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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

Commission file no. 1-13071

Hanover Compressor Company

(Exact name of registrant as specified in its charter)

12001 North Houston Rosslyn, Houston, Texas 77086

(Address of principal executive offices, zip code)

Registrant’s telephone number, including area code:

(281) 447-8787

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

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

Title of class:     None

      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, 2004 was $752,645,000. 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 statements filed by such persons on or prior to June 30, 2004 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 4, 2005: 87,053,366 shares.

DOCUMENTS INCORPORATED BY REFERENCE

      Portions of the Registrant’s definitive proxy statement for the 2005 Annual Meeting of Stockholders to be held in 2005, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2004, are incorporated by reference into Part III.

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HANOVER COMPRESSOR COMPANY

TABLE OF CONTENTS

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:

      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. Except as required by law, 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.

General

      Hanover Compressor Company, (“we”, “us”, “our”, “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, and oilfield power generation services, primarily to our U.S. 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 and tank farms, primarily for use in Europe and the Middle East.

      Substantially all of our assets are owned and our operations are 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 U.S. subsidiaries of HCLP were merged, directly or indirectly, with and into HCLP.

      We believe that we are currently the largest provider of rental natural gas compression equipment and services in the United States on the basis of aggregate horsepower, with 5,944 rental units in the United States having an aggregate capacity of approximately 2,551,000 horsepower at December 31, 2004. In addition, we estimate that we are one of the largest providers of compression services in the Latin American market, operating 645 units internationally with approximately 758,000 horsepower at December 31, 2004. As of December 31, 2004, approximately 77% of our natural gas compression horsepower was located in the United States and approximately 23% was located elsewhere, primarily in Latin America.

      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 geographic business unit 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 rental segment of that market has experienced significant growth over the past decade. Despite a deterioration of market conditions in 2002 and 2003, we believe the U.S. market for both the purchase and rental of natural gas compression equipment will continue to improve 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, 2004, the rental portion of the U.S. gas compression market was estimated by industry sources to be approximately 5.4 million horsepower. We believe the growth of the rental compression capacity in the U.S. market has been primarily driven by the trend toward outsourcing by energy producers and processors. We believe that outsourcing provides the customer greater financial and operating flexibility by minimizing the customer’s investment in equipment and enabling the customer to more efficiently resize their compression capabilities to meet changing reservoir conditions. In addition, we believe that outsourcing typically provides the customer with more timely and technically proficient service and maintenance, which often reduces operating costs. Nevertheless, a significant percentage of installed gas compression equipment continues to be purchased by the customer, rather than rented.

      We believe growth opportunities for our products exist due to (1) increased worldwide energy consumption, (2) implementation of international environmental and conservation laws prohibiting the flaring of natural gas, which increases the need for gathering systems, (3) increased outsourcing by energy producers and processors, (4) the environmental soundness, economy and availability of natural gas as an alternative energy source, (5) continued aging of the worldwide natural gas reserve base and the attendant decline of wellhead pressures and (6) increased use of our products for reinjection in oilfield maintenance and the stripping of natural gas liquids from production streams. The rental compression business is capital intensive, and our ability to take advantage of these growth opportunities may be limited by our ability to raise capital to fund our expansion. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” in Item 7 of this Form 10-K.

Notable Events in 2004

      Debt Transactions. During 2004, we used cash flows from operations and proceeds from asset dispositions to reduce our outstanding indebtedness and minority interest obligations by $149.1 million.

      In June 2004, we issued under our shelf registration statement $200.0 million aggregate principal amount of our 9.0% Senior Notes due 2014, which are fully and unconditionally guaranteed on a senior subordinated basis by our wholly-owned subsidiary, HCLP. The net proceeds from this offering and available cash were used to repay the outstanding indebtedness and minority interest obligations of $193.6 million and $6.4 million, respectively, under our 2000A equipment lease that was to expire in March 2005.

      Dispositions. In November 2004, we sold the compression rental assets of our Canadian subsidiary, Hanover Canada Corporation, to Universal Compression Canada, a subsidiary of Universal Compression Holdings, Inc., for approximately $56.9 million. Additionally, in December 2004 we sold our ownership interest in Collicutt Energy Services Ltd. (“CES”) for approximately $2.6 million to an entity owned by Steven Collicutt. Hanover owned approximately 2.6 million shares in CES, which represented approximately 24.1% of the ownership interest of CES. These businesses are reflected as discontinued operations in our consolidated statement of operations. The sale of our Canadian compression rental fleet and our interest in CES resulted in a $2.1 million gain, net of tax.

      During October 2004, we sold an asset held for sale related to our discontinued power generation business for approximately $7.5 million and realized a gain of approximately $0.7 million. This asset was sold to a subsidiary of The Wood Group. The Wood Group owns 49.5% of the Simco/ Harwat Consortium, a joint venture gas compression project in Venezuela in which we hold a 35.5% ownership interest.

      On March 5, 2004, we sold our 50.384% limited partnership interest and 0.001% general partnership interest in Hanover Measurement Services Company, L.P. (“Hanover Measurement”) to EMS Pipeline Services, L.L.C. for $4.9 million. We accounted for our interest in Hanover Measurement under the equity method. As a result of the sale, we recorded a $0.3 million gain that is included in other revenue.

      Securities Class Actions. On October 23, 2003, we entered into a Stipulation of Settlement to settle all of the claims underlying the putative securities class action, the putative ERISA class action and the shareholder derivative actions that were filed against the Company. The terms of the settlement required 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.

      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 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 therefore became final and was implemented according to its terms. Our independent registered public accounting firm, PricewaterhouseCoopers LLP, is not a party to the settlement and remains a party to the securities class action. (See Item 7 “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 securities litigation settlement.”)

      In April 2004, we issued the $6.7 million contingent note related to the securities settlement. The note was extinguished (with no money owing under it) during the third quarter of 2004 under the terms of the note since our common stock traded above the average price of $12.25 per share for 15 consecutive trading days. As a result of the cancellation of the note in the third quarter of 2004, we reversed the note and the embedded derivative, which resulted in a $4.0 million reduction to the cost of the securities-related litigation.

      As part of the settlement, we implemented certain corporate governance enhancements, allowed 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 made certain changes to our code of conduct.

      GKH Investments, L.P. and GKH Private Limited (collectively “GKH”), which formally owned more than 10% of our outstanding common stock and which sold shares in our March 2001 secondary offering of common stock, were parties to the settlement and agreed to settle claims against them that arose out of that offering as well as other potential securities, ERISA, and derivative claims. We understand that in April 2004 GKH transferred 2.5 million shares of our common stock from their holdings or from other sources to the settlement fund as required by the terms of the settlement.

      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.

Industry Overview

Natural 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 and processing 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 oil and natural gas producers and have caused producers, as well as oil and natural gas transporters and processors, to increasingly outsource their non-core compression activities to specialists such as us.

      The advent of rental and contract compression over forty years ago made it possible for oil and natural gas producers, natural gas 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, we believe certain large U.S. oil and natural gas companies are seeking to streamline their operations and reduce their capital expenditures and other costs. To this end, they have sold certain U.S. 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:

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 and processing 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 and processing 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.

      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 and tank farms, 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 and processing equipment is the growing global consumption of natural gas. As more gas is consumed, the demand for compression and production and processing 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 and processing 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 international natural gas consumption has grown recently. Despite this growth in energy demand, most international 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:

      The U.S. and international compression rentals segments have operations primarily in the United States 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 which accounted for 10% or more of consolidated revenue in any of the last three fiscal years, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Form 10-K and Note 24 to the Notes to Consolidated Financial Statements in Item 15 of this Form 10-K.

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, 2004, our compressor fleet consisted of 6,589 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, market conditions 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 U.S. compression rental business. Such price increases, along with an improvement in market conditions, resulted in a 5% increase in revenue from our U.S. rental business in the year ended December 31, 2004 as compared to the year ended December 31, 2003. 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 U.S. applications.

      We believe 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%. We are able to offer this level of commitment due largely to our 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.

      Our rental fleet units are serviced at manufacturers’ recommended maintenance intervals, modified as required by the particular 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 our 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.

      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 personnel receive regular mechanical and safety training both from our staff and our vendors. Each of our field mechanics is responsible for specific compressor unit installations and has at his or her disposal a dedicated local parts inventory. Additionally, each field mechanic operates from a fully equipped service vehicle. Each mechanic’s field service vehicle is equipped with a radio or cellular telephone, which allows that individual to be our primary contact with the customer’s field operations staff and to be contacted at either his or her residence or mobile phone 24 hours a day. Accordingly, our field service mechanics are given the responsibility to promptly respond to customer service needs as they arise based on the mechanic’s trained judgment and field expertise.

      We believe 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, 2004, we had a compressor unit fabrication backlog for sale to third parties of $56.7 million compared to $28.2 million at December 31, 2003. 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, 2004 is summarized in the following table.

      Through our production and processing equipment fabrication division, we design, engineer, fabricate, sell and rent a broad range of oil and gas production and processing 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, 2004, we had a production and processing equipment fabrication backlog of $234.2 million compared to $124.8 million at December 31, 2003, including Belleli’s backlog of $150.0 million and $106.7 million at December 31, 2004 and 2003, respectively. Typically, we expect our production and processing equipment backlog to be produced within a three to thirty-six month period. At December 31, 2004, approximately $9.6 million of future revenue related to our production and processing equipment backlog was expected to be recognized after December 31, 2005. 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 and tank farms, primarily for use in Europe and the Middle East.

      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, installation services and oilfield-related power generation sales and services. In addition, we purchase and recondition used gas compression units, oilfield power generation and treating facilities and production and processing equipment that is then sold or rented to customers. We maintain parts inventories for our own use and to meet our customers’ needs. As of December 31, 2004, we had approximately $135.8 million in parts and supplies inventories.

      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. In addition, we fabricate heavy wall reactors for refineries and other vessels used in production, processing and treating of crude oil and natural gas. Steel is a commodity which can have wide

price fluctuations and represents a significant portion of the raw materials for these 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.

      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 and processing 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 2004, 2003 or 2002.

      Our rental and sales activities are conducted throughout the continental United States, internationally and in offshore operations. International locations include Argentina, Canada, Italy, United Arab Emirates, Equatorial Guinea, India, Venezuela, Colombia, Trinidad, Bolivia, Brazil, Mexico, Peru, Pakistan, Indonesia, Nigeria, United Kingdom and Russia. We have fabrication facilities in the United States, Canada, Italy, UAE and the United Kingdom. In addition, we have representative offices in the Netherlands and the Cayman Islands. As of December 31, 2004, equipment representing approximately 23% of our compressor rental fleet horsepower was being used in international applications.

      Our salespeople pursue the rental and sales market for compressors and production and processing 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. 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.

      We believe that we are currently the largest provider of rental natural gas compression equipment and services 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 our 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. Additionally, 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 and availability. Our competition in the custom engineered market usually consists of larger companies that have the ability to provide integrated projects and product support after the sale. Increasingly, the ability to fabricate these large custom-engineered systems near to the point of end-use is a major competitive advantage.

      We are subject to various federal, state, local and international laws and regulations relating to occupational health and safety and the environment 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 may require us to operate, on behalf of a specific customer, petroleum storage units such as underground tanks, or pipelines and other regulated units, all of which may impose additional regulatory compliance and permitting obligations. Failure to comply with these occupational health and safety and environmental laws and regulations or associated permits may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial obligations, and the issuance of injunctions as to future compliance. Moreover, as with any owner or operator of real property, we are subject to clean-up costs and liability for regulated substances or any other toxic or hazardous wastes that may exist on or have been released under any of our properties.

      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, nor can we control another entity’s willingness or ability, solvent or insolvent, to fund the remediation of their contamination of our existing properties or properties where we operate when such liability is established. Moreover, the production of atmospheric emissions of regulated substances, and the handling of petroleum products and other regulated substances is a normal part of our operations and we have experienced occasional minor spills, incidental leakages and emission rates in excess of permit limits 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 quantities regulated under RCRA. 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 by companies sub-contracted to us. In addition, many of these properties have been previously owned or 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. At two of our owned sites, we are currently working with prior owners who have undertaken the full legal obligations to monitor and/or clean-up contamination at such sites that occurred prior to our acquisition of them. 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 governmental bodies 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.

      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 with newly enacted legislation as it emerges. 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 30, 2004, the Texas Commission on Environmental Quality (“TCEQ”) informed us that it was pursuing an enforcement action against us for alleged violations of the Texas Health and Safety Code and Commission Rules at a gas processing plant owned and operated by us in Madison County, Texas. The alleged violations included failure to comply with certain permit limitations relating to sulfur emissions during certain periods in 2003 and 2004 and failure to provide certain required notifications in connection therewith. After meeting with us, TCEQ issued a revised proposed Agreed Order dated August 30, 2004 outlining the terms of settlement pertaining to the allegations. We executed the August 30, 2004 proposal, and submitted payment for same to TCEQ on September 9, 2004 in the amount of $46,200. Final TCEQ commission approval of the settlement was scheduled for February 9, 2005, but was deferred for the administrative convenience of TCEQ. We have not been advised of the new hearing date.

      On June 21, 2004, an inspector representing California’s South Coast Air Quality Management District (“AQMD”) conducted an inspection at one of our compressed natural gas (“CNG”) fueling stations in Los Angeles, California. At the conclusion of the inspection, we received a Notice of Violation from the inspector that alleged emission rates of certain regulated engine exhaust products were in excess of air quality permit limits. Hanover representatives met with AQMD in Los Angeles and agreed to the terms by which we would upgrade the subject equipment under an Order of Abatement that was subsequently executed by us on August 25, 2004. We met again with AQMD in Los Angeles on several occasions relative to the alleged emission violations for which we received the original June 21st Notice of Violation and negotiated a final Settlement Agreement in respect of all allegations, which we signed on November 18, 2004. Under the terms of the Agreement, Hanover will pay a total penalty of $69,000 in monthly installments which commenced on November 30, 2004 and conclude on May 30, 2005.

      We believe that we are currently in substantial compliance with environmental laws and regulations and other known regulatory requirements. 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 international governmental controls and restrictions pertaining to the environment and other regulated activities in the countries in which we operate. We believe our operations are in substantial compliance with existing international governmental controls and restrictions and that compliance with these international 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 international 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, 2004, of the approximately 758,000 horsepower of compression we had deployed internationally, approximately 93% was located in Latin America (primarily in Venezuela, Argentina and Mexico). Changes in local economic or political conditions, particularly in Venezuela, Argentina and other parts of Latin America, could have a material adverse effect on our business, consolidated financial

condition, results of operations and cash flows. Additional risks inherent in our international business activities include the following:

      In addition, our future plans involve expanding our business in international markets where we currently do not conduct business. The risks inherent in establishing 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 the value of these currencies relative to the U.S. dollar.

      At December 31, 2004 we had intercompany advances outstanding to our subsidiary in Italy of approximately $55.0 million. These advances are denominated in U.S. dollars. The impact of the remeasurement of these advances on our statement of operations by our subsidiary will depend on the outstanding balance in future periods. The remeasurement of these advances in 2004 resulted in a translation gain of approximately $3.7 million.

      For the year ended December 31, 2004, our Argentine operations represented approximately 6% of our revenue and 9% of our gross profit. For the year ended December 31, 2004, our Venezuelan operations represented approximately 12% of our revenue and 21% of our gross profit. At December 31, 2004, we had approximately $17.3 million and $22.4 million in accounts receivable related to our Argentine and Venezuelan operations, respectively.

      The following table summarizes the exchange gains and losses we recorded for assets exposed to currency translation (in thousands):

      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 dropped. 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 be materially and adversely affected, which could result in reductions in our net income. For example, as a result of the disruption in our operations in Venezuela, during the fourth quarter of 2002, our international rental revenues decreased by approximately $2.7 million due to concerns about the ultimate receipt of those revenues. Although we were able to realize those revenues in 2003, no assurances can be given that this will be the result if a similar situation occurred in the future.

      In February 2003, the Venezuelan government fixed the exchange rate to 1,600 bolivars for each U.S. dollar. In February 2004 and March 2005, the Venezuelan government devalued the currency to 1,920 bolivars and 2,148 bolivars, respectively, for each U.S. dollar. The impact of any further devaluation on our results will depend upon the amount of our assets (primarily working capital) exposed to currency fluctuation in Venezuela in future periods.

      The economic situation in Argentina and Venezuela is subject to change. To the extent that the situation deteriorates, exchange controls continue in place and the value of the peso and bolivar against the dollar is reduced further, our results of operations in Argentina and Venezuela could be materially and adversely affected which could result in reductions in our net income.

      As part of our 2001 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. At December 31, 2004, we had approximately $89.2 million invested in these non-consolidated affiliates.

      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 (“Cawthorne Channel Project”) 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 substantially completed the building of the required barge-mounted facilities. Under the terms of a series of contracts between Global and us, Shell, and several other counterparties, respectively, Global is responsible for the development of the overall project. In light of the political environment in Nigeria, Global’s capitalization level and 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 these contracts.

      This project and our other projects in Nigeria are subject to numerous risks and uncertainties associated with operating in Nigeria. Such risks include, among other things, political, social and economic instability, civil uprisings, riots, terrorism, the taking of property without fair compensation and governmental actions that may restrict payments or the movement of funds or result in the deprivation of contract rights. Any of these risks as well as other risks associated with a major construction project could materially delay the anticipated commencement of operations of the Cawthorne Channel Project or impact any of our operations in Nigeria. Any such delays could affect the timing and decrease the amount of revenue we may realize from our investments in Nigeria. 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. At December 31, 2004, we had an investment of approximately $60.3 million in projects in Nigeria, a substantial majority of which related to the Cawthorne Channel Project. We currently anticipate investing

an additional $10 million in the Cawthorne Channel Project during 2005. In addition, we have approximately $4.2 million associated with advances to, and our investment in, Global.

      In July 2004, Wilpro Energy Services (PIGAP II) Limited (“PIGAP II”) received a notice of default from the Venezuelan state oil company, PDVSA, alleging that PIGAP II was not in compliance under a services agreement as a result of certain operational issues. PIGAP II is a joint venture, currently owned 70% by a subsidiary of The Williams Companies, Inc. (“Williams”) and 30% by Hanover, that operates a natural gas compression facility in Venezuela. While PIGAP II advised us that it did not believe a basis existed for such notice of default, the giving of the notice of default by PDVSA could be deemed an event of default under PIGAP II’s outstanding project loans totaling approximately $207.7 million. PIGAP II sought a waiver of this potential default from its lenders, and the lenders under the PIGAP II project loan agreement have waived any potential default under the loan documents. Additionally, in January 2005, PDVSA advised PIGAP II that there were no events of default under the services agreement in existence at that time. Hanover’s net book investment in PIGAP II at December 31, 2004 was approximately $33.5 million and Hanover’s pretax income with respect to PIGAP II for the year ended December 31, 2004 was approximately $12.2 million.

      For financial data relating to the Company’s geographic concentrations, see Note 24 to the Notes to Consolidated Financial Statements included in Item 15 of this Form 10-K.

Executive Officers of the Registrant

      The following sets forth, as of March 9, 2005, the name, age and prior business experience of each of our executive officers:

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

      John E. Jackson was elected President and Chief Executive Officer in October 2004 and as a director in July 2004. Mr. Jackson joined Hanover in February 2002 as Senior Vice President and Chief Financial Officer. 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.

      Gary M. Wilson was appointed Senior Vice President, General Counsel and Secretary effective May 15, 2004. Since 1985, Mr. Wilson served Schlumberger Limited in various positions of increasing responsibility, including Deputy General Counsel of Schlumberger Oilfield Services. Most recently, Mr. Wilson acted as General Counsel of WesternGeco, a joint venture between Schlumberger and Baker Hughes Inc., a position he held since 2000. Mr. Wilson began his career in 1981 with the law firm of Richards Butler, based in Abu Dhabi and London.

      Lee E. Beckelman was appointed Vice President and Chief Financial Officer on January 26, 2005. Mr. Beckelman joined Hanover in December 2002 and served as Vice President of Investor Relations and Corporate Development. Prior to joining Hanover, Mr. Beckelman was Vice President of J.P. Morgan Securities Inc. (previously Chase Securities Inc.) where he was responsible for the marketing and

structuring of syndicated loans, primarily for companies in the energy industry. Prior to joining J.P. Morgan Securities Inc. in July 1995, Mr. Beckelman also worked in energy project finance and development for Bechtel Enterprises and Transworld Oil USA and began his career in 1988 with Texas Commerce Bank.

      Anita H. Colglazier was appointed Vice President and Controller on March 9, 2005. Ms. Colglazier joined Hanover in 2002 and served as Director, Financial Reporting and Policy until her recent appointment. Prior to joining Hanover, Ms. Colglazier held various management and accounting positions during her 18 years with Union Pacific Resources Company (“UPRC”), including Assistant Controller. Anadarko Petroleum acquired UPRC in July 2000. After the acquisition through her departure in 2002, Ms. Colglazier worked as an accounting manager supporting the transition and integration of UPRC into Anadarko. Prior to joining UPRC, Ms. Colglazier was an auditor with Deloitte, Haskins & Sells.

      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 was appointed Vice President — Investor Relations and Technology on March 9, 2005. Mr. York joined Hanover in April 2002 and served as Vice President and Corporate Controller until his recent appointment. 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, during 2001 and early 2002. From 1981 to 2000, Mr. York held various management positions of increasing responsibility 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 a senior accountant with KPMG Peat Marwick in Waco, TX, from 1979 to 1981.

      Mickey McDonald has served as Vice President — U.S. Operations since 2003. From 1990 to 2003, Mr. McDonald served in a variety of management positions at Hanover, including Vice President of the U.S. Southeastern Region. Mr. McDonald was President of C&B Compression Services from 1980 to 1990, when it was acquired by Hanover.

      Steve W. Muck has served as Vice President — International Operations since 2000. From 1994 to 2000, Mr. Muck served as Vice President of Worldwide Operations of Dresser-Rand. In addition, Mr. Muck held positions in sales and marketing with Dresser-Rand and its predecessor, Ingersoll Rand, from 1975 to 1994.

      Hilary S. Ware has served as Vice President — Human Resources Worldwide since 2002. From 2001 to 2002, Ms. Ware was a principal of DeNovo Partners. For 23 years, Ms. Ware served British Petroleum and its affiliates in various human resource positions of increasing responsibility, including Director of Human Resource Integrated Services from 1997 to 2001.

Employees

      As of December 31, 2004, we had approximately 5,900 employees, approximately 300 of whom are represented by a labor union. Additionally, we had approximately 700 contract personnel. We believe that our relations with our employees and contract personnel are satisfactory.

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.

      Hanover has adopted “P.R.I.D.E. in Performance — Hanover’s Guide to Ethical Business Conduct” (“Code of Ethics”) that applies to our directors, officers and employees, including our principal executive officer, principal financial officer and principal accounting officer. Our Code of Ethics is posted on the Company’s website at http://www.hanover-co.com. Any changes to, and/or waivers granted, with respect to our Code of Ethics relating to our principal executive officer, principal financial officer, principal accounting officer, and other executive officers and directors of Hanover that we are required to disclose pursuant to applicable rules and regulations of the Securities and Exchange Commission will be posted on our website. Upon request the Company will provide a copy of our Code of Ethics without charge. Such request can be made in writing to the Corporate Secretary at Hanover Compressor Company, 12001 North Houston Rosslyn Road, Houston, Texas 77086.

      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) 405-2111. 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, 2004:

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

      In the ordinary course of business we are involved in various 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, 2004.

PART II

      Our common stock is listed on the New York Stock Exchange under the symbol “HC.” As of March 4, 2005, 87,053,366 shares of our common stock were issued and held by 676 holders of record. On March 4, 2005, the last reported sales price of our common stock on the New York Stock Exchange was $13.31. 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 or 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 compensation plans.

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, 2004. 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.

      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 in Item 15 of this Form 10-K.

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, and oilfield power generation services, primarily to our U.S. 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 and tank farms, 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 lease obligations, increased from approximately $572 million at December 31, 1999 to approximately $1,736 million at December 31, 2001. As a result of these acquisitions, we inherited not only different accounting and reporting systems, but also different policies, procedures and philosophies for operating the business, none of which were integrated and standardized.

      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 officers and directors were named as defendants in a consolidated action 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 now been settled.

      We believe we made significant strides in 2004 towards realizing our objectives to develop our total solutions capabilities, expand our global presence and improve our financial stability. During 2004, our key accomplishments included:

      Our key areas of focus for 2005 include:

      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. 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. Although our revenues increased during 2004, which we believe resulted from an improvement in market conditions and our focus on sales success ratio, our gross profit margins have not significantly improved. In 2005, we intend to focus on improving our operating margins.

      The North American rig count increased by 10% to 1,686 at December 31, 2004 from 1,531 at December 31, 2003, and the twelve-month rolling average North American rig count increased by 11% to 1,559 at December 31, 2004 from 1,404 at December 31, 2003. In addition, the twelve-month rolling average New York Mercantile Exchange wellhead natural gas price increased to $6.14 per MMBtu at December 31, 2004 from $5.39 per MMBtu at December 31, 2003. 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 U.S. rentals of equipment by our customers, which we believe is primarily the result of the lack of a significant increase in U.S. natural gas production levels.

      Net losses. We recorded a consolidated net loss of $44.0 million for the year ended December 31, 2004, as compared to consolidated net losses of $208.3 and $116.1 million and for the years ended December 31, 2003 and 2002, respectively. Our results for the years ended 2003 and 2002 were 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):

      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 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 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. During 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.

      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 facilities in addition to the four fabrication facilities we closed pursuant to our original reduction plan. During the year ended December 31, 2004, we paid an additional $0.7 million in employee separation costs related to the completion of these activities. From December 31, 2002 to December 31, 2004, our U.S. headcount has decreased by approximately 600 employees.

      In May 2003, Hanover reached an agreement that was subject to court approval, to settle securities class actions, ERISA class actions and the shareholder derivative actions filed against Hanover as described under “Year ended December 31, 2003 compared to year ended December 31, 2002 — Provision for Securities Litigation Settlement.” The terms of the settlement became final in March 2004 and provided for Hanover to: (a) make a cash payment of approximately $30 million to the securities settlement fund (of which $26.7 million was funded by payments from Hanover’s directors and officers insurance carriers), (b) issue 2.5 million shares of Hanover common stock, and (c) issue a contingent note with a principal amount of $6.7 million. The contingent feature was determined to be a derivative that we recorded as an asset, as required by SFAS 133.

      In April 2004, we issued the $6.7 million contingent note related to the securities settlement. The note was payable, together with accrued interest, on March 31, 2007 but was extinguished (with no money owing under it) during the third quarter of 2004 under the terms of the note since our common stock traded above the average price of $12.25 per share for 15 consecutive trading days. As a result of the cancellation of the note in the third quarter of 2004, we reversed the note and the embedded derivative, which resulted in a $4.0 million reduction to the cost of the securities-related litigation.

      During the years ended December 31, 2004 and 2003, respectively, we recorded income of $4.2 million and a $43.0 million charge, respectively, for the cost of the litigation settlement. For further details regarding the securities settlement, see Note 20 to the Notes to the Consolidated Financial Statements in Item 15 of this Form 10-K.

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, revenue recognition and contingencies and litigation. We base our estimates on historical experience and on other assumptions that we believe are reasonable under the circumstances. The results of this process form the basis of our judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates

under different assumptions or conditions and these differences can be material to our financial condition, results of operations and liquidity.

      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. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our existing accounts receivable. We determine the allowance based on historical write-off experience. We review the adequacy of our allowance for doubtful accounts monthly. Balances aged greater than 90 days are reviewed individually for collectibility. In addition, all other balances are reviewed based on significance and customer payment histories. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. As of December 31, 2004, our largest account receivable from a customer was approximately $9.1 million. During 2004, 2003 and 2002, we recorded approximately $2.7 million, $4.0 million, and $7.1 million in additional allowances for doubtful accounts, respectively.

      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 2004, 2003 and 2002, we recorded approximately $1.1 million, $1.5 million, and $13.9 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 and assets held for sale 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. There was no significant impairment in 2004. 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 or whenever events indicate impairment may have occurred, 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 affect 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. There were no impairments in 2004 related to our annual goodwill impairment test. During 2003 and 2002, we recorded $35.5 million and $52.1 million, respectively, in goodwill impairments as a result of evaluations of our goodwill.

      We hold investments in companies having operations or technology in areas that relate to our business. 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 in the future.

      We must estimate our expected future taxable income in order to assess the realizability of our deferred income tax assets. As of December 31, 2004, we reported a net deferred tax liability of $40.9 million, which included gross deferred tax assets of $362.9 million, net of a valuation allowance of $65.4 million and gross deferred tax liabilities of $338.4 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 tax liabilities recognized or the amount of any valuation allowance recognized against deferred tax assets. We must also consider if we have the ability to implement 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 international subsidiaries. Assumptions related to the permanent reinvestment of the earnings of international subsidiaries are reconsidered periodically to give effect to changes in our businesses and in our tax profile.

      As a result of recent operating losses, 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 U.S. losses, we cannot reach the conclusion that it is “more likely than not” that certain of our U.S. deferred tax assets will be realized in the future. We will be required to record additional valuation allowances if our U.S. deferred tax asset position is increased and the “more likely than not” criteria of SFAS 109 is not met. In addition, we have recorded valuation allowances for certain international jurisdictions. If we are required to record additional valuation allowances in the United States or any other jurisdictions, our effective tax rate will be impacted, perhaps substantially, compared to the statutory rate. Our preliminary analysis leads us to believe that we will likely be required to record additional valuation allowances in 2005, unless we are able to generate additional taxable earnings or implement additional tax planning strategies that would minimize or eliminate the amount of such additional valuation allowance.

      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

change orders, availability of raw materials and the impact of delayed performance. If the aggregate combined cost estimates for all of our fabrication businesses had been higher or lower by 1% in 2004, our results of operations before tax would have been decreased or increased by approximately $3.9 million. As of December 31, 2004, we had recognized approximately $49.6 million in estimated earnings on uncompleted contracts.

      We are substantially self-insured for worker’s compensation, employer’s liability, property, auto liability, general liability and employee group health claims in view of the relatively high per-incident deductibles we absorb under our insurance arrangements for these risks. Losses up to deductible amounts are estimated and accrued based upon known facts, historical trends and industry averages. We review these estimates quarterly and believe such accruals to be adequate. However, insurance liabilities are difficult to estimate due to unknown factors, including the severity of an injury, the determination of our liability in proportion to other parties, timely reporting of occurrences, ongoing treatment or loss mitigation, general trends in litigation recovery outcomes and the effectiveness of safety and risk management programs. Therefore, if actual experience differs from the assumptions and estimates used for recording the liabilities, adjustments may be required and would be recorded in the period that the experience becomes known. As of December 31, 2004 and 2003, we had approximately $3.2 million and $4.4 million, respectively, in claim reserves.

      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.

Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

      For the year ended December 31, 2004, revenue increased to $1,188.6 million over 2003 revenue of $1,075.1 million. Net loss for the year ended December 31, 2004, was $44.0 million, compared with a net loss of $208.3 million in 2003. As detailed in the chart below, included in the 2003 net loss was $250.6 million in pre-tax charges.

      Included in the net loss for 2004 were the following pre-tax charges (in thousands):

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

U.S. Rentals

(in thousands)

      U.S. rental revenue increased during the year ended December 31, 2004, compared to the year ended December 31, 2003, due primarily to improvement in market conditions that has led to an improvement in pricing. Gross margin for the year ended December 31, 2004 decreased compared to the year ended December 31, 2003, primarily due to increased maintenance and repair expense.

International Rentals

(in thousands)

      For 2004, international rental revenue and gross profit increased, compared to 2003, due to increased compression and processing plant rental activity, primarily in Argentina, Brazil and Mexico, and the addition of two gas processing plants in Mexico and Brazil added in the third quarter of 2003. The increase in revenues in these areas led to an increase in our international rental gross margin in 2004. Our 2003 revenue and gross margin were positively impacted by approximately $2.7 million in revenue that was related to services performed during 2002 but was not recognized until 2003 due to concerns about the ultimate receipt as a result of the strike by workers of the national oil company in Venezuela. As of December 31, 2004, we had approximately 758,000 horsepower of compression deployed internationally, compared to approximately 842,000 horsepower of compression deployed internationally at December 31, 2003. Our international horsepower deployed decreased by approximately 100,000 horsepower in 2004 due to the sale of our rental fleet in Canada.

Parts, Service and Used Equipment

(in thousands)

      Parts, service and used equipment revenue for the year ended December 31, 2004 was higher than the year ended December 31, 2003 due primarily to increased demand by our international parts and service business. Parts, service and used equipment revenue includes two business components: (1) parts and service and (2) used rental equipment and installation sales. For the year ended December 31, 2004, parts and service revenue was $139.3 million with a gross margin of 24%, compared to $125.5 million and 29%, respectively, for the year ended December 31, 2003. The decrease in margins was primarily due to a decrease in margins by our U.S. parts and service business, which has not performed as anticipated. Used

rental equipment and installation sales revenue in the year ended December 31, 2004 was $41.1 million with a gross margin of 27%, compared to $39.4 million with a 14% gross margin for the year ended December 31, 2003. Our used rental equipment and installation sales and gross margins vary significantly from period to period and are dependent on the exercise of purchase options on rental equipment by customers and the start-up of new projects by customers.

Compression and Accessory Fabrication

(in thousands)

      For the year ended December 31, 2004, compression fabrication revenue and gross profit increased primarily due to our increased focus on fabrication sales and an improvement in market conditions. As of December 31, 2004, we had compression fabrication backlog of $56.7 million compared to $28.2 million at December 31, 2003.

Production and Processing Equipment Fabrication

(in thousands)

      Production and processing equipment fabrication revenue for the year ended December 31, 2004 was greater than for the year ended December 31, 2003, primarily due to our increased focus on fabrication sales and an improvement in market conditions. We have focused on improving our sales success ratio on new bid opportunities which has resulted in the 2004 improvement in our production and processing equipment backlog. As of December 31, 2004, we had a production and processing equipment fabrication backlog of $234.2 million compared to $124.8 million at December 31, 2003, including Belleli’s backlog of $150.0 million and $106.7 million at December 31, 2004 and 2003, respectively.

      Equity in income of non-consolidated affiliates decreased by $3.2 million to $19.8 million during the year ended December 31, 2004, from $23.0 million during the year ended December 31, 2003. This decrease is primarily due to the sale of Hanover Measurement in the first quarter of 2004 and a decrease in results from our equity interest in Simco and PIGAP II joint venture. PIGAP II experienced an increase in interest expense during the year ended December 31, 2004 compared to the year ended December 31, 2003 as a result of the completion of PIGAP II’s project financing in October 2003. The decrease in equity earnings for the Simco/Harwat Consortium was due to a major plant refurbishment during 2004. The decrease in equity earnings of unconsolidated entities was partially offset by the $3.3 million increase in El Furrial earnings for the year ended December 31, 2004 due to an improvement in operating results. In 2003, El Furrial experienced a fire which negatively impacted operating results.

      On March 5, 2004, we sold our 50.384% limited partnership interest and 0.001% general partnership interest in Hanover Measurement to EMS Pipeline Services, L.L.C. for $4.9 million. We accounted for

our interest in Hanover Measurement under the equity method. As a result of the sale, we recorded a $0.3 million gain that is included in other revenue.

      Selling, general, and administrative expense (“SG&A”) for both 2004 and 2003, as a percentage of revenue, was 15%. SG&A expense in 2004 was $173.1 million compared to $159.9 million in 2003. The increase over 2003 was primarily due to the inclusion of approximately $6.4 million of additional auditing and consulting costs related to our efforts in connection with the implementation of Section 404 of the Sarbanes-Oxley Act of 2002, increased severance expense of approximately $2.3 million, increased relocation and office start up expenses for new offices and personnel in Russia and increased municipal taxes due to increased business activity, primarily in Latin America.

      Depreciation and amortization expense for 2004 was $175.3 million, compared to $169.2 million in 2003. The increase in depreciation and amortization was primarily due to: (1) net additions to property, plant and equipment placed in service during the year; (2) approximately $8.5 million in additional depreciation expense associated with the compression equipment operating leases that were consolidated into our financial statements in the third quarter of 2003; and (3) $1.7 million in amortization to write-off deferred financing costs associated with the June 2004 refinancing of our 2000A compression equipment obligations and early payoff of a portion of our 2000B compression equipment lease obligations. There were no significant asset impairments in 2004. During 2003, we recorded $14.3 million of impairments for idle rental fleet assets to be sold or scrapped.

      Beginning in July 2003, payments accrued under our sale leaseback transactions are included in interest expense as a result of consolidating on our balance sheet the entities that lease compression equipment to us. As a result, during the year ended December 31, 2004 as compared to the year ended December 31, 2003, our interest expense increased $57.8 million to $147.0 million and our leasing expense decreased $43.1 million to $0. The increase in our combined interest and leasing expense was primarily due to an increase in the overall effective interest rate on outstanding debt to 8.4% from 7.3% during the years ended December 31, 2004 and 2003, respectively.

      Foreign currency translation for the year ended December 31, 2004 was a gain of $5.2 million, compared to a loss of $2.5 million for the year ended December 31, 2003. For the year ended December 31, 2004, foreign currency translation included $4.5 million in translation gains related to the re-measurement of our international subsidiaries’ dollar denominated inter-company debt.

      The following table summarizes the exchange gains and losses we recorded for assets exposed to currency translation (in thousands):

      At December 31, 2004 we had intercompany advances outstanding to our subsidiary in Italy of approximately $55.0 million. These advances are denominated in U.S. dollars. The impact of the remeasurement of these advances on our statement of operations by our subsidiary will depend on the outstanding balance in future periods. The remeasurement of these advances in 2004 resulted in a translation gain of approximately $3.7 million.

      For the year ended December 31, 2003, other expenses included $2.9 million in charges primarily recorded to write-off certain non-revenue producing assets and to record the settlement of a contractual obligation.

      During 2003, we recorded a $35.5 million non-cash charge for goodwill impairment associated with Belleli. 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. During 2003, we determined the present value of Belleli’s expected future cash flows was less than our carrying value of Belleli.

      In May 2003, Hanover reached agreement that was subject to court approval, to settle securities class actions, ERISA class actions and the shareholder derivative actions. The terms of the settlement became final in March 2004 and required Hanover to: (a) make a cash payment of approximately $30 million to the securities settlement fund (of which $26.7 million was funded by payments from Hanover’s directors and officers insurance carriers), (b) issue 2.5 million shares of Hanover common stock, and (c) issue a contingent note with a principal amount of $6.7 million.

      In April 2004, we issued the $6.7 million contingent note related to the securities settlement. The note was payable, together with accrued interest, on March 31, 2007 but was extinguished (with no money owing under it) under the terms of the note since our common stock traded above the average price of $12.25 per share for 15 consecutive trading days during the third quarter of 2004. As a result of the cancellation of the note in the third quarter of 2004, we reversed the note and the embedded derivative, which resulted in a $4.0 million reduction to the cost of the securities-related litigation.

      The provision for income taxes increased $21.2 million, to $24.8 million for the year ended December 31, 2004 from $3.6 million for the year ended December 31, 2003. The average effective income tax rates during the year ended December 31, 2004 and December 31, 2003 were (84.5%) and (3.2%), respectively. The change in rate was primarily due to the following factors: (1) significant decrease in losses before tax during the year ended December 31, 2004, (2) decrease in the valuation allowance recorded for U.S. deferred tax assets where realization is uncertain, and (3) inclusion in taxable income of earnings repatriated from Canada.

      As a result of current year operating losses 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 U.S. tax losses over the past three years, we cannot reach the conclusion that it is “more likely than not” that certain of our U.S. deferred tax assets will be realized in the future. We will be required to record additional valuation allowances if our U.S. deferred tax asset position is increased and the “more likely than not” criteria of SFAS 109 is not met. In addition, we have provided valuation allowances for certain international jurisdictions. If we are required to record additional valuation allowances in the United States or any other jurisdictions, our effective tax rate will be impacted, perhaps substantially compared to the statutory rate. Our preliminary analysis leads us to believe that we will likely be required to record additional valuation allowances in 2005, unless we are able to generate additional taxable earnings or implement additional tax planning strategies that would minimize or eliminate the amount of such additional valuation allowance. In addition, we may be required to record additional valuation allowances in future periods.

      During the fourth quarter of 2004, we sold the compression rental assets of our Canadian subsidiary, Hanover Canada Corporation, to Universal Compression Canada, a subsidiary of Universal Compression Holdings, Inc., for approximately $56.9 million. Additionally, in December 2004 we sold our ownership interest in CES for approximately $2.6 million to an entity owned by Steven Collicutt. Hanover owned

approximately 2.6 million shares in CES, which represented approximately 24.1% of the ownership interests of CES.

      During the fourth quarter of 2004, we sold an asset held for sale related to our discontinued power generation business for approximately $7.5 million and realized a gain of approximately $0.7 million. This asset was sold to a subsidiary of The Wood Group. The Wood Group owns 49.5% of the Simco/ Harwat Consortium, a joint venture gas compression project in Venezuela in which we hold a 35.5% ownership interest.

      During the first quarter of 2004, we sold our 50.384% limited partnership interest and 0.001% general partnership interest in Hanover Measurement to EMS Pipeline Services, L.L.C. for $4.9 million. We accounted for our interest in Hanover Measurement under the equity method. As a result of the sale, we recorded a $0.3 million gain that is included in other revenue.

      During the fourth quarter of 2002, we reviewed our business lines and the board of directors approved management’s recommendation to exit and sell our non-oilfield power generation and certain used equipment business lines. In 2003, we recorded an additional $14.1 million charge (net of tax) to write-down our investment in discontinued operations to their current estimated market value. Income from discontinued operations decreased $3.9 million, to net income of $6.3 million during the year ended December 31, 2004, from income of $10.2 million during the year ended December 31, 2003. The decrease in income from discontinued operations was due to the dispositions that occurred in 2004 and 2003. During 2004, we recorded a $2.1 million gain (net of tax) related to the sale of Hanover Canada Corporation and CES.

      We recorded a cumulative effect of accounting change of $86.9 million, net of tax, related to the adoption of FIN 46 on July 1, 2003.

      Prior to July 1, 2003, we had entered into lease transactions that were recorded as a sale and leaseback of the compression equipment and were treated as operating leases for financial reporting purposes. On July 1, 2003, we adopted the provisions of FIN 46 as they relate to the special purpose entities that lease compression equipment to us. As a result of the adoption, we added approximately $1,089 million in compressor equipment assets, $192.3 million of accumulated depreciation (including approximately $58.6 million of accumulated depreciation related to periods before the sale and leaseback of the equipment), $1,105.0 million in debt and $34.6 million in minority interest obligations to our balance sheet, and we reversed $108.8 million of deferred gains that were recorded on our balance sheet as a result of the sale leaseback transactions. On July 1, 2003, we recorded a $133.7 million charge ($86.9 million net of tax) to record the cumulative effect from the adoption of FIN 46 related to prior period depreciation of the compression equipment assets.

      In 2004 and 2003, we exercised our purchase options under our 1999, 2000A and part of our 2000B compression equipment operating leases. As of December 31, 2004, the remaining compression assets owned by the entities that lease equipment to us but are now included in property, plant and equipment in our consolidated financial statements had a net book value of approximately $564.7 million, including improvements made to these assets after the sale leaseback transactions.

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

      For the year ended December 31, 2003, revenue increased to $1,075.1 million over 2002 revenue of $1,013.4 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 U.S. 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 U.S. 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):

      Included in the net loss for 2002 were the following pre-tax charges (in thousands):

U.S. Rentals

(in thousands)

      For 2003, U.S. rental revenues and gross profit decreased from 2002 due to weaker demand, stronger competition, which resulted in lower fleet utilization in the first six months of the year relative to the same period a year earlier, and higher operating expenses, including higher repairs and maintenance and start up costs for a large gas plant in 2003. As a result of lower fleet utilization in the first half of the year, our average U.S. utilization for 2003 was approximately 3% lower than our average utilization for 2002. However, our U.S. rental horsepower utilization rate at December 31, 2003 was 76% compared to 72% at December 31, 2002. The increase in utilization was due to an increase in contracted units, which led to a 2% increase in utilization, the retirement of units to be sold or scrapped and the deployment of units into international operations.

International Rentals

(in thousands)

      For 2003, international rental revenue and gross profit increased, compared to 2002, due to increased compression rental activity, primarily in Argentina and Mexico, and the addition in 2003 of two gas processing plants in Mexico and Brazil.

      Our 2003 revenue and gross margin were positively impacted by approximately $2.7 million in revenue that was not recognized until 2003 due to concerns about its ultimate receipt as a result of the strike by workers of the national oil company in Venezuela. Our 2002 international revenue and gross margin benefited from the inclusion of approximately $9.7 million in revenues from partial reimbursement of foreign currency losses from the renegotiations of contracts with our Argentine customers, discussed further below, but was negatively impacted by approximately $2.7 million in revenues from Venezuelan customers that was not recognized until 2003. These items increased our 2002 revenue by approximately $7.0 million and our gross margin by approximately 1%, net. Excluding these items from our 2002 revenues, our 2003 revenues and operating expenses increased by approximately 14% and 17%, respectively. Gross margin for 2003 decreased, when compared to 2002, due primarily to the inclusion of these revenue items in 2002 and an increase in start-up costs in 2003.

Parts, Service and Used Equipment

(in thousands)

      For 2003, parts, service, and used equipment revenue was lower than 2002 results due primarily to lower used rental equipment and installation sales. Parts, service and used equipment revenue includes two business components: (1) parts and service and (2) used rental equipment and installation sales. Parts and service revenue was $125.5 million with a gross margin of 29% for 2003, compared to $143.9 million in revenue with a gross margin of 22% in 2002. Parts and service revenue declined by approximately $18.4 million due to weaker market conditions. Used rental equipment and installation sales revenue was $39.4 million with a gross margin of 14% compared to $79.8 million with a gross margin of 16% in 2002. The decrease in used rental equipment and installation sales was primarily due to a large gas plant sale transaction that occurred during 2002. The 2002 parts, service, and used equipment gross margin was negatively impacted by approximately 3% due to the $6.8 million inventory write-down and reserves recorded during 2002 for parts, which were either obsolete, excess or carried at a price above market value.

Compression and Accessory Fabrication

(in thousands)

      For 2003, compression fabrication revenue and gross margin declined, compared to 2002, due primarily to strong competition for new orders which negatively affected the selling price and the resulting gross margin and sales and operational disruptions associated with the consolidation of our fabrication facilities.

Production and Processing Equipment Fabrication

(in thousands)

      Production and processing equipment revenue for 2003 increased over 2002 revenue because of the inclusion of a full year of revenue from Belleli. Included in 2003 were $116.8 million in revenue and $105.3 million in expense for Belleli, compared to $15.4 million in revenue and $13.7 million in expense in 2002. In November 2002, we increased our ownership percentage of Belleli to 51% and began including Belleli in our consolidated financial results. Gross margin for production and processing equipment fabrication declined, compared to the same period a year earlier, due primarily to increased competition for our high specification equipment lines, cost overruns on certain projects that we were not able to pass on to respective customers, project delays in anticipated orders, a slow-down in sales activity at Belleli early in the year caused by the war in Iraq, and increased foreign currency exposure due to the strengthening of the Euro and Canadian dollar relative to the U.S. dollar.

      Equity in income of non-consolidated affiliates increased by $4.4 million to $23.0 million during the year ended December 31, 2003, from $18.6 million during the year ended December 31, 2002. This increase is primarily due to an improvement in results from our equity interest in Hanover Measurement and PIGAP II joint venture. During 2002, Hanover Measurement had recorded a goodwill impairment charge and PIGAP II results were negatively impacted by foreign exchange losses.

      SG&A for both 2003 and 2002, as a percentage of revenue, was 15%. SG&A expense in 2003 was $159.9 million compared to $150.9 million in 2002. The increase over 2002 was primarily due to the inclusion of Belleli’s SG&A expense of $11.0 million, compared to $1.2 million in 2002.

      Depreciation and amortization expense for 2003 was $169.2 million, compared to $148.1 million in 2002. The increase in depreciation and amortization was primarily due to: (1) additions to the rental fleet, including maintenance capital, placed in service during the year; (2) the inclusion of $3.0 million of depreciation and amortization from the inclusion of Belleli for a full year; (3) $14.3 million of impairments recorded for idle rental fleet assets to be sold or scrapped; (4) approximately $8.5 million in additional depreciation expense associated with the compression equipment operating leases that were

consolidated into our financial statements in the third quarter of 2003; and (5) $2.5 million in amortization to write-off deferred financing costs associated with the our old bank credit facility and compression equipment lease obligations that were refinanced in December 2003. Depreciation and amortization expense for 2002 included $34.5 million in impairment charges for the reduction in the carrying value of certain idle compression equipment that was retired and the acceleration of depreciation related to certain plants and facilities that were expected to be sold or abandoned. After a review of our idle rental fleet assets in 2002 and 2003, we determined that certain assets should be scrapped or sold rather than repaired. A number of these units were acquired in business acquisitions over the last several years and given our utilization level, we determined not to repair or rebuild them to bring them up to Hanover’s standards.

      Beginning in July 2003, payments accrued under our sale leaseback transactions are included in interest expense as a result of consolidating the entities that lease compression equipment to us. See “— Cumulative Effect Of Accounting Change” below. As a result of this, our interest expense increased $45.8 million, to $89.2 million, and our leasing expense decreased $46.9 million to $43.1 million for the year ended December 31, 2003.

      Our combined interest and leasing expense increased due to the increase in the outstanding balance of our zero coupon note, the inclusion of approximately $1.5 million in interest expense from Belleli and higher effective rates as a result of the February 2003 amendment to our bank credit facility and compression equipment operating leases. These increases were offset by lower interest on our bank credit facility as a result of lower balances outstanding and by a decrease in additional interest paid on leases, explained below.

      In connection with the compression equipment leases entered into in August 2001, we were obligated to prepare registration statements and complete an exchange offer to enable the holders of the notes issued by the lessors to exchange their notes with notes registered under the Securities Act of 1933. Because of the restatement of our financial statements, the exchange offer was not completed pursuant to the time line required by the agreements related to the compression equipment lease obligations and we were required to pay additional lease expense in an amount equal to $105,600 per week until the exchange offering was completed. The additional lease expense began accruing on January 28, 2002 and increased our lease expense by $1.1 million and $5.1 million during 2003 and 2002, respectively. The registration statements became effective in February 2003. The exchange offer was completed and the requirement to pay the additional lease expense ended on March 13, 2003.

      Foreign currency translation expense for the year ended December 31, 2003 was $2.5 million, compared to a $16.7 million for the year ended December 31, 2002. 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. 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. In addition, 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 and recorded translation losses of approximately $0.6 million and $1.0 million, respectively, for all other countries.

      Other expenses decreased by $24.7 million to $2.9 million during the year ended December 31, 2003 from $27.6 million for the year ended December 31, 2002. For the year ended December 31, 2003, other expenses included $2.9 million in charges primarily recorded to write-off certain non-revenue producing assets and to record the settlement of a contractual obligation. For the year ended December 31, 2002,

other expenses included $15.9 million of write-downs and charges related to investments in four non-consolidated affiliates that had experienced a decline in value that we believed to be other than temporary, a $0.5 million write-off of a purchase option for an acquisition that we had abandoned, $2.7 million in other non-operating costs and a $8.5 million write-down of notes receivable, including a $6.0 million reserve established for loans to employees who were not executive officers.

      During 2003, we recorded a $35.5 million non-cash charge for goodwill impairment associated with Belleli. 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. During 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.

      In the fourth quarter 2002, we recorded a $4.6 million goodwill impairment charge related to the write-down of the goodwill associated with our pump division. In addition, in the second quarter 2002, we recorded a $47.5 million goodwill impairment charge on the goodwill associated with our production and processing equipment fabrication business.

      Hanover and certain of its past and present officers and directors were named as defendants in a consolidated federal court action that included a putative securities class action, arising under the Employee Retirement Income Security Act (“ERISA”) and shareholder derivative actions. The litigation related principally to the matters involved in the transactions underlying the restatements of our financial statements. The plaintiffs alleged, among other things, that we and the other defendants acted unlawfully and fraudulently in connection with those transactions and our original disclosures related to those transactions and thereby violated the antifraud provisions of the federal securities laws and the other defendants’ fiduciary duties to Hanover.

      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 required 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. In April 2004, we issued the $6.7 million contingent note related to the securities settlement. The note was payable, together with accrued interest, on March 31, 2007, but was extinguished (with no money owing under it) under the terms of the note since our common stock traded above the average price of $12.25 per share for 15 consecutive trading days during the third quarter of 2004. In addition, upon the occurrence of a change of control that involved us, if the change of control or shareholder approval of the change of control occurred before February 9, 2005, which was twelve months after final court approval of the settlement, we would have been obligated to contribute an additional $3 million to the settlement fund. As part of the settlement, we implemented certain corporate governance enhancements, allowed 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 made certain enhancements to our code of conduct.

      GKH, which, as of December 31, 2003, 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 required 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 set the date for the final hearing. The final hearing was held on February 6, 2004, and no objections to the settlement or requests to be excluded from the terms of the settlement had been received prior to the deadline set by the court.

      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 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 has been 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 registered public accounting firm, 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 the 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 issued was based on the present value of the future cash flows discounted at borrowing rates which were 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 was amortized to interest expense over the term of the note. Because the note could be extinguished without a payment (if our common stock traded 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 were required to record an asset when the note was 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 was marked to market with any increase or decrease included in our statement of operations until extinguished. The note was extinguished with no money owing under it during the third quarter 2004.

      Our income tax expense increased $20.7 million, to a provision of $3.6 million for the year ended December 31, 2003 from a benefit of $17.1 million during the year ended December 31, 2002. The average effective income tax rates for the year ended December 31, 2003 and December 31, 2002 were (3.2)% and

17.6%, respectively. The decrease in rate was primarily due to a $25.7 million valuation allowance recorded for U.S. deferred tax assets where near-term future realization is uncertain and the non-deductible Belleli goodwill impairment.

      As a result of operating losses 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 U.S. tax 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 U.S. 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 impacted, perhaps substantially, compared to the statutory rate.

      During the fourth quarter of 2002, we reviewed our business lines and the board of directors approved management’s recommendation to exit and sell our non-oilfield power generation and certain used equipment business lines. Income from discontinued operations increased $5.7 million, to net income of $10.2 million during the year ended December 31, 2003, from net income of $4.5 million during the year ended December 31, 2002. In 2003, we recorded an additional $14.1 million charge (net of tax) to write-down our investment in discontinued operations to their current estimated market value. During 2002, we recorded a $40.4 million charge (net of tax) related to write-downs of our investment in discontinued operations.

      We recorded a cumulative effect of accounting change of $86.9 million, net of tax, related to the partial adoption of FIN 46 on July 1, 2003.

Leasing Transactions and Accounting Change for FIN 46

      As of December 2004, we are the lessee in three transactions involving the sale of compression equipment by us to special purpose entities, which in turn lease the equipment back to us. At the time we entered into the leases, these transactions had a number of advantages over other sources of capital then available to us. The sale leaseback transactions (1) enabled us to affordably extend the duration of our financing arrangements and (2) reduced our cost of capital.

      In August 2001 and in connection with the acquisition of Production Operators Corporation (“POC”), we completed two sale leaseback transactions involving certain compression equipment. Under one sale leaseback transaction, we received $309.3 million in proceeds from the sale of certain compression equipment. Under the second sale leaseback transaction, we received $257.8 million in proceeds from the sale of additional compression equipment. Under the first transaction, the equipment was sold and leased back by us for a seven-year period and will continue to be deployed by us in the normal course of our business. The agreement calls for semi-annual rental payments of approximately $12.8 million in addition to quarterly rental payments of approximately $0.2 million. Under the second transaction, the equipment was sold and leased back by us for a ten-year period and will continue to be deployed by us in the normal course of our business. The agreement calls for semi-annual rental payments of approximately $10.9 million in addition to quarterly rental payments of approximately $0.2 million. We have options to repurchase the equipment under certain conditions as defined by the lease agreements. We incurred transaction costs of approximately $18.6 million related to these transactions. These costs are included in intangible and other assets and are being amortized over the respective lease terms.

      In October 2000, we completed a $172.6 million sale leaseback transaction of compression equipment. In March 2000, we entered into a separate $200 million sale leaseback transaction of compression equipment. Under the March transaction, we received proceeds of $100 million from the sale of compression equipment at the first closing in March 2000, and in August 2000, we completed the second

half of the equipment lease and received an additional $100 million for the sale of additional compression equipment. Under our 2000 lease agreements, the equipment was sold and leased back by us for a five-year term and will be used by us in our business. We have options to repurchase the equipment under the 2000 lease, subject to certain conditions set forth in these lease agreements. The 2000 lease agreements call for variable quarterly payments that fluctuate with the London Interbank Offering Rate and have covenant restrictions similar to our bank credit facility. We incurred an aggregate of approximately $7.1 million in transaction costs for the leases entered into in 2000, which are included in intangible and other assets on the balance sheet and are being amortized over the respective lease terms of the respective transactions.

      During 2004, we used cash flow from operations and proceeds from asset dispositions to exercise our purchase option and to reduce our outstanding debt and minority interest obligations by $115.0 million under our 2000B compressor equipment lease. In June 2004 we issued notes under our shelf registration statement and exercised our purchase options under the March and August 2000 compression equipment operating leases. As of December 31, 2004, the remaining compression assets owned by the entities that lease equipment to us but are now included in property, plant and equipment in our consolidated financial statements had a net book value of approximately $564.7 million, including improvements made to these assets after the sale leaseback transactions.

      The following table summarizes, as of December 31, 2004, the residual guarantee, lease termination date and minority interest obligations for our equipment leases (in thousands):

      The lease facilities contain certain financial covenants and limitations which restrict us with respect to, among other things, indebtedness, liens, leases and sale of assets. We are entitled under the compression equipment operating lease agreements to substitute equipment that we own for equipment owned by the special purpose entities, provided that the value of the equipment that we are substituting is equal to or greater than the value of the equipment that is being substituted. Each lease agreement limits the aggregate amount of replacement equipment that may be substituted to under each lease.

      In January 2003, the FASB issued FIN 46. The primary objectives of FIN 46 are to provide guidance on the identification of entities for which control is achieved by means other than through voting rights and the determination of when and which business enterprise should consolidate a variable interest entity (“VIE”) in its financial statements. FIN 46 applies to an entity in which either (1) the equity investors (if any) do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity’s activities without receiving additional subordinated financial support from other parties. In addition, FIN 46 requires that both the primary beneficiary and all other enterprises with a significant variable interest in a VIE make additional disclosures. As revised, FIN 46 was effective immediately for VIE’s created after January 31, 2003. For special-purposes entities created prior to February 1, 2003, FIN 46 was effective at the first interim or annual reporting period ending after December 15, 2003, or December 31, 2003 for us. For entities, other than special purpose entities, created prior to February 1, 2003, FIN 46 was effective for us as of March 31, 2004. In addition, FIN 46 allowed companies to elect to adopt early the provisions of FIN 46 for some, but not all, of the variable interest entities they own.

      Prior to July 1, 2003, these lease transactions were recorded as a sale and leaseback of the compression equipment and were treated as operating leases for financial reporting purposes. On July 1, 2003, we adopted the provisions of FIN 46 as they relate to the special purpose entities that lease compression equipment to us. As a result of the adoption, we added approximately $1,089 million in compressor equipment assets, $192.3 million of accumulated depreciation (including approximately

$58.6 million of accumulated depreciation related to periods before the sale and leaseback of the equipment), $1,105.0 million in debt and $34.6 million in minority interest obligations to our balance sheet, and we reversed $108.8 million of deferred gains that were recorded on our balance sheet as a result of the sale leaseback transactions. On July 1, 2003, we recorded a $133.7 million charge ($86.9 million net of tax) to record the cumulative effect from the adoption of FIN 46 related to prior period depreciation of the compression equipment assets.

      The minority interest obligations represent the equity of the entities that lease compression equipment to us. In accordance with the provisions of our compression equipment lease obligations, the equity certificate holders are entitled to quarterly or semi-annual yield payments on the aggregate outstanding equity certificates. As of December 31, 2004, the yield rates on the outstanding equity certificates ranged from 5.2% to 10.6%. Equity certificate holders may receive a return of capital payment upon lease termination or our purchase of the leased compression equipment after full payment of all debt obligations of the entities that lease compression equipment to us. At December 31, 2004, the carrying value of the minority interest obligations approximated the fair market value of assets that would be required to be transferred to redeem the minority interest obligations.

Liquidity and Capital Resources

      Our unrestricted cash balance amounted to $38.1 million at December 31, 2004 compared to $56.6 million at December 31, 2003. Working capital increased to $303.1 million at December 31, 2004 from $279.1 million at December 31, 2003. The increase in working capital was primarily the result of an increase in accounts receivable and inventory due to an improvement in market conditions that has led to increased sales in our businesses.

      Our cash flow from operating, investing and financing activities, as reflected in the Consolidated Statement of Cash Flow, are summarized in the table below (dollars in thousands):

      The decrease in cash provided by operating activities for the year ended December 31, 2004 as compared to the year ended December 31, 2003 was primarily due to an increase in accounts receivable and inventory due to an improvement in market conditions that has led to increased sales in our businesses. The decrease was also due to a decrease in dividends and distributions from our non-consolidated affiliates. During the year ended December 31, 2004 and 2003, we received dividends of $9.8 million and $18.5 million, respectively, from our non-consolidated affiliates.

      The decrease in cash used in investing activities during the year ended December 31, 2004 as compared to the year ended December 31, 2003 was primarily attributable to a decrease in capital expenditures and a decrease in cash used for business acquisitions, net of $4.7 million in proceeds received from the sale of our interest in Hanover Measurement. In addition, in October 2003, our non-consolidated affiliate, PIGAP II, closed on the project’s financing and returned approximately $61.5 million of our investment in the joint venture.

      The increase in cash used in financing activities during the year ended December 31, 2004 as compared to the year ended December 31, 2003 was primarily due to the net reduction of debt during

2004, including the repayment of approximately $115.0 million towards our 2000B compression equipment lease obligations.

      The increase in cash provided by discontinued operations during the year ended December 31, 2004 was principally related to proceeds from the sales of Hanover Canada Corporation and CES for $56.9 million and $2.6 million, respectively. In 2003, Wellhead Power Gates, LLC and Wellhead Power Panoche, LLC were sold for proceeds of approximately $27.2 million.

      We may carry out new customer projects through rental fleet additions and other related capital expenditures. We generally invest funds necessary to make these rental fleet additions when our idle equipment cannot economically fulfill a project’s requirements and the new equipment expenditure is matched with long-term contracts whose expected economic terms exceed our return on capital targets. We currently plan to spend approximately $125 million to $150 million on capital expenditures during 2005 including (1) rental equipment fleet additions and (2) approximately $40 million to $50 million on equipment maintenance capital. During February 2005, we repaid our 2000B compressor equipment lease obligations using our bank credit facility and therefore have classified our 2000B equipment lease notes as long-term debt.

      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 or 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.

      Historically, we have funded our capital requirements with a combination of internally generated cash flow, borrowings under a bank credit facility, sale leaseback transactions, raising additional equity and issuing long-term debt.

      The following summarizes our cash contractual obligations at December 31, 2004 and the effect such obligations are expected to have on our liquidity and cash flow in future periods:

      As part of our business, we are a party to various financial guarantees, performance guarantees and other contractual commitments to extend guarantees of credit and other assistance to various subsidiaries, investees and other third parties. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on our consolidated balance sheet or reflected in the table above. The possibility of our having to honor our contingencies is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. We would record a reserve for these guarantees if events occurred that required that one be established. See Note 19 to the Notes to Consolidated Financial Statements in Item 15 of this Form 10-K.

      Debt Refinancing. In June 2003, we filed a shelf registration statement with the SEC pursuant to which we may from time to time publicly offer equity, debt or other securities in an aggregate amount not to exceed $700 million. The SEC subsequently declared the shelf registration statement effective on November 19, 2003.

      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 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 proceeds from this offering were used to repay a portion of the outstanding indebtedness under our bank credit facility.

      In June 2004, we issued under our shelf registration statement $200.0 million aggregate principal amount of our 9.0% Senior Notes due 2014, which are fully and unconditionally guaranteed on a senior subordinated basis by HCLP. The net proceeds from this offering and available cash were used to repay the outstanding indebtedness and minority interest obligations of $193.6 million and $6.4 million, respectively, under our 2000A equipment lease that was to expire in March 2005.

      Subject to market conditions, the remaining shelf registration statement will be available to offer one or more series of additional debt or other securities.

      Bank Credit Facility. Effective December 15, 2003, we entered into a $350 million bank credit facility with 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 bank credit facility 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 bank credit facility clarifies and provides certain thresholds with respect to our ability to make investments in our international subsidiaries. In addition, under the agreement we granted the lenders a security interest in the inventory, equipment and certain other property of Hanover and its U.S. subsidiaries (with certain exceptions), and pledged 66% of the equity interest in certain of our international subsidiaries. Additionally, our bank credit facility requires that the minimum tangible net worth of HCLP not be less than $702 million. This may limit distributions by HCLP to Hanover in future periods. We believe that this bank credit facility will provide flexibility in accessing the capacity under the facility to support our short-term liquidity needs.

      Our bank credit facility provides for a $350 million revolving credit facility in which advances bear interest at (a) the greater of the administrative agent’s prime rate, the federal funds effective rate, or the base CD rate, or (b) a eurodollar rate, plus, in each case, a specified margin (5.2% weighted average interest rate at December 31, 2004). A commitment fee equal to 0.625% times the average daily amount of the available commitment under the bank credit facility is payable quarterly to the lenders participating in the bank credit facility. Our bank credit facility contains certain financial covenants and limitations on, among other things, indebtedness, liens, leases and sales of assets.

      As of December 31, 2004, we were in compliance with all material covenants and other requirements set forth in our bank credit facility, the indentures and agreements related to our compression equipment lease obligations and indentures and agreements relating to our other long-term debt. While there is no assurance, we believe based on our current projections for 2005 that we will be in compliance with the financial covenants in these agreements. A default under our bank credit facility or a default under certain of the various indentures and agreements would trigger in some situations cross-default provisions under our bank credit facilities or the indentures and agreements relating to certain of our other debt obligations. Such defaults would have a material adverse effect on our liquidity, financial position and operations.

      We expect that our bank credit facility and cash flow from operations will provide us adequate capital resources to fund our estimated level of capital expenditures for the short term. As of December 31, 2004, we had approximately $7.0 million in borrowings (5.2% weighted average effective rate at December 31, 2004) and approximately $99.3 million in letters of credit outstanding under our bank credit facility. Our bank credit facility permits us to incur indebtedness, subject to covenant limitations described above, up to a $350 million credit limit (with letters of credit treated as indebtedness), plus, in addition to certain other indebtedness, an additional (1) $40 million in unsecured indebtedness, (2) $50 million of nonrecourse indebtedness of unqualified subsidiaries, and (3) $25 million of secured purchase money indebtedness. Giving effect to the covenant limitations in our bank credit facility, additional borrowings of up to $123.0 million were available under that facility as of December 31, 2004. In February 2005, we repaid our 2000B compressor equipment lease using borrowings from our bank credit facility. Because our total debt did not increase as a result of such repayment and our trailing four quarter interest coverage ratio is currently limiting our availability, we believe that this did not have a material impact on the available borrowings under our bank credit facility.

      In addition to purchase money and similar obligations, the indentures and the agreements related to our compression equipment lease obligations for our 2001A and 2001B sale leaseback transactions, our 8.625% Senior Notes due 2010 and our 9.0% Senior Notes due 2014 permit us to incur indebtedness up to the $350 million credit limit under our bank credit facility, plus (1) an additional $75 million in unsecured indebtedness and (2) any additional indebtedness so long as, after incurring such indebtedness, our ratio of the sum of consolidated net income before interest expense, income taxes, depreciation expense, amortization of intangibles, certain other non-cash charges and rental expense to total fixed charges (all as defined and adjusted by the agreements), or our “coverage ratio,” is greater than 2.25 to 1.0 and no default or event of default has occurred or would occur as a consequence of incurring such additional indebtedness and the application of the proceeds thereon. The indentures and agreements related to our 2001A and 2001B compression equipment lease obligations, our 8.625% Senior Notes due 2010 and our 9.0% Senior Notes due 2014 define indebtedness to include the present value of our rental obligations under sale leaseback transactions and under facilities similar to our compression equipment operating leases. As of December 31, 2004, Hanover’s coverage ratio was less than 2.25 to 1.0 and therefore as of

such date we could not incur indebtedness other than under our bank credit facility and up to an additional $58.5 million in unsecured indebtedness and certain other permitted indebtedness, including certain refinancing indebtedness.

      Credit Ratings. As of March 9, 2005, our credit ratings as assigned by Moody’s Investors Service, Inc. (“Moody’s”) and Standard & Poor’s Ratings Services (“Standard & Poor’s”) were:

      We do not have any credit rating downgrade provisions in our debt agreements or the agreements related to our compression equipment lease obligations that would accelerate their maturity dates. However, a downgrade in our credit rating could materially and adversely affect our ability to renew existing, or obtain access to new, credit facilities in the future and could increase the cost of such facilities. Should this occur, we might seek alternative sources of funding. In addition, our significant leverage puts us at greater risk of default under one or more of our existing debt agreements if we experience an adverse change to our financial condition or results of operations. Our ability to reduce our leverage depends upon market and economic conditions, as well as our ability to execute liquidity-enhancing transactions such as sales of non-core assets or our equity securities.

      International Operations. 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 the value of these currencies relative to the U.S. dollar. For the year ended December 31, 2004, our Argentine operations represented approximately 6% of our revenue and 9% of our gross profit. For the year ended December 31, 2004, our Venezuelan operations represented approximately 12% of our revenue and 21% of our gross profit. At December 31, 2004, we had approximately $17.3 million and $22.4 million in accounts receivable related to our Argentine and Venezuelan operations.

      The following table summarizes the exchange gains and losses we recorded for assets exposed to currency translation (in thousands):

      At December 31, 2004 we had intercompany advances outstanding to our subsidiary in Italy of approximately $55.0 million. These advances are denominated in U.S. dollars. The impact of the remeasurement of these advances on our statement of operations by our subsidiary will depend on the outstanding balance in future periods. The remeasurement of these advances in 2004 resulted in a translation gain of approximately $3.7 million.

      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 dropped. In addition, exchange controls have been put in place that 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 agreement 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 be materially and adversely affected, which could result in reductions in our net income. For example, as a result of the disruption in our operations in Venezuela, during the fourth quarter of 2002, our international rental revenues decreased by approximately $2.7 million due to concerns about the ultimate receipt of those revenues. Although we were able to realize those revenues in 2003, no assurances can be given that this will be the result if a similar situation occurred in the future. In addition, in February 2003, the Venezuelan government fixed the exchange rate to 1,600 bolivars for each U.S. dollar. In February 2004 and March 2005, the Venezuelan government devalued the currency to 1,920 bolivars and 2,148 bolivars, respectively, for each U.S. dollar. 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.

      The economic situation in Argentina and Venezuela is subject to change. To the extent that the situation deteriorates, exchange controls continue in place and the value of the peso and bolivar against the dollar is reduced further, our results of operations in Argentina and Venezuela could be materially and adversely affected which could result in reductions in our net income.

      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 Shell and Global. We have substantially completed the building of the required barge-mounted facilities. Under the terms of a series of contracts between Global and us, Shell, and several other counterparties, respectively, Global is responsible for the development of the overall project. In light of the political environment in Nigeria, Global’s capitalization level and 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 these contracts.

      This project and our other projects in Nigeria are subject to numerous risks and uncertainties associated with operating in Nigeria. Such risks include, among other things, political, social and economic

instability, civil uprisings, riots, terrorism, the taking of property without fair compensation and governmental actions that may restrict payments or the movement of funds or result in the deprivation of contract rights. Any of these risks as well as other risks associated with a major construction project could materially delay the anticipated commencement of operations of the Cawthorne Channel Project or impact any of our operations in Nigeria. Any such delays could affect the timing and decrease the amount of revenue we may realize from our investments in Nigeria. 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. At December 31, 2004, we had an investment of approximately $60.3 million in projects in Nigeria, a substantial majority of which related to the Cawthorne Channel Project. We currently anticipate investing an additional $10 million in the Cawthorne Channel Project during 2005. In addition, we have approximately $4.2 million associated with advances to, and our investment in, Global.

      In July 2004, PIGAP II received a notice of default from the Venezuelan state oil company, PDVSA, alleging that PIGAP II was not in compliance under a services agreement as a result of certain operational issues. PIGAP II is a joint venture, currently owned 70% by a subsidiary of Williams and 30% by Hanover, that operates a natural gas compression facility in Venezuela. While PIGAP II advised us that it did not believe a basis existed for such notice of default, the giving of the notice of default by PDVSA could be deemed an event of default under PIGAP II’s outstanding project loans totaling approximately $207.7 million. PIGAP II sought a waiver of this potential default from its lenders, and the lenders under the PIGAP II project loan agreement have waived any potential default under the loan documents. Additionally, in January 2005, PDVSA advised PIGAP II that there were no events of default under the services agreement in existence at that time. Hanover’s net book investment in PIGAP II at December 31, 2004 was approximately $33.5 million and Hanover’s pretax income with respect to PIGAP II for the year ended December 31, 2004 was approximately $12.2 million.

      Derivative Financial Instruments. We use derivative financial instruments to minimize the risks and/or costs associated with financial and global operating activities by managing our exposure to interest rate fluctuations on a portion of our debt and leasing obligations. Our primary objective is to reduce our overall cost of borrowing by managing the fixed and floating interest rate mix of our debt portfolio. We do not use derivative financial instruments for trading or other speculative purposes. The cash flow from hedges is classified in our consolidated statements of cash flows under the same category as the cash flows from the underlying assets, liabilities or anticipated transactions.

      For derivative instruments designated as fair value hedges, the gain or loss is recognized in earnings in the period of change together with the gain or loss on the hedged item attributable to the risk being hedged. For derivative instruments designated as cash flow hedges, the effective portion of the derivative gain or loss is included in other comprehensive income, but not reflected in our consolidated statement of operations until the corresponding hedged transaction is settled. The ineffective portion is reported in earnings immediately.