreciation and amortization. Changes in forecasts could effect the estimated fair value of our reporting units and result in a goodwill impairment charge in a future period. We used a 12% weighted average cost of capital in our analysis of the present value of future cash flows. During 2003 and 2002, we recorded $35.5 million and $52.1 million, respectively, in goodwill impairments as a result of our goodwill evaluations.

      We hold minority interests in companies having operations or technology in areas that relate to our business, one of which is publicly traded and may experience volatile share prices. We record an investment impairment charge when we believe an investment has experienced a decline in value that is other than temporary. Future adverse changes in market conditions or poor operating results of underlying investments could result in losses or an inability to recover the carrying value of the investments that may not be reflected in an investment’s current carrying value, thereby possibly requiring an impairment charge

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      We must estimate our expected future taxable income in order to assess the realizability of our deferred income tax assets. As of December 31, 2003, we reported a net deferred tax liability of $28.3 million, which included gross deferred tax assets of $320.0 million, net of a valuation allowance of $55.0 million and gross deferred tax liabilities of $293.3 million. Numerous assumptions are inherent in the estimation of future taxable income, including assumptions about matters that are dependent on future events, such as future operating conditions and future financial conditions.

      Additionally, we must consider any prudent and feasible tax planning strategies that might minimize the amount of deferred tax liabilities recognized or the amount of any valuation allowance recognized against deferred tax assets, if management has the ability to implement these strategies and the expectation of implementing these strategies if the forecasted conditions actually occur. The principal tax planning strategy available to us relates to the permanent reinvestment of the earnings of foreign subsidiaries. Assumptions related to the permanent reinvestment of the earnings of foreign subsidiaries are reconsidered periodically to give effect to changes in our businesses and in our tax profile.

      As a result of current year operating losses and charges in 2003, we were in a net deferred tax asset position (for U.S. income tax purposes) for the first time in 2003. Due to our cumulative domestic losses over the past three years, we could not reach the conclusion that it was “more likely than not” that certain of our U.S. deferred tax assets will be realized in the future. Accordingly, we provided a $25.7 million deferred tax valuation allowance against our net U.S. deferred tax asset. We will be required to record additional valuation allowances if our domestic deferred tax asset position is increased and the “more likely than not” criteria of SFAS 109 is not met. If we are required to record additional valuation allowances, our effective tax rate will be increased, perhaps substantially above the statutory rate. Our preliminary analysis leads us to believe that we will likely be required to record additional valuation allowances in the first quarter of 2004, unless we are able to implement tax planning strategies that would minimize or eliminate the amount of such additional valuation allowance prior to the end of the first quarter, and may be required to record additional valuation allowances in future periods.

      We recognize revenue and profit for our fabrication operations as work progresses on long-term, fixed-price contracts using the percentage-of-completion method, which relies on estimates of total expected contract revenue and costs. We follow this method because reasonably dependable estimates of the revenue and costs applicable to various stages of a contract can be made and because the fabrication projects usually last several months. Recognized revenues and profit are subject to revisions as the contract progresses to completion. Revisions in profit estimates are charged to income in the period in which the facts that give rise to the revision become known. The average duration of these projects is four to thirty-six months. Due to the long-term nature of some of our jobs, developing the estimates of cost often requires significant judgment.

      We estimate percentage of completion for compressor and processing equipment fabrication on a direct labor hour to total labor hour basis. This calculation requires management to estimate the number of total labor hours required for each project and to estimate the profit expected on the project. Production and processing equipment fabrication percentage of completion is estimated using the direct labor hour and cost to total cost basis. The cost to total cost basis requires us to estimate the amount of total costs (labor and materials) required to complete each project. Since we have many fabrication projects in process at any given time, we do not believe that materially different results would be achieved if different estimates, assumptions, or conditions were used for any single project.

      Factors that must be considered in estimating the work to be completed and ultimate profit include labor productivity and availability, the nature and complexity of work to be performed, the impact of

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      In the ordinary course of business, we are involved in various pending or threatened legal actions. While we are unable to predict the ultimate outcome of these actions, SFAS 5, “Accounting for Contingencies” requires management to make judgments about future events that are inherently uncertain. We are required to record (and have recorded) a loss during any period in which we, based on our experience, believe a contingency is likely to result in a financial loss to us. In making its determinations of likely outcomes of pending or threatened legal matters, management considers the evaluation of counsel knowledgeable about each matter. See “Legal Proceedings” in Item 3 of this Form 10-K.

Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

      For the year ended December 31, 2003, revenue increased to $1,095.4 million over 2002 revenue of $1,028.8 million. Included in 2003 revenue was $116.8 million of production and processing equipment fabrication revenue from Belleli, compared to $15.4 million for the same period a year earlier. We began including Belleli in our consolidated financial results in November 2002.

      Net loss for the year ended December 31, 2003, was $208.3 million, compared with a net loss of $116.1 million in 2002. As detailed in the chart below, included in the 2003 net loss was $250.6 million in pre-tax charges. In addition, we recorded a $25.7 million U.S. deferred tax valuation allowance that was included in the provision for income taxes. The net loss in 2002 included $182.7 million in pre-tax charges for the write-down of our investment in discontinued operations, the write-down of a portion of our domestic compression rental fleet, severance costs and bad debt reserves.

      In addition, 2003 net loss increased due to a decrease in gross margin percentages for both our domestic and international rental fleet and our fabrication businesses and an increase in selling, general and administrative expense and depreciation expense which are discussed further below. Our 2003 net loss included a $39.2 million pre-tax loss from the inclusion of Belleli, including a $35.5 million goodwill impairment discussed further below.

      Included in the net loss for 2003 were the following pre-tax charges (in thousands):