Archrock - 10-K annual report

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

This report contains “forward-looking statements” intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical fact contained in this report are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, including, without limitation, statements regarding our business growth strategy and projected costs; future financial position; the sufficiency of available cash flows to fund continuing operations; the expected amount of our capital expenditures; future revenue, gross margin and other financial or operational measures related to our business and our primary business segments; the future value of our equipment; and plans and objectives of our management for our future operations. You can identify many of these statements by looking for words such as “believes,” “expects,” “intends,” “projects,” “anticipates,” “estimates” or similar words or the negative thereof.

 

Such forward-looking statements are subject to various risks and uncertainties that could cause actual results to differ materially from those anticipated as of the date of this report. Although we believe that the expectations reflected in these forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will prove to be correct.

 

These forward-looking statements are also affected by the risk factors described below in Part I, Item 1A (“Risk Factors”) and those set forth from time to time in our filings with the Securities and Exchange Commission (“SEC”), which are available through our website atwww.exterran.com and through the SEC’s Electronic Data Gathering and Retrieval System (“EDGAR”) at www.sec.gov. Important factors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things:

 

 

 

 

 

All forward-looking statements included in this report are based on information available to us on the date of this report. Except as required by law, we undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements contained throughout this report.

 

We were incorporated on February 2, 2007 as Iliad Holdings, Inc., a wholly-owned subsidiary of Universal Compression Holdings, Inc. (“Universal”), and thereafter changed our name to Exterran Holdings, Inc. (“Exterran”). On August 20, 2007, Universal and Hanover Compressor Company (“Hanover”) merged into our wholly-owned subsidiaries, and we became the parent entity of Universal and Hanover. Immediately following the completion of the merger, Universal merged with and into us. Hanover was determined to be the acquirer for accounting purposes and, therefore, our financial statements reflect Hanover’s historical results for periods prior to the merger date. We have included the financial results of Universal’s operations in our consolidated financial statements beginning August 20, 2007. References to “our,” “we” and “us” refer to Hanover for periods prior to the merger date and to Exterran for periods on or after the merger date. References to “North America” when used in this report refer to the U.S. and Canada. References to “International” and variations thereof when used in this report refer to the world excluding North America. For more information regarding the merger, see Note 3 to the Consolidated Financial Statements included in Part IV, Item 15 (“Financial Statements”) of this report.

 

As a result of the merger between Hanover and Universal, each outstanding share of common stock of Universal was converted into one share of Exterran common stock and each outstanding share of Hanover common stock was converted into 0.325 shares of Exterran common stock. All share and per share amounts in this report have been retroactively adjusted to reflect the conversion ratio of Hanover common stock for all periods presented.

 

We are a global market leader in the full service natural gas compression business and a premier provider of operations, maintenance, service and equipment for oil and natural gas production, processing and transportation applications. Our global customer base consists of companies engaged in all aspects of the oil and natural gas industry, including large integrated oil and natural gas companies, national oil and natural gas companies, independent producers and natural gas processors, gatherers and pipelines. We operate in three primary business lines: contract operations, fabrication and aftermarket services. In our contract operations business line, we own a fleet of natural gas compression equipment and crude oil and natural gas production and processing equipment that we utilize to provide operations services to our customers. In our fabrication business line, we fabricate and sell equipment similar to the equipment that we own and utilize to provide contract operations to our customers. We also fabricate the equipment utilized in our contract operations services. In addition, our fabrication business line provides engineering, procurement and construction services primarily related to the manufacturing of critical process equipment for refinery and petrochemical facilities, the construction of tank farms and the construction of evaporators and brine heaters for desalination plants. In

our Total Solutions projects, we provide the engineering design, project management, procurement and construction services necessary to incorporate our products into complete production, processing and compression facilities. Total Solutions products are offered to our customers on a contract operations or on a sale basis. In our aftermarket services business line, we sell parts and components and provide operations, maintenance, overhaul and reconfiguration services to customers who own compression, production, processing, gas treating and other equipment.

 

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 contract operations fleet allow us to provide reliable and timely customer service.

 

We are the indirect majority owner of the Partnership, a master limited partnership that provides natural gas contract operations services to customers throughout the U.S. As of December 31, 2009, public unitholders held a 34% ownership interest in the Partnership and we owned the remaining equity interest, including the general partner interest and all incentive distribution rights. The general partner of the Partnership is our subsidiary and we consolidate the financial position and results of operations of the Partnership. It is our intention for the Partnership to be the primary vehicle for the long-term growth of our U.S. contract operations business and for us to continue to contribute U.S. contract operations customer contracts and equipment to the Partnership over time in exchange for cash, the Partnership’s assumption of our debtand/or our receipt of additional interests in the Partnership. As of December 31, 2009, the Partnership owned a fleet of 3,401 compressor units comprising approximately 1,304,000 horsepower, or 31% (by available horsepower) of our and the Partnership’s combined total U.S. horsepower.

 

 

Natural gas compression is a mechanical process whereby the pressure of a given volume of natural gas is increased to a desired higher pressure for transportation from one point to another; compression is essential to the production and transportation of natural gas. Compression is typically required several times during the natural gas production and transportation cycle, including: (1) at the wellhead; (2) throughout gathering and distribution systems; (3) into and out of processing and storage facilities; and (4) along intrastate and interstate pipelines.

 

 

 

Many producers, transporters and processors outsource their compression services due to the benefits and flexibility of contract compression. Changing well and pipeline pressures and conditions over the life of a well often require producers to reconfigure or replace their compressor units to optimize the well production or gathering system efficiency.

 

We believe outsourcing compression operations to compression service providers such as us offers customers:

 

 

The international compression market is comprised primarily of large horsepower compressors. A significant portion of this market involves comprehensive projects that require the design, fabrication, delivery, installation, operation and maintenance of compressors and related natural gas treatment and processing equipment by the contract operations service provider.

 

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

 

The standard production and processing equipment market tends to be somewhat commoditized, with sales following general industry trends of oil and gas production. We fabricate and stock standard production equipment based on historical product mix and expected customer purchases. The custom equipment market is driven by global economic trends, and the specifications of equipment that is purchased can vary significantly. Technology, engineering capabilities, project management, available manufacturing space and quality control standards are the key drivers in the custom equipment market.

 

We believe that the fundamental force driving the demand for natural gas compression and production and processing equipment over the past decade has been the growing global consumption of natural gas and its

byproducts. As more natural gas is consumed, the demand for compression and production and processing equipment generally increases. In addition, we expect the demand for natural gas and natural gas byproducts to increase over the long-term, and to result in additional demand for compression and production and processing equipment and related services.

 

Although natural gas has historically been a more significant source of energy in the U.S. than in the rest of the world, the U.S. Energy Information Administration (“EIA”) reports that natural gas consumption outside of the U.S. grew 44% from 1998 through 2008. Despite this growth in energy demand, most international energy markets have historically lacked the infrastructure necessary to either transport natural gas to markets or consume it locally; thus, natural gas historically has often been flared at the wellhead. We believe that over the long-term demand for natural gas infrastructure in international markets will increase. This anticipated increase in demand for infrastructure is due to a projected increase in demand for natural gas, recent technology advances, including liquefied natural gas (or LNG) and gas-to-liquids, which make the transportation of natural gas without pipelines more economical, environmental legislation prohibiting flaring, and the construction of numerous natural gas-fueled power plants built to meet international energy demand.

 

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

 

Natural gas consumption in the U.S. for the twelve months ended November 30, 2009 decreased by approximately 2% over the twelve months ended November 30, 2008, is expected to increase by 0.4% in both 2010 and 2011 and is expected to increase by an average of 0.7% per year until 2030, according to the EIA. We believe the outlook for natural gas compression in the U.S. will continue to benefit from the aging of producing natural gas fields that will require more compression to continue producing the same volume of natural gas and from increased production from unconventional sources, including coalbeds, shales and tight sands.

 

Total natural gas consumption worldwide is projected to increase by an average of 2.4% per year until 2030, according to the EIA. We believe this projected increase in consumption will positively impact the market for natural gas compression in areas outside the U.S. as infrastructure will need to be built to accommodate such growth. Additionally, we believe fabrication of production and processing equipment will increase over time to support the infrastructure required to meet this increasing demand.

 

Our critical process equipment business benefited from strong energy markets in 2007 and early 2008. However, the decrease in the price of oil beginning in the second half of 2008 and the reductions in global economic activity have led to a reduction in our fabrication backlog.

 

We also construct evaporators and brine heaters for desalination plants and tank farms primarily for use in North Africa and the Middle East. Demand for our evaporators and brine heaters for desalination plants is primarily driven by population growth, improvements in the standard of living and investment in infrastructure. We expect continued investment in these projects, and therefore demand for the equipment, in the regions we serve to increase in the next few years. However, the reductions in global economic activity led to a reduction in our backlog related to these projects during 2009. As industry capital spending declined in 2009, our fabrication business segment experienced a reduction in demand. This decline in demand for our fabrication products has led to a reduction in our fabrication backlog and revenue, and continued reductions in industry capital spending may further reduce our fabrication backlog and revenue. Our reduction in fabrication backlog has also been driven by shorter lead times on delivery of major components from our suppliers and, in turn, our lead times in delivering our products to customers. These conditions are also expected to further negatively impact our North America contract operations business segment, although we believe the effects could be less severe on that business because it is more closely tied to natural gas production than drilling activities and, therefore, it has historically experienced more stable demand than that for certain other energy service products and services.

 

 

Our revenues and income are derived from four business segments:

 

 

For financial data relating to our business segments or geographic regions that accounted for 10% or more of consolidated revenue in any of the last three fiscal years, see Part II, Item 7 (“Management’s Discussion and Analysis of Financial Condition and Results of Operations”) and Note 23 to the Financial Statements.

 

The size and horsepower of our natural gas compressor fleet on December 31, 2009 is summarized in the following table:

 

 

Over the last several years, we have undertaken efforts to standardize our compressor fleet around major components and key suppliers. The standardization of our fleet:

 

 

We provide comprehensive contract operations services, which include our provision at the customer’s location of our personnel, equipment, tools, materials and supplies necessary to provide the amount of natural gas compression, production or processing service for which the customer has contracted. Based on the operating specifications at the customer’s location and the customer’s unique needs, these services include designing, sourcing, owning, installing, operating, servicing, repairing and maintaining equipment to provide these services to our customers. We also provide contract water management and processing services, primarily to the coalbed methane industry.

 

When providing contract compression services, we work closely with a customer’s field service personnel so that the compression services can be adjusted to efficiently match changing characteristics of the reservoir and the natural gas produced. We routinely repackage or reconfigure a portion of our existing fleet to adapt to our customers’ compression services needs. We utilize both slow and high speed reciprocating compressors driven either by internal combustion engines or electric motors. We also utilize rotary screw compressors for specialized applications.

 

Our equipment is maintained in accordance with established maintenance schedules. These maintenance procedures are updated as technology changes and as our operations group develops new techniques and procedures. In addition, because our field technicians provide maintenance on our contract operations equipment, they are familiar with the condition of our equipment and can readily identify potential problems. In our experience, these maintenance procedures maximize equipment life and unit availability, minimize avoidable downtime and lower the overall maintenance expenditures over the equipment life. Generally, each of our compressor units undergoes a major overhaul once every three to seven years, depending on the type and size of the unit.

 

We also provide contract production and processing services, similar to the contract compression services described above, utilizing our fleet of natural gas production and processing equipment. In Total Solutions projects, we provide the engineering design, project management, procurement and construction services necessary to incorporate our products into complete production, processing and compression facilities. Total Solutions products are offered to our customers on a contract operations or on a sale basis.

 

We believe that our aftermarket services and fabrication businesses, described below, provide us with opportunities to cross-sell our contract operations services.

 

Our customers typically contract for our services on asite-by-sitebasis for a specific monthly rate that is generally adjusted only if we fail to operate in accordance with the contract requirements. At the end of the initial term, which in North America is typically between six and twelve months, contract operations services generally continue until terminated by either party with 30 days advance notice. Our customers generally are required to pay our monthly service fee even during periods of limited or disrupted natural gas flows, which enhances the stability and predictability of our cash flows. Additionally, because we do not take title to the natural gas we compress, process or treat and because the natural gas we use as fuel for our compressors and other equipment is supplied by our customers, we have limited direct exposure to commodity price fluctuations.

 

We maintain field service locations in the natural gas producing regions of the U.S. and Canada from which we can service and overhaul our own compressor fleet to provide contract operations services to our customers. Many of these locations are also utilized to provide aftermarket services to our customers, as described in more detail below. As of December 31, 2009, our North America contract operations segment provided contract operations services primarily using a fleet of 10,433 natural gas compression units that had an aggregate capacity of approximately 4,321,000 horsepower. For the year ended December 31, 2009, 26% of our total revenue was generated from North America contract operations.

 

Our international operations are focused on markets that require both large horsepower compressor applications and full production and processing facilities. Our international contract operations segment typically engages in longer-term contracts and more comprehensive projects than our North America contract operations segment. International projects often require us to provide complete engineering, design and

installation services and a greater investment in equipment, facilities and related installation costs. These larger projects may include several compressor units on one site or entire facilities designed to process and treat oil or natural gas to make it suitable for end use. As of December 31, 2009, our international contract operations segment provided contract operations services using a fleet of 1,164 units that had an aggregate capacity of approximately 1,234,000 horsepower and a fleet of production and processing equipment. For the year ended December 31, 2009, 14% of our total revenue was generated from international contract operations.

 

Our aftermarket services segment sells parts and components and provides operation, maintenance, overhaul and reconfiguration services to customers who own compression, production, treating and oilfield power generation 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 services, production and processing equipment and oilfield power generation equipment and facilities. For the year ended December 31, 2009, 11% of our total revenue was generated from aftermarket services.

 

 

We design, engineer, fabricate, install and sell skid-mounted natural gas compression units and accessories to meet standard or unique customer specifications. We sell this compression equipment primarily to major and independent oil and natural gas producers as well as national oil and natural gas companies in the countries in which we operate.

 

Generally, compressors sold to third parties are assembled according to each customer’s specifications. We purchase components for these compressors from third party suppliers including several major engine, compressor and electric motor manufacturers in the industry. We also sell pre-packaged compressor units designed to our standard specifications. For the year ended December 31, 2009, 22% of our total revenue was generated from our compressor and accessory fabrication business line.

 

As of December 31, 2009, our compressor and accessory fabrication backlog was $296.9 million, compared to $395.5 million at December 31, 2008. At December 31, 2009, all future revenue related to our compressor and accessory fabrication backlog is expected to be recognized before December 31, 2010.

 

We design, engineer, fabricate, install and sell a broad range of oil and natural gas production and processing equipment designed to heat, separate, dehydrate and condition crude oil and natural gas to make such products suitable for end use. Our products include line heaters, oil and natural gas separators, glycol dehydration units, dewpoint control plants, water treatment, mechanical refrigeration and cryogenic plants and skid-mounted production packages designed for both onshore and offshore production facilities. 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 at times are in remote areas, such as deepwater offshore sites and in developing countries with limited oil and natural gas industry infrastructure. To meet most customers’ rapid response requirements and minimize customer downtime, we maintain an inventory of standard products and long delivery components used to manufacture our customer specification products. We also provide engineering, procurement and construction services primarily related to the manufacturing of critical process equipment for refinery and petrochemical facilities, the construction of tank farms and the construction of evaporators and brine heaters for desalination plants. For the year ended December 31, 2009, 27% of our total revenue was generated from our production and processing equipment fabrication business line.

As of December 31, 2009, our production and processing equipment fabrication backlog was $515.6 million, compared to $732.7 million at December 31, 2008. Typically, we expect our production and processing equipment backlog to be produced within a three to 36 month period. At December 31, 2009, approximately $68.0 million of future revenue related to our production and processing equipment backlog was expected to be recognized after December 31, 2010.

 

We intend to continue to capitalize on our competitive strengths to meet our customers’ needs through the following key strategies:

 

 

We believe we have the following key competitive strengths:

 

 

 

The financial performance of our contract operations business is generally less affected by short-term market cycles and oil and natural gas price volatility than the financial performance of our fabrication operations and other companies operating in the oilfield services industry because:

 

 

In addition, we have a broad customer base and we operate in diverse geographic regions. While compressors often must be specifically engineered or reconfigured to meet the unique demands of our customers, the fundamental technology of compression equipment has not experienced significant technological change.

 

Our results of operations have not historically reflected any material seasonal tendencies and we currently do not believe that seasonal fluctuations will have a material impact on us in the foreseeable future.

 

Our global customer base consists primarily of companies engaged in all aspects of the oil and natural gas industry, including large integrated oil and natural gas companies, national oil and natural gas companies, independent producers and natural gas processors, gatherers and pipelines.

 

Our contract operations and sales activities are conducted throughout North America and internationally, including offshore operations. We currently operate in over 30 countries in major oil and natural gas producing areas including the U.S., Argentina, Brazil, Mexico, Italy and the United Arab Emirates. We have fabrication facilities in the U.S., Italy, Singapore, the United Arab Emirates and the United Kingdom.

 

Our salespeople pursue the market for our products in their respective territories. Each salesperson is assigned a customer list or territory 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. Additionally, our salespeople coordinate with each other to effectively pursue customers who operate in multiple regions. Our salespeople work with our operations personnel in order to promptly respond to and satisfy customer needs.

 

Upon receipt of a request for proposal or bid by a customer, we analyze the application and prepare a quotation, including 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 provide assistance on complex applications, field operations issues and equipment modifications.

 

We fabricate compression and production and processing equipment for use in providing contract operations services and for sale to third parties 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 construct tank farms and fabricate critical process equipment for refinery and petrochemical facilities 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. Increases in raw material costs cannot always be offset by increases in our products’ sales prices. While many of our materials and components are available from multiple suppliers at competitive prices, some of the components used in our products are obtained from a limited group of suppliers. We occasionally experience long lead times for components from our suppliers and, therefore, we may at times make purchases in anticipation of future orders.

 

The natural gas compression services and fabrication business is highly competitive. Overall, we experience considerable competition from companies that 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. We believe that we compete effectively on the basis of price, equipment availability, customer service and flexibility in meeting customer needs and quality and reliability of our compressors and related services. We face vigorous competition in both compression services and compressor fabrication, with some firms competing in both segments. 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 the point of end-use is a competitive advantage.

 

We operate in many geographic markets outside North America. At December 31, 2009, approximately 17% of our revenue was generated by our operations in Latin America (primarily in Argentina, Mexico and Brazil) and 31% of our revenue was generated in the Eastern Hemisphere. Changes in local economic or political conditions, particularly in Argentina and other parts of Latin America and Nigeria, could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

Our future plans involve expanding our business in international markets. 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, Brazil, Italy, Canada and Mexico.

 

Additional risks inherent in our international business activities are described below in Risk Factors. For financial data relating to our geographic concentrations, see Note 23 to the Financial Statements.

 

 

Our operations are subject to stringent and complex U.S. federal, state, local and international laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment and to occupational health and safety. Compliance with these environmental laws and regulations may expose us to significant costs and liabilities and cause us to incur significant capital expenditures in our operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of investigatory and remedial obligations, and the issuance of injunctions delaying or prohibiting operations. We believe that our operations are in substantial compliance with applicable environmental and health and safety laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us. However, the clear trend in environmental regulation is to place more restrictions on activities that may affect the environment, and thus, any changes in these laws and regulations that result in more stringent and costly waste handling, storage, transport, disposal, emission or remediation requirements could have a material adverse effect on our results of operations and financial position.

 

The primary U.S. federal environmental laws to which our operations are subject include the Clean Air Act (“CAA”) and regulations thereunder, which regulate air emissions; the Clean Water Act (“CWA”) and regulations thereunder, which regulate the discharge of pollutants in industrial wastewater and storm water runoff; the Resource Conservation and Recovery Act (“RCRA”) and regulations thereunder, which regulate the management and disposal of solid and hazardous waste; and the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and regulations thereunder, known more commonly as “Superfund,” which imposes liability for the remediation of releases of hazardous substances in the environment. We are also subject to regulation under the Occupational Safety and Health Act (“OSHA”) and regulations thereunder, which regulate the protection of the health and safety of workers. Analogous state, local and international laws and regulations may also apply.

 

The CAA and analogous state laws and their implementing regulations regulate emissions of air pollutants from various sources, including natural gas compressors, and also impose various monitoring and reporting requirements. Such laws and regulations may require a facility to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. Our standard contract operations contract typically provides that the customer will assume permitting responsibilities and certain environmental risks related to site operations.

 

The Environmental Protection Agency (“EPA”) adopted new rules effective March 18, 2008 that establish more stringent emission standards for new spark ignition natural gas compressor engines. The new rules require increased emission controls on certain new and reconstructed stationary reciprocating engines that were excluded from previous regulation. We do not expect these rules to have a material adverse effect on our operations or financial condition. In March 2009, the EPA formally proposed new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines. The rule, when finalized by the EPA, may require us to undertake significant expenditures, including expenditures for purchasing and installing emissions control equipment such as oxidation catalysts or non-

selective catalytic reduction equipment, imposing more stringent maintenance practices, and implementing additional monitoring practices on a potentially significant percentage of our natural gas compressor engine fleet. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements. The comment period on the proposed regulation ended on June 3, 2009 and the EPA has signed a consent decree requiring it to promulgate a final rule no later than August 10, 2010. Under the proposal, compliance will be required by three years from the effective date of the final rule. This proposed rule, when finalized, and any other new regulations requiring the installation of more sophisticated emission control equipment could have a material adverse impact on our business, financial condition, results of operations and cash flows.

 

The U.S. Congress is considering new legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane, that are understood to contribute to global warming. The American Clean Energy and Security Act of 2009 could, if enacted by the full Congress, require greenhouse gas emissions reductions by covered sources of as much as 17% from 2005 levels by 2020 and by as much as 83% by 2050. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address greenhouse gas emissions, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Although most of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions, such as electric power plants, it is possible that smaller sources such as our gas-fired compressors could become subject to greenhouse gas-related regulation. Depending on the particular program, we could be required to control emissions or to purchase and surrender allowances for greenhouse gas emissions resulting from our operations.

 

Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may regulate greenhouse gas emissions from mobile sources such as new motor vehicles, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court held in Massachusetts v. EPAthat greenhouse gases including carbon dioxide fall under the CAA’s definition of “air pollutant.” In July 2008, on the basis of this decision, the EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the CAA. In the notice, the EPA evaluated the potential regulation of greenhouse gases under several different provisions of the CAA, but did not propose any specific new regulatory requirements for greenhouse gases. The notice and three other recent regulatory developments, described below, along with recent statements by the Administrator of the EPA, suggest that the EPA is beginning to pursue a path toward the regulation of greenhouse gas emissions under its existing CAA authority. First, in September 2009, the EPA adopted a new rule requiring approximately 13,000 facilities comprising a substantial percentage of annual U.S. greenhouse gas emissions to inventory their emissions starting in 2010 and to report those emissions to the EPA beginning in 2011. That rule, at least for now, does not apply to oil and gas systems. Second, on December 15, 2009, the EPA officially published its finalized determination that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA pave the way for the agency to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the CAA. Third, the EPA in late September 2009 proposed a rule that would provide for the tailored application of the agency’s major air permitting programs to facilities that annually emit over 25,000 tons of greenhouse gases, such as large industrial facilities of the type covered by the inventory rule described above.

 

Although it is not currently possible to predict how any such proposed or future greenhouse gas legislation or regulation by Congress, the states, or multi-state regions will impact our business, any legislation or regulation of greenhouse gas emissions that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions or reduced demand for our services, and could have a material adverse effect on our business financial condition, results of operations and cash flows.

 

The CWA and analogous state laws and their implementing regulations impose restrictions and strict controls with respect to the discharge of pollutants into state waters or waters of the U.S. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. In addition, the CWA regulates storm water discharges associated with industrial activities depending on a facility’s primary standard industrial classification. Many of our facilities have applied for and obtained industrial wastewater discharge permits as well as sought coverage under local wastewater ordinances. In addition, many of those facilities have filed notices of intent for coverage under statewide storm water general permits and developed and implemented storm water pollution prevention plans, as required. U.S. federal laws also require development and implementation of spill prevention, controls, and countermeasure plans, including appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak at such facilities.

 

The RCRA and analogous state laws and their implementing regulations govern the generation, transportation, treatment, storage and disposal of hazardous and non-hazardous solid wastes. During the course of our operations, we generate wastes (including, but not limited to, used oil, antifreeze, filters, sludges, paints, solvents, and sandblast materials) in quantities regulated under RCRA. The EPA and various state agencies have limited the approved methods of disposal for these types of wastes. CERCLA and analogous state laws and their implementing regulations impose strict, and under certain conditions, joint and several liability without regard to fault or the legality of the original conduct on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include current and past owners and operators of the facility or disposal site where the release occurred and any company that transported, disposed of, or arranged for the transport or disposal of the hazardous substances released at the site. Under CERCLA, 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. In addition, where contamination may be present, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury, property damage and recovery of response costs allegedly caused by hazardous substances or other pollutants released into the environment.

 

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 by 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 certain operations to prevent future contamination. At certain of such sites, we are currently working with the prior owners who have undertaken to monitor and cleanup contamination that occurred prior to our acquisition of these sites. We are not currently under any order requiring that we undertake or pay for anyclean-upactivities. However, we cannot provide any assurance that we will not receive any such order in the future.

 

We are subject to the requirements of OSHA and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organizeand/ordisclose information about hazardous materials used or

produced in our operations. We believe we are in substantial compliance with these requirements and with other OSHA and comparable requirements.

 

Our operations outside the U.S. are 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 international controls and restrictions in the future.

 

As of December 31, 2009, we had approximately 11,100 employees, approximately 700 of whom are represented by labor unions. We believe that our relations with our employees are satisfactory.

 

Our website address is www.exterran.com. Our annual reports onForm 10-K,quarterly reports onForm 10-Q,current reports onForm 8-Kand amendments to those reports are available on our website, without charge, as soon as reasonably practicable after they are filed electronically with the SEC. Information contained on our website is not incorporated by reference in this report or any of our other securities filings. Paper copies of our filings are also available, without charge, from Exterran Holdings, Inc., 16666 Northchase Drive, Houston, Texas 77060, Attention: Investor Relations. Alternatively, the public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information on the operation of the Public Reference Room may be obtained by calling the SEC at1-800-SEC-0330.The SEC also maintains a website that contains reports, proxy and information statements and other information regarding issuers who file electronically with the SEC. The SEC’s website address is www.sec.gov.

 

Additionally, we make available free of charge on our website:

 

 

 

The continuing challenges in the global economy and financial markets may have an impact on our business and our financial condition. If any of our lenders become unable to perform their obligations under our credit facilities, our borrowing capacity under these facilities could be reduced. Inability to borrow additional amounts under those facilities could limit our ability to fund our future growth and operations. These challenges could also have an impact on our derivative agreements if any of our counterparties are unable to perform their obligations under those agreements.

 

Our results of operations depend upon the level of activity in the global energy market, including natural gas development, production, processing and transportation. For example, as a result of market conditions in 2009, our North America contract operations and fabrication revenues and bookings decreased and resulted in a decrease in income from continuing operations. Oil and natural gas prices and the level of drilling and exploration activity can be volatile. For example, oil and natural gas exploration and development activity and the number of well completions typically decline when there is a significant reduction in oil and natural gas prices or significant instability in energy markets. As a result, the demand for our natural gas compression services and oil and natural gas production and processing equipment could be adversely affected. A reduction in demand could also force us to reduce our pricing substantially. Additionally, in North America compression services for our customers’ production from unconventional natural gas sources such as tight sands, shales and coalbeds constitute an increasing percentage of our business. Some of these unconventional sources are less economic to produce in lower natural gas price environments. Further, some of these unconventional sources may not require as much compression or require compression as early in the production life-cycle of an unconventional field or well as has been experienced historically in conventional and other unconventional natural gas sources. These factors could in turn negatively impact the demand for our products and services. A decline in demand for oil and natural gas or prices for those commodities, or instability in the North America or global energy markets could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

In addition, we review our long-lived assets for impairment when events or changes in circumstances indicate the carrying value may not be recoverable. Goodwill is tested for impairment at least annually. A decline in demand for oil and natural gas or prices for those commodities, or instability in the North America or global energy markets could cause a further reduction in demand for our products and services and result in a reduction of our estimates of future cash flows and growth rates in our business. These events could cause us to record additional impairments of long-lived assets. For example, during the years ended December 31, 2009 and 2008, we recorded goodwill impairments of $150.8 million and $1,148.4 million, respectively; and during 2009 and 2008, we recorded fleet impairments of $91.0 million and $24.1 million, respectively. The impairment of our goodwill, intangible assets or other long-lived assets could have a material adverse effect on our results of operations.

 

We believe there currently exists a greater supply of idle and underutilized compression equipment owned by our customers and competitors in North America than in recent years, which has limited, and will continue to limit in the near term, our ability to maintain or improve our horsepower utilization and revenues. Some of our customers may continue to replace our compression equipment and services with equipment they own or with competitor owned equipment and may continue to rationalize their amount of compression horsepower. In addition, some of our customers or prospective customers may purchase their own compression equipment in lieu of using our products or services. For example, our total North America operating horsepower decreased by approximately 17% from December 31, 2008 to December 31, 2009, and we expect further horsepower declines into 2010. A further reduction in demand for our products and services, or a further reduction in our pricing for our products or services, could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

Many of our customers finance their exploration and development activities through cash flow from operations, the incurrence of debt or the issuance of equity. During times when the oil or natural gas markets weaken, our customers are more likely to experience a downturn in their financial condition. A reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing could result in a reduction in our customers’ spending for our products and services. For example, our customers could seek to preserve capital by cancelingmonth-to-monthcontracts, canceling or delaying scheduled maintenance of their existing natural gas compression and oil and natural gas production and processing equipment or determining not to enter into any new natural gas compression service contracts or purchase new compression and oil and natural gas production and processing equipment, thereby reducing demand for our products and services. Reduced demand for our products and services could adversely affect our business, financial condition, results of operations and cash flows. In addition, in the event of the financial failure of a customer, we could experience a loss on all or a portion of our outstanding accounts receivable associated with that customer.

 

We operate in many geographic markets outside the U.S., which entails difficulties in staffing and managing our international operations and complying with legal and regulatory requirements. Changes in local economic or political conditions could have a material adverse effect on our business, financial condition, results of operations and cash flows. For example, as discussed in Note 2 to the Financial Statements, in 2009 the Venezuelan state-owned oil company, Petroleos de Venezuela S.A. (“PDVSA”), assumed control over substantially all of our assets and operations in Venezuela. The risks inherent in our international business activities include the following:

 

 

 

In addition, we plan to expand our business in international markets where we have not previously conducted 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 that could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

Our operations in Nigeria are subject to numerous risks and uncertainties associated with operating in Nigeria. These risks include, among other things, political, social and economic instability, civil uprisings, riots, terrorism, kidnapping, the taking of property without fair compensation and governmental actions that may restrict payments or the movement of funds or property or result in the deprivation of contract rights. Any of these risks, including risks arising from the increase in violence and local unrest in Nigeria over the past several years, could adversely impact our operations in Nigeria and could affect the timing and decrease the amount of revenue we may realize from our assets in Nigeria. At December 31, 2009 our net investment in assets in Nigeria was $46.9 million.

 

We operate in many international countries. We anticipate that there will be instances in which costs and revenues will not be exactly matched with respect to currency denomination. We generally do not hedge exchange rate exposures, which exposes us to the risk of exchange rate losses. Gains and losses from the remeasurement of assets and liabilities that are receivable or payable in currency other than our subsidiaries’ functional currency are included in our consolidated statements of operations. In addition, currency fluctuations cause the U.S. dollar value of our international results of operations and net assets to vary with exchange rate fluctuations. This could have a negative impact on our business, financial condition or results of operations. In addition, fluctuations in currencies relative to currencies in which the earnings are generated may make it more difficult to performperiod-to-periodcomparisons of our reported results of operations. For

example, other (income) expense, net for the year ended December 31, 2009 includes foreign currency translation gains of $16.7 million compared to a loss of $10.7 million for the year ended December 31, 2008.

 

To the extent we continue to expand geographically, we expect that increasing portions of our revenues, costs, assets and liabilities will be subject to fluctuations in foreign currency valuations. We may experience economic loss and a negative impact on earnings or net assets solely as a result of foreign currency exchange rate fluctuations. Further, the markets in which we operate could restrict the removal or conversion of the local or foreign currency, resulting in our inability to hedge against these risks.

 

As our business has grown, the size and scope of some of our contracts with our customers has increased. This increase in size and scope can translate into more technically challenging conditions or performance specifications for our products and services. Contracts with our customers generally specify delivery dates, performance criteria and penalties for our failure to perform. Any failure to execute such larger projects in a timely and cost effective manner could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

In connection with projects covered by fixed-price contracts, we generally bear the risk of cost over-runs, operating cost inflation, labor availability and productivity, and supplier and subcontractor pricing and performance unless they result from customer-requested change orders. Under both our fixed-price contracts and our cost-reimbursable contracts, we may rely on third parties for many support services, and we could be subject to liability for their failures. For example, we have experienced losses on certain large fabrication projects that have negatively impacted our fabrication results. Our failure to accurately estimate our costs and the time required for a fixed-price fabrication project could have a material adverse effect on our business, results of operations, cash flows and financial condition.

 

At December 31, 2009, we had approximately $2.3 billion in outstanding debt obligations. Many factors, including factors beyond our control, may affect our ability to make payments on our outstanding indebtedness. These factors include those discussed elsewhere in these Risk Factors and those listed in the Disclosure Regarding Forward-Looking Statements section included in Part I of this report.

 

Our substantial debt and associated commitments could have important adverse consequences. For example, these commitments could:

 

 

As of December 31, 2009, after taking into consideration interest rate swaps, we had approximately $406.4 million of outstanding indebtedness subject to interest at floating rates. Changes in economic conditions outside of our control could result in higher interest rates, thereby increasing our interest expense and reducing the funds available for capital investment, operations or other purposes.

 

Our bank credit facilities, asset-backed securitization facilities and the agreements governing certain of our other indebtedness include various covenants with which we must comply, including, but not limited to, limitations on incurrence of indebtedness, investments, liens on assets, transactions with affiliates, mergers, consolidations, sales of assets and other provisions customary in similar types of agreements. For example, we must maintain various consolidated financial ratios including a ratio of EBITDA (as defined in the credit agreement) to Total Interest Expense (as defined in the credit agreement) of not less than 2.25 to 1.0, a ratio of consolidated Total Debt (as defined in the credit agreement) to EBITDA of not greater than 5.0 to 1.0 and a ratio of Senior Secured Debt (as defined in the credit agreement) to EBITDA of not greater than 4.0 to 1.0. As of December 31, 2009, we maintained a 6.1 to 1.0 EBITDA to Total Interest Expense ratio, a 3.5 to 1.0 consolidated Total Debt to EBITDA ratio and a 2.8 to 1.0 Senior Secured Debt to EBITDA ratio. As of December 31, 2009, we were in compliance with all financial covenants under our credit agreements. If we fail to remain in compliance with our financial covenants we would be in default under our credit agreements. In addition, if we experience a material adverse effect on our assets, liabilities, financial condition, business, operations or prospects that, taken as a whole, impacted our ability to perform our obligations under our credit agreements, this could lead to a default under our credit agreements. A default under one or more of our debt agreements would in some situations trigger cross-default provisions under certain agreements relating to our debt obligations. If our operations in Venezuela had been excluded from our calculation of EBITDA for the year ended December 31, 2009, we would have had a 5.9 to 1.0 EBITDA to Total Interest Expense ratio, a 3.7 to 1.0 consolidated Total Debt to EBITDA ratio and a 2.9 to 1.0 Senior Secured Debt to EBITDA ratio.

 

The Partnership’s credit facility and asset-backed securitization facility also include covenants limiting its ability to make distributions, incur indebtedness, grant liens, merge, make loans, acquisitions, investments or dispositions and engage in transactions with affiliates. The Partnership must maintain various consolidated financial ratios, including a ratio of EBITDA (as defined in the Partnership Credit Agreement) to Total Interest Expense (as defined in the Partnership Credit Agreement) of not less than 2.5 to 1.0, and a ratio of Total Debt (as defined in the Partnership Credit Agreement) to EBITDA of not greater than 5.0 to 1.0. As of December 31, 2009, the Partnership maintained a 5.2 to 1.0 EBITDA to Total Interest Expense ratio and a 4.0 to 1.0 Total Debt to EBITDA ratio. The Partnership Credit Agreement allows for the Partnership’s Total Debt to EBITDA ratio to be increased from 5.0 to 1.0 to 5.5 to 1.0 during a quarter when an acquisition closes meeting certain thresholds and for the following two quarters after the acquisition closes. Therefore, because the Partnership acquired from us additional contract operations customer service agreements and a fleet of compressor units used to provide compression services under those agreements, which met the applicable thresholds in the fourth quarter of 2009, the maximum allowed ratio of Total Debt to EBITDA was increased from 5.0 to 1.0 to 5.5 to 1.0 for the period from December 31, 2009 through June 30, 2010. After June 30, 2010, the Partnership’s required Total Debt to EBITDA ratio will revert to 5.0 to 1.0. As of December 31, 2009, the Partnership was in compliance with all financial covenants under the Partnership Credit Agreement.

 

As of December 31, 2009, due to certain covenant limitations under the facility, only approximately $58.2 million of the $230.0 million in unfunded commitments could have been available for additional borrowings, if such facility were fully funded with all eligible contract compression assets available at that time. If our operations within Exterran ABS experience additional reductions in cash flows, the amount available for additional borrowings could be further reduced.

 

If we continue to experience a significant deterioration in the demand for our products or services, we may not be able to comply with certain of the covenants associated with our indebtedness. The breach of any of our covenants could result in a default under one or more of our debt agreements, which could cause our

indebtedness under those agreements to become due and payable. In addition, a default under one or more of our debt agreements, including a default by the Partnership under its credit facilities, would trigger cross-default provisions under certain of our debt agreements, which would accelerate our obligation to repay our indebtedness under those agreements. If the Partnership continues to experience a deterioration in the demand for its services, and is unable to consummate further acquisitions from us, amend its senior secured credit facility or restructure its debt, it estimates that it could be in violation of the maximum Total Debt to EBITDA covenant ratio contained in its senior secured credit facility during 2010. The breach of this or any other covenant could result in a default under the Partnership’s credit agreement, which could cause its indebtedness under the credit agreement to become due and payable. If the repayment obligations on any of our indebtedness were to be so accelerated, we may not be able to repay the debt or refinance the debt on acceptable terms, and our financial position would be materially adversely affected.

 

The length of our contract operations services contracts with customers varies based on operating conditions and customer needs. In most cases, based on currently prevailing services rates, our initial contract terms are not long enough to enable us to fully recoup the cost of the equipment we utilize to provide contract operations services. We cannot be sure that a substantial number of these customers will continue to renew their contracts, that we will be able to enter into new contract operations services contracts with customers or that any renewals will be at comparable rates. The inability to renew a substantial portion of our contract operations services contracts, or the inability to renew a substantial portion of our contract operations services contracts at comparable service rates, would lead to a reduction in revenues and net income and could require us to record additional asset impairments. This would have a material adverse effect upon our business, financial condition, results of operations and cash flows.

 

Some of the components used in our products are obtained from a single source or a limited group of suppliers. Our reliance on these suppliers involves several risks, including price increases, inferior component quality and a potential inability to obtain an adequate supply of required components in a timely manner. The partial or complete loss of certain of these sources could have a negative impact on our results of operations and could damage our customer relationships. Further, a significant increase in the price of one or more of these components could have a negative impact on our results of operations.

 

Our industry is highly competitive and there are low barriers to entry, especially in North America. We expect to experience competition from companies that may be able to adapt more quickly to technological changes within our industry and throughout the economy as a whole, more readily take advantage of acquisitions and other opportunities and adopt more aggressive pricing policies. Our ability to renew or replace existing contract operations service contracts with our customers at rates sufficient to maintain current revenue and cash flows could be adversely affected by the activities of our competitors. If our competitors substantially increase the resources they devote to the development and marketing of competitive products or services or substantially decrease the price at which they offer their products or services, we may not be able to compete effectively. Some of these competitors may expand or fabricate new compression units that would create additional competition for the services we currently provide to our customers. In addition, our other lines of business could face significant competition.

 

We also may not be able to take advantage of certain opportunities or make certain investments because of our significant leverage and our other obligations. Any of these competitive pressures could have a material adverse effect on our business, results of operations and financial condition.

 

Our operations entail inherent risks, including equipment defects, malfunctions and failures and natural disasters, which could result in uncontrollable flows of natural gas or well fluids, fires and explosions. These risks may expose us, as an equipment operator and fabricator, to liability for personal injury, wrongful death, property damage, pollution and other environmental damage. The insurance we carry against many of these risks may not be adequate to cover our claims or losses. We currently have a minimal amount of insurance on our offshore assets. In addition, 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. Further, insurance covering the risks we expect to face or in the amounts we desire may not be available in the future or, if available, the premiums may not be commercially justifiable. If we were to incur substantial liability and such damages were not covered by insurance or were in excess of policy limits, or if we were to incur liability at a time when we were not able to obtain liability insurance, our business, results of operations and financial condition could be negatively impacted.

 

The anticipated after-tax economic benefit of an investment in the Partnership’s common units depends largely on it being treated as a partnership for U.S. federal income tax purposes. The Partnership has not received a ruling from the Internal Revenue Service (“IRS”) on this or any other tax matter affecting it.

 

If the Partnership were treated as a corporation for U.S. federal income tax purposes, it would pay U.S. federal income tax at the corporate tax rate and would also likely pay state income tax. Treatment of the Partnership as a corporation for U.S. federal income tax purposes would result in a material reduction in the anticipated cash flow and after-tax return to its unitholders, likely causing a substantial reduction in the value of its common units.

 

Current law may change so as to cause the Partnership to be treated as a corporation for U.S. federal income tax purposes or otherwise subject it to entity-level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. The Partnership’s partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects it to taxation as a corporation or otherwise subjects it to entity-level taxation for U.S. federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels of the Partnership may be adjusted to reflect the impact of that law on it at the option of its general partner without the consent of its unitholders. If the Partnership were to be taxed at the entity level, it would lose the comparative cost of capital advantage we believe it has over time as compared to a corporation.

 

The present U.S. federal income tax treatment of publicly traded partnerships, including the Partnership, or our investment in the Partnership may be modified by administrative, legislative or judicial interpretation at any time. For example, judicial interpretations of the U.S. federal income tax laws may have a direct or indirect impact on the Partnership’s status as a partnership and, in some instances, a court’s conclusions may heighten the risk of a challenge regarding the Partnership’s status as a partnership. Moreover, members of Congress have considered substantive changes to the existing U.S. federal income tax laws that would have affected

publicly traded partnerships. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively. Although the legislation considered would not have appeared to affect the Partnership’s tax treatment as a partnership, we are unable to predict whether any of these changes, or other proposals, will be reconsidered or will ultimately be enacted. Any such changes or differing judicial interpretations of existing laws could negatively impact the value of our investment in the Partnership.

 

In March 2009, the EPA formally proposed new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines. The rule, when finalized by the EPA, may require us to undertake significant expenditures, including expenditures for purchasing and installing emissions control equipment such as oxidation catalysts or non-selective catalytic reduction equipment, imposing more stringent maintenance practices, and implementing additional monitoring practices on a potentially significant percentage of our natural gas compressor engine fleet. At this point, we cannot predict the final regulatory requirements or the cost to comply with such requirements. The comment period on the proposed regulation ended on June 3, 2009, and the EPA has signed a consent decree requiring it to promulgate a final rule no later than August 10, 2010. Under the proposal, compliance will be required by three years from the effective date of the final rule. This proposed rule, when finalized, and any other new regulations requiring the installation of more sophisticated emission control equipment could have a material adverse impact on our business, financial condition, results of operations and cash flows.

 

We are subject to a variety of U.S. federal, state, local and international laws and regulations relating to the environment, health and safety, export controls, currency exchange, labor and employment and taxation. These laws and regulations are complex, change frequently and have tended to become more stringent over time. Failure to comply with these laws and regulations may result in a variety of administrative, civil and criminal enforcement measures, including assessment of monetary penalties, imposition of remedial requirements and issuance of injunctions as to future compliance. From time to time, as part of our operations, including newly acquired operations, we may be subject to compliance audits by regulatory authorities in the various countries in which we operate.

 

Environmental laws and regulations may, in certain circumstances, impose strict liability for environmental contamination, which may render us liable for remediation costs, natural resource damages and other damages as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior owners or operators or other third parties. In addition, where contamination may be present, it is not uncommon for neighboring land owners and other third parties to file claims for personal injury, property damage and recovery of response costs. Remediation costs and other damages arising as a result of environmental laws and regulations, and costs associated with new information, changes in existing environmental laws and regulations or the adoption of new environmental laws and regulations could be substantial and could negatively impact our financial condition or results of operations.

 

We may need to apply for or amend facility permits or licenses from time to time with respect to storm water 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 compliance and permitting obligations.

 

We conduct operations at numerous facilities in a wide variety of locations across the continental U.S. and internationally. The operations at many of these facilities require environmental permits or other authorizations. Additionally, natural gas compressors at many of our customers’ facilities require individual air permits or general authorizations to operate under various air regulatory programs established by rule or

regulation. These permits and authorizations frequently contain numerous compliance requirements, including monitoring and reporting obligations and operational restrictions, such as emission limits. Given the large number of facilities in which we operate, and the numerous environmental permits and other authorizations that are applicable to our operations, we may occasionally identify or be notified of technical violations of certain requirements existing in various permits or other authorizations. Occasionally, we have been assessed penalties for our non-compliance, and we could be subject to such penalties in the future.

 

We routinely deal with natural gas, oil and other petroleum products. Hydrocarbons or other hazardous substances or wastes may have been disposed or released on, under or from properties used by us to provide contract operations services or inactive compression storage or on or under other locations where such substances or wastes have been taken for disposal. These properties may be subject to investigatory, remediation and monitoring requirements under environmental laws and regulations.

 

The modification or interpretation of existing environmental laws or regulations, the more vigorous enforcement of existing environmental laws or regulations, or the adoption of new environmental laws or regulations may also negatively impact oil and natural gas exploration and production, gathering and pipeline companies, which in turn could have a negative impact on us.

 

The U.S. Congress is considering new legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane, that are understood to contribute to global warming. For example, the American Clean Energy and Security Act of 2009 could, if enacted by the full Congress, require greenhouse gas emissions reductions by covered sources of as much as 17% from 2005 levels by 2020 and by as much as 83% by 2050. In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address greenhouse gas emissions, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Although most of the state-level initiatives have to date been focused on large sources of greenhouse gas emissions, such as electric power plants, it is possible that smaller sources such as our gas-fired compressors could become subject to greenhouse gas-related regulation. Depending on the particular program, we could be required to control emissions or to purchase and surrender allowances for greenhouse gas emissions resulting from our operations.

 

Also, as a result of the U.S. Supreme Court’s decision on April 2, 2007 in Massachusetts, et al. v. EPA, the EPA may regulate greenhouse gas emissions from mobile sources such as new motor vehicles, even if Congress does not adopt new legislation specifically addressing emissions of greenhouse gases. The Court held in Massachusetts v. EPAthat greenhouse gases including carbon dioxide fall under the CAA’s definition of “air pollutant.” In July 2008, on the basis of this decision, the EPA released an “Advance Notice of Proposed Rulemaking” regarding possible future regulation of greenhouse gas emissions under the CAA. In the notice, the EPA evaluated the potential regulation of greenhouse gases under several different provisions of the CAA, but did not propose any specific new regulatory requirements for greenhouse gases. The notice and three other recent regulatory developments, described below, along with recent statements by the Administrator of the EPA, suggest that the EPA is beginning to pursue a path toward the regulation of greenhouse gas emissions under its existing CAA authority. First, in September 2009, the EPA adopted a new rule requiring approximately 13,000 facilities comprising a substantial percentage of annual U.S. greenhouse gas emissions to inventory their emissions starting in 2010 and to report those emissions to the EPA beginning in 2011. That rule, at least for now, does not apply to oil and gas systems. Second, on December 15, 2009, the EPA officially published its finalized determination that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings by the EPA pave the way for the agency to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the CAA. Third, the EPA in late September 2009 proposed a rule that would provide for the tailored application of the agency’s major air permitting programs to facilities that annually emit over 25,000 tons of greenhouse gases, such as large industrial facilities of the type covered by the inventory rule described above.

Although it is not currently possible to predict how any such proposed or future greenhouse gas legislation or regulation by Congress, the states or multi-state regions will impact our business, any legislation or regulation of greenhouse gas emissions that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions or reduced demand for our products and services, and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

Some of the factors that could affect the price of our common stock are quarterly increases or decreases in revenue or earnings, changes in revenue or earnings estimates by the investment community and speculation in the press or investment community about our financial condition or results of operations. General market conditions and North America or international economic factors and political events unrelated to our performance may also affect our stock price. In addition, the price of our common stock may be impacted by changes in the value of our investment in the Partnership. For these reasons, investors should not rely on recent trends in the price of our common stock to predict the future price of our common stock or our financial results.

 

As part of our business strategy, we intend to contribute or sell the remainder of our U.S. contract operations business to the Partnership, over time, but we are under no obligation to do so. Likewise, the Partnership is under no obligation to purchase any additional portions of that business. The consummation of any future sales of additional portions of that business and the timing of such sales will depend upon, among other things:

 

 

The Partnership intends to fund its future acquisitions from us with external sources of capital, including additional borrowings under its credit facilitiesand/orpublic or private offerings of equity or debt. As a result of the economic slowdown and the availability of equity and debt capital, the Partnership’s ability to fund future acquisitions of our U.S. contract operations business may be limited.

 

If we are unable to consummate additional contributions or sales of our U.S. contract operations business to the Partnership, we may not be able to capitalize on what we believe is the Partnership’s lower cost of capital over time, which could impact our competitive position in the U.S. Additionally, without the proceeds from future contributions or sales of our U.S. contract operations business to the Partnership, we will have less capital to invest to grow our business.

 

There are provisions in our restated certificate of incorporation and bylaws that may make it more difficult for a third party to acquire control of us, even if a change in control would result in the purchase of our stockholders’ shares of common stock at a premium to the market price or would otherwise be beneficial to our stockholders. For example, our restated certificate of incorporation authorizes the board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it

could be more difficult for a third party to acquire us. In addition, provisions of our restated certificate of incorporation and bylaws, such as limitations on stockholder actions by written consent and on stockholder proposals at meetings of stockholders, could make it more difficult for a third party to acquire control of us. Delaware corporation law may also discourage takeover attempts that have not been approved by the board of directors.

 

None.

 

The following table describes the material facilities we owned or leased as of December 31, 2009:

 

 

Our executive offices are located at 16666 Northchase Drive, Houston, Texas 77060 and our telephone number is(281) 836-7000.

 

In the ordinary course of business we are involved in various pending or threatened legal actions. 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; however, because of the inherent uncertainty of litigation, we cannot provide assurance that the resolution of any particular claim or proceeding to which we are a party will not have a material adverse effect on our consolidated financial position, results of operations or cash flows for the period in which the resolution occurs.

 

No matters were submitted to a vote of our stockholders during the fourth quarter of our fiscal year ended December 31, 2009.

 

Our common stock is traded on the New York Stock Exchange under the symbol “EXH.” The following table sets forth the range of high and low sale prices for our common stock for the periods indicated.

 

 

On February 12, 2010, the closing price of our common stock was $21.08 per share. As of February 12, 2010, there were approximately 1,097 holders of record of our common stock.

The performance graph below shows the cumulative total stockholder return on our common stock and, prior to the merger, Hanover’s common stock, compared with the S&P 500 Composite Stock Price Index (the “S&P 500 Index”) and the Oilfield Service Index (the “OSX”) over the five-year period beginning on December 31, 2004. The results for the period from December 31, 2004 through August 20, 2007, the date of the merger, reflect Hanover’s historical common stock price adjusted for Hanover’s 0.325 merger exchange ratio. We have used Hanover’s historical common stock price during this period because Hanover was determined to be the acquirer for accounting purposes in the merger. The results for the period from August 21, 2007, when our common stock began trading on the New York Stock Exchange, through December 31, 2009 reflect the price of our common stock. The results are based on an investment of $100 in each of Hanover’s common stock, the S&P 500 Index and the OSX. The graph assumes the reinvestment of dividends and adjusts all closing prices and dividends for stock splits.

 

 

 

We have never declared or paid any cash dividends to our stockholders 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, repurchase company stock, or develop and expand our business, except for a portion of the cash flow generated from operations of the Partnership which will be used to pay a distribution on its units not owned by us. Any future determinations to pay cash dividends to our stockholders will be at the discretion of the 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.

 

In August 2007, our board of directors authorized the repurchase of up to $200 million of our common stock through August 2009. In December 2008, our board of directors increased the share repurchase program, from $200 million to $300 million, and extended the expiration date of the authorization, from August 19, 2009 to December 15, 2010. Under the stock repurchase program, we may repurchase shares in open market purchases or in privately negotiated transactions in accordance with applicable insider trading and other securities laws and regulations. We may also implement all or part of the repurchases under aRule 10b5-1trading plan, so as to provide the flexibility to extend our share repurchases beyond the quarterly purchase window. During the year ended December 31, 2009, we did not repurchase any shares of our common stock under this program. Since the program was initiated, we have repurchased 5,416,221 shares of our common stock at an aggregate cost of $199.9 million.

 

For disclosures regarding securities authorized for issuance under equity compensation plans, see Part III, Item 12 (“Security Ownership of Certain Beneficial Owners and Management”) of this report.

 

In the table below we have presented certain selected financial data for Exterran for each of the five years in the period ended December 31, 2009, which has been derived from our audited consolidated financial statements. The following information should be read together with Management’s Discussion and Analysis of Financial Condition and Results of Operations and Financial Statements which are contained in this report (in thousands, except per share data):

 

 

 

We define gross margin as total revenue less cost of sales (excluding depreciation and amortization expense). Gross margin is included as a supplemental disclosure because it is a primary measure used by our management as it represents the results of revenue and cost of sales (excluding depreciation and amortization expense), which are key components of our operations. We believe gross margin is important because it focuses on the current performance of our operations and excludes the impact of the prior historical costs of the assets acquired or constructed that are utilized in those operations, the indirect costs associated with selling, general and administrative (“SG&A”) activities, the impact of our financing methods and income taxes. Depreciation expense may not accurately reflect the costs required to maintain and replenish the operational usage of our assets and therefore may not portray the costs from current operating activity. As an indicator of our operating performance, gross margin should not be considered an alternative to, or more meaningful than, net income (loss) as determined in accordance with generally accepted accounting principles (“GAAP”). Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.

 

Gross margin has certain material limitations associated with its use as compared to net income (loss). These limitations are primarily due to the exclusion of interest expense, depreciation and amortization expense, SG&A expense, impairments and restructuring charges. Each of these excluded expenses is material to our consolidated results of operations. Because we intend to finance a portion of our operations through borrowings, interest expense is a necessary element of our costs and our ability to generate revenue. Additionally, because we use capital assets, depreciation expense is a necessary element of our costs and our ability to generate revenue, and SG&A expenses are necessary costs to support our operations and required corporate activities. To compensate for these limitations, management uses this non-GAAP measure as a supplemental measure to other GAAP results to provide a more complete understanding of our performance.

 

The following table reconciles our net income (loss) to gross margin (in thousands):

 

 

 

We are a global market leader in the full service natural gas compression business and a premier provider of operations, maintenance, service and equipment for oil and natural gas production, processing and transportation applications. Our global customer base consists of companies engaged in all aspects of the oil and natural gas industry, including large integrated oil and natural gas companies, national oil and natural gas companies, independent producers and natural gas processors, gatherers and pipelines. We operate in three primary business lines: contract operations, fabrication and aftermarket services. In our contract operations business line, we own a fleet of natural gas compression equipment and crude oil and natural gas production and processing equipment that we utilize to provide operations services to our customers. In our fabrication business line, we fabricate and sell equipment similar to the equipment that we own and utilize to provide contract operations to our customers. We also fabricate the equipment utilized in our contract operations services. In addition, our fabrication business line provides engineering, procurement and construction services primarily related to the manufacturing of critical process equipment for refinery and petrochemical facilities, the construction of tank farms and the construction of evaporators and brine heaters for desalination plants. In our Total Solutions projects, we provide the engineering design, project management, procurement and construction services necessary to incorporate our products into complete production, processing and compression facilities. Total Solutions products are offered to our customers on a contract operations or on a sale basis. In our aftermarket services business line, we sell parts and components and provide operations, maintenance, overhaul and reconfiguration services to customers who own compression, production, processing, gas treating and other equipment.

 

On August 20, 2007, Hanover and Universal completed their business combination pursuant to a merger. As a result of the merger, each of Universal and Hanover became our wholly-owned subsidiary, and Universal merged with and into us. Hanover was determined to be the acquirer for accounting purposes and, therefore, our financial statements and the financial information included herein reflect Hanover’s historical results for the periods prior to the merger date. For more information regarding the merger, see Note 3 to the Financial Statements.

 

Our business environment and corresponding operating results are affected by the level of energy industry spending for the exploration, development and production of oil and natural gas reserves. Spending by oil and natural gas exploration and production companies is dependent upon these companies’ forecasts regarding the expected future supply and demand for, and future pricing of, oil and natural gas products as well as their estimates of risk-adjusted costs to find, develop and produce reserves. Although we believe our contract operations business is typically less impacted by commodity prices than certain other energy service products and services, changes in oil and natural gas exploration and production spending will normally result in changes in demand for our products and services.

 

Natural Gas Consumption.  Natural gas consumption in the U.S. for the twelve months ended November 30, 2009 decreased by approximately 2% compared to the twelve months ended November 30, 2008. Total natural gas consumption in the U.S. is projected by the EIA to increase by 0.4% in both 2010 and 2011, and is expected to increase by an average of 0.7% per year until 2030. Total natural gas consumption worldwide is projected to increase by an average of 2.4% per year until 2030, according to the EIA.

In 2008, the U.S. accounted for an estimated annual production of approximately 20 trillion cubic feet of natural gas, or 19% of the worldwide total of approximately 110 trillion cubic feet. The EIA estimates that the U.S.’s natural gas production level will be approximately 23 trillion cubic feet in 2030, or 15% of the worldwide total of approximately 153 trillion cubic feet.

 

Natural Gas Compression Services Industry.  We believe the market for our products in the U.S. will continue to have growth opportunities over time due to the following factors, among others:

 

 

While the international natural gas contract compression services market is currently smaller than the U.S. market, we believe there are growth opportunities in international demand for our products due to the following factors:

 

 

Our revenue, earnings and financial position are affected by, among other things, market conditions that impact demand and pricing for natural gas compression and oil and natural gas production and processing and our customers’ decisions regarding whether to utilize our products and services rather than purchase equipment or engage our competitors. In particular, many of our North America contract operations agreements with customers have short initial terms; we cannot be certain that these contracts will be renewed after the end of the initial contractual term, and any such nonrenewal, or renewal at a reduced rate, could adversely impact our results of operations. However, we believe that, barring a significant and extended worldwide recession, industry activity outside of North America should be less affected given the longer-term nature of oil and natural gas infrastructure development projects in international markets.

 

In North America, we believe that the current economic environment and the available supply of idle and underutilized compression equipment owned by our customers and competitors will continue to negatively impact our ability to improve our North America contract operations horsepower utilization and revenues in the near term. In North America, our total operating horsepower decreased by approximately 17% from December 31, 2008 to December 31, 2009, and we expect further horsepower declines into 2010. In international markets, we expect thestart-up of projects in our contract operations backlog will result in an increase in revenues in our international contract operations business in 2010 compared to 2009. Additionally, we believe there will continue to be demand for our contract operations and Total Solutions projects in international markets, and we expect to have opportunities to grow our international business through our contract operations, aftermarket services and fabrication business segments.

 

As industry capital spending declined in 2009, our fabrication business segment experienced a reduction in demand. This decline in demand for our fabrication products led to a reduction in our fabrication backlog and revenue, and continued reductions in industry capital spending may further reduce our fabrication backlog and revenue. Our reduction in fabrication backlog has also been driven by shorter lead times on delivery of major components from our suppliers and, in turn, our lead times in delivering our products to customers.

 

Given the global recession and its impact on activity levels, the matching of our costs and capacity to business levels continues to be challenging. We have taken steps to match our operating costs to current operating

levels and will continue to monitor our expected business levels. For example, in March 2009 we announced that we approved a plan to consolidate our compression fabrication operations, and in May 2009 we announced that we would be reducing operating and general and administrative costs, including headcount reductions, in all facets of our business. Additionally, in August 2009, we announced a plan to further consolidate certain of our fabrication operations.

 

Our level of capital spending depends on the demand for our products and services and the equipment we require to render services to our customers. Although we are not able at this time to predict the final impact of the current market and industry conditions on our business, our level of capital investment in our contract operations fleet assets has declined and, based on current market conditions, we expect that net cash provided by operating activities will be in excess of our requirements to finance our capital expenditures and scheduled debt repayments through December 31, 2010.

 

We intend for the Partnership to be the primary vehicle for the long-term growth of our U.S. contract operations business. In November 2009, the Partnership acquired from us additional contract operations customer service agreements with 18 customers and a fleet of approximately 900 compressor units used to provide compression services under those agreements. We intend to continue to contribute over time additional U.S. contract operations customer contracts and equipment to the Partnership in exchange for cash, the Partnership’s assumption of our debtand/or our receipt of additional interests in the Partnership. Such transactions would depend on, among other things, market and economic conditions, our ability to reach agreement with the Partnership regarding the terms of any purchase and the availability to the Partnership of debt and equity capital on reasonable terms.

 

Market conditions in the natural gas industry, competition in the natural gas compression industry and the risks inherent in our on-going international expansion continue to represent key challenges and uncertainties. In addition to these challenges, we believe the following represent some of the key challenges and uncertainties we will face in the near future:

 

North America Compression Fleet Utilization.  Our ability to increase our revenues in our North America contract operations business is dependent in large part on our ability to increase our utilization of our idle fleet. In North America, we believe that the current economic environment and the available supply of idle and underutilized compression equipment owned by our customers and competitors will continue to negatively impact our ability to improve our North America contract operations horsepower utilization and revenues in the near term. Our total North America operating horsepower decreased by approximately 17% from December 31, 2008 to December 31, 2009, and we expect further horsepower declines into 2010. We believe the decrease in utilization and revenues in North America has been the result of reduced commodity prices and energy activity, an excess supply of gas compression equipment in the industry, and the rationalization of compression equipment by our customers that has included replacing outsourced compression units with customer-owned equipment and downsizing compression units where excess horsepower capacity existed.

 

Execution on Larger Contract Operations and Fabrication Projects.  As our business has grown, the size and scope of some of the contracts with our customers has increased. This increase in size and scope can translate into more technically challenging conditionsand/orperformance specifications. Contracts with our customers generally specify delivery dates, performance criteria and penalties for our failure to perform. Our success on such projects is one of our key challenges. If we do not timely and cost effectively execute on such larger projects, our results of operations and cash flows could be negatively impacted.

 

Labor.  Both in North America and internationally, we believe our ability to hire, train and retain qualified personnel continues to be challenging and important. Although we have been able to satisfy our personnel needs thus far, retaining employees continues to be a challenge. To increase retention of qualified operating personnel, we have instituted programs that enhance skills and provide on-going training. Our ability to continue our growth will depend in part on our success in hiring, training and retaining these employees.

Decline in Activity in the Global Energy Market.  Our results of operations depend upon the level of activity in the global energy market, including natural gas development, production, processing and transportation. Oil and natural gas prices and the level of drilling and exploration activity can be volatile. For example, oil and natural gas exploration and development activity and the number of well completions typically decline when there is a significant reduction in oil and natural gas prices or significant instability in energy markets. We believe the decrease in activity levels in the energy industry in the U.S. as compared to 2008 may continue to negatively impact the level of capital spending by our customers and, therefore, our business activity in the near term.

 

As discussed in Note 2 to the Financial Statements of this report, the results from continuing operations for all periods presented exclude the results of our Venezuela international contract operations and aftermarket services businesses. Those results are now reflected in discontinued operations for all periods presented.

 

Net income (loss) attributable to Exterran stockholders.  We recorded a consolidated net loss attributable to Exterran stockholders of $549.4 million for the year ended December 31, 2009, as compared to a net loss of $947.3 million for the year ended December 31, 2008 and consolidated net income of $34.6 million for the year ended December 31, 2007. Our results for the years ended December 31, 2009, 2008 and 2007 were affected by charges and events that may not necessarily be indicative of our core operations or our future prospects and impact comparability between years.

 

Results by Business Segment.  The following table summarizes revenue, cost of sales and gross margin percentages (defined as revenue less cost of sales, excluding depreciation and amortization expense, divided by revenue) for each of our business segments (dollars in thousands):

 

 

The following tables summarize our total available horsepower, operating horsepower, horsepower utilization percentages and fabrication backlog (horsepower in thousands and dollars in millions):

 

 

 

Revenue.  Revenue for the year ended December 31, 2009 decreased 10% to $2,715.6 million from $3,024.1 million for the year ended December 31, 2008. The decrease in revenue for the year ended December 31, 2009 primarily related to reduced revenue in our North America contract operations, aftermarket services and fabrication business segments caused by deterioration in market conditions.

 

Net income (loss) attributable to Exterran stockholders.  Net loss attributable to Exterran stockholders for the year ended December 31, 2009 was $549.4 million, or a decrease of 42%, as compared to net loss attributable to Exterran stockholders of $947.3 million for the year ended December 31, 2008. Our net loss attributable to

Exterran stockholders for the year ended December 31, 2009 was impacted by deterioration in market conditions as well as the charges listed below.

 

Net income (loss) attributable to Exterran stockholders for the years ended December 31, 2009 and 2008 was impacted by the following charges (in thousands):

 

 

 

 

The decrease in revenue and gross margin (defined as revenue less cost of sales, excluding depreciation and amortization expense) was primarily due to a 10% decrease in average operating horsepower and a 4% reduction in our revenue per average operating horsepower in the year ended December 31, 2009 compared to the year ended December 31, 2008. Gross margin, a non-GAAP financial measure, is reconciled, in total, to net income (loss), its most directly comparable financial measure calculated and presented in accordance with GAAP in Selected Financial Data — Non-GAAP Financial Measure in Part II, Item 6 of this report. Our average operating horsepower declined due to a deterioration in market conditions and natural gas prices in North America. This deterioration and an increased competitive environment resulted in pricing pressure in the year ended December 31, 2009. Revenue for the year ended December 31, 2009 benefited from the inclusion of an additional $12.3 million in revenue from EMIT Water Discharge Technology, LLC (“EMIT”), which we acquired in July 2008.

 

 

The increase in revenues in the year ended December 31, 2009 compared to the year ended December 31, 2008 was primarily caused by an increase in revenue in the Middle East, Brazil and Indonesia of approximately $6.9 million, $5.7 million and $9.2 million, respectively, due to the start up of new contracts in these regions. This was partially offset by a $7.2 million decrease in revenues in Mexico as a result of the expiration of a large contract in 2009.

 

 

 

The decrease in revenue, cost of sales and gross margin was due to lower activity levels in North America in 2009 caused by a decline in market conditions.

 

 

 

The decrease in revenue in the year ended December 31, 2009 compared to the year ended December 31, 2008 was primarily due to a reduction of $148.5 million and $113.3 million in compressor and accessory fabrication product line revenue and production and processing product line revenue, respectively. The decrease in fabrication revenue was due to the completion of various projects and a reduction in new bookings caused by weaker market conditions in 2009, partially offset by a $91.6 million increase in installation product line sales resulting from the completion of installation projects during the year ended December 31, 2009. Our gross margin percentage in the year ended December 31, 2009 was negatively impacted by the increase in installation product line sales which had lower margins compared to the rest of the fabrication segment, the deterioration in market conditions impacting our fabrication business and under-absorption of overhead costs resulting from the decrease in activity.

 

 

The decrease in SG&A expenses was primarily due to our efforts to reduce costs in response to lower business activity levels during the year ended December 31, 2009 compared to the year ended December 31, 2008. As a percentage of revenue, SG&A expense for each of the years ended December 31, 2009 and 2008 was 12%.

 

During the year ended December 31, 2008, merger and integration expenses related to the merger between Hanover and Universal were primarily comprised of professional fees, amortization of retention bonus awards, change of control payments and severance for employees.

 

The increase in depreciation and amortization expense during the year ended December 31, 2009 compared to the year ended December 31, 2008 was primarily the result of property, plant and equipment additions, partially offset by a $10.2 million decrease in amortization expense related to finite life intangible assets resulting from the merger of Hanover and Universal. The intangible assets from the merger are being amortized based on the expected income to be realized from these assets.

 

As a result of a decline in market conditions and operating horsepower in North America during 2009, we reviewed the idle compression assets used in our contract operations segments for units that are not of the type, configuration, make or model that are cost efficient to maintain and operate. As a result of that review, we determined that 1,232 units representing 264,900 horsepower would be retired from the fleet. We performed a cash flow analysis of the expected proceeds from the disposition of these units to determine the fair value of the fleet assets we will no longer utilize in our operations. The net book value of these assets exceeded the fair value by $91.0 million and was recorded as a long-lived asset impairment. During 2008, management identified certain fleet units that will not be used in our contract operations business in the future and recorded a $1.5 million impairment. During 2008, we also recorded a $1.0 million impairment related to the loss sustained on offshore units that were on platforms which capsized during Hurricane Ike. These impairments are recorded in Fleet impairment expense in the consolidated statements of operations.

 

We were involved in the Cawthorne Channel Project to process natural gas from certain Nigerian oil and natural gas fields. The area in Nigeria where the Cawthorne Channel Project was located experienced local civil unrest and violence, and natural gas delivery to the Cawthorne Channel Project was stopped for significant periods of time starting in June 2006. Additionally, in late July 2008, a vessel owned by a third party that provided storage and splitting services for the liquids processed by our facility was the target of a local security incident. As a result, the Cawthorne Channel Project only operated for limited periods of time beginning in June 2006. As a result of operational difficulties and taking into consideration the project’s historical performance and declines in commodity prices, we undertook an assessment of our estimated future cash flows from the Cawthorne Channel Project. Based on the analysis we completed, we did not believe that we would recover all of our remaining investment in the Cawthorne Channel Project. Accordingly, we recorded an impairment charge of $21.6 million in our 2008 results to reduce the carrying amount of our assets associated with the Cawthorne Channel Project to their estimated fair value, which is reflected in Fleet impairment expense in our consolidated statements of operations. During the fourth quarter of 2009, we recorded a pre-tax gain of approximately $20.8 million on the sale of our investment in the subsidiary that

owns the barge mounted processing plant and certain other related assets used on the Cawthorne Channel Project. This gain is recorded in Other (income) expense, net in our consolidated statements of operations.

 

Restructuring charges of $20.3 million for the year ended December 31, 2009 were incurred due to our efforts to adjust our costs to our forecasted business activity levels and included facility impairments, severance and employee benefit costs and other facility closure and moving costs resulting from our decision to close and consolidate certain of our fabrication facilities. See Note 15 to the Financial Statements for further discussion of the restructuring charges.

 

As discussed in Note 2 to the Financial Statements, on June 2, 2009, PDVSA commenced taking possession of our assets and operations in Venezuela. By the end of the second quarter of 2009, PDVSA had assumed control over substantially all of our assets and operations in Venezuela. We determined that this event could indicate an impairment of our international contract operations and aftermarket services reporting units’ goodwill and therefore performed a goodwill impairment test for these reporting units in the second quarter of 2009. Our international contract operations reporting unit failed the goodwill impairment test and we recorded an impairment of goodwill in our international contract operations reporting unit of $150.8 million in the second quarter of 2009. During the year ended December 31, 2008 we recorded a goodwill impairment charge of $1,148.4 million related to our North America contract operations segment. In 2008, there were severe disruptions in the credit and capital markets and reductions in global economic activity which had significant adverse impacts on stock markets andoil-and-gas-relatedcommodity prices, both of which we believe contributed to a significant decline in our stock price and corresponding market capitalization. We determined that the deepening recession and financial market crisis, along with the continuing decline in the market value of our common stock, resulted in an impairment of all the goodwill in our North America contract operations reporting unit. See Note 9 to the Financial Statements for further discussion of these charges.

 

The decrease in interest expense during the year ended December 31, 2009 compared to the year ended December 31, 2008, was primarily due to a decrease in our weighted average effective interest rate, including the impact of interest rate swaps, to 4.8% for the year ended December 31, 2009 from 5.3% for the year ended December 31, 2008.

 

The loss recorded in equity in (income) loss of non-consolidated affiliates for the year ended December 31, 2009 was primarily the result of the expropriation of our Venezuelan joint ventures’ assets and operations during the six months ended June 30, 2009. We currently do not expect to have significant, if any, equity earnings in non-consolidated affiliates in the future from these investments. Our non-consolidated affiliates are expected to seek full compensation for any and all expropriated assets and investments under all applicable legal regimes, including investment treaties and customary international law, which could result in us recording a gain on our investment in future periods. However, we are unable to predict what, if any, compensation we ultimately will receive or when we may receive any such compensation. See Note 8 to the Financial Statements for further discussion of our investments in non-consolidated affiliates.

 

The change in other (income) expense, net, was primarily due to a $31.5 million increase in gains on asset sales in the year ended December 31, 2009 and a foreign currency translation gain of $16.7 million for the year ended December 31, 2009 compared to a loss of $10.7 million for the year ended December 31, 2008. Gain on asset sales for the year ended December 31, 2009 included a pre-tax gain of approximately $20.8 million on the sale of our investment in the subsidiary that owns the barge mounted processing plant and certain other related assets used on the Cawthorne Channel Project. Our foreign currency translation gains and losses are primarily related to the remeasurement of our international subsidiaries’ net assets exposed to changes in foreign currency rates. The increase in the foreign currency translation gain for the year ended December 31, 2009 was primarily caused by changes in the translation rates between the U.S. dollar and the Brazilian Real and Argentine Peso.

 

 

The increase in our provision for income taxes was primarily due to a $14.5 million reduction in deferred tax assets resulting from the restructuring of certain international operations and the sale of a subsidiary, a $7.7 million charge for unrecognized tax benefits related to uncertain tax positions in foreign jurisdictions, and a $5.2 million charge for valuation allowances recorded against net operating losses of certain foreign subsidiaries. The increase was partially offset by lower income before income taxes, excluding $96.6 million of impairment charges reflected in equity in income (loss) of non-consolidated affiliates and a $150.8 million non-deductible goodwill impairment charge related to our international contract operations segment for the year ended December 31, 2009 and a goodwill impairment charge of $1,148.4 million related to our North America contract operations segment for the year ended December 31, 2008. The provision for the year ended December 31, 2009 also included an $8.4 million deferred tax benefit related to the impairment of our investments in non-consolidated affiliates. A $52.9 million deferred tax benefit was recorded in our provision for the year ended December 31, 2008 for the tax deductible portion of the North America contract operations goodwill impairment.

 

 

 

On June 2, 2009, PDVSA commenced taking possession of our assets and operations in a number of our locations in Venezuela. By the end of the second quarter of 2009, PDVSA had assumed control over substantially all of our assets and operations in Venezuela. As a result of PDVSA taking possession of substantially all of our assets and operations in Venezuela, we recorded asset impairments totaling $329.7 million, primarily related to receivables, inventory, fixed assets and goodwill during the year ended December 31, 2009. These asset impairments were partially offset by a $18.6 million benefit primarily from the reversal of deferred income taxes related to our Venezuelan operations in year ended December 31, 2009 compared to a provision for income taxes of $0.2 million in the year ended December 31, 2008. For further information regarding the expropriation, see Note 2 to the Financial Statements.

 

 

As of December 31, 2009, noncontrolling interest is primarily comprised of the portion of the Partnership’s earnings that is applicable to the limited partner interest in the Partnership not owned by us. As of December 31, 2009, public unitholders held a 34% ownership interest in the Partnership.

 

The results of operations for the year ended December 31, 2007 include Universal’s operations for the 134 days from the date of the merger, August 20, 2007, through December 31, 2007. Accordingly, these results of operations are not representative of a full year of operating results for Exterran.

 

Revenue.  Revenue for the year ended December 31, 2008 increased 25% to $3,024.1 million from $2,425.8 million for the year ended December 31, 2007. The increase in revenues in the year ended

December 31, 2008 was primarily due to the inclusion of Universal’s results for the entire period compared to the prior year, which included Universal’s results only after the merger date of August 20, 2007 through the end of the period.

 

Net income (loss) attributable to Exterran stockholders.  Net loss attributable to Exterran stockholders for the year ended December 31, 2008 was $947.3 million, or a decrease of $981.9 million, as compared to net income attributable to Exterran stockholders of $34.6 million for the year ended December 31, 2007. Net loss attributable to Exterran stockholders in the year ended December 31, 2008 includes a goodwill impairment of $1,148.4 million ($1,095.4 million, net of tax). Results for the year ended December 31, 2008 includes Universal’s results for the entire 2008 year period compared to the prior year, which included Universal’s results only after the merger date of August 20, 2007 through the end of the period.

 

Net income (loss) attributable to Exterran stockholders for the years ended December 31, 2008 and 2007 was impacted by the following charges (in thousands):

 

 

 

 

The increase in revenue, cost of sales and gross margin (defined as revenue less cost of sales, excluding depreciation and amortization expense) was primarily due to the inclusion of Universal’s results for the entire year ended December 31, 2008 compared to the prior year, which included Universal’s results only after the merger date of August 20, 2007 through the end of the period. The increase in revenues from Universal after the merger was somewhat offset by a decrease in average utilization in 2008. Revenue for the year ended December 31, 2008 benefited by $13.9 million from the inclusion of the results of EMIT, which we acquired in July 2008. The decrease in gross margin percentage was due to higher costs for labor and consumables and lower average utilization without a corresponding reduction in costs, partially offset by savings that began to be realized from the synergies of the merger.

 

 

The increase in revenue, cost of sales and gross margin was primarily due to the inclusion of Universal’s results for the entire year ended December 31, 2008 compared to the prior year, which included Universal’s results only after the merger date of August 20, 2007 through the end of the period, including an increase of approximately $51.2 million and $36.6 million in Argentina and Brazil, respectively, which accounted for approximately 62% of the increase in revenue.

 

 

 

The increase in revenue, cost of sales and gross margin was primarily due to the inclusion of Universal’s results for the entire year ended December 31, 2008 compared to the prior year, which included Universal’s results only after the merger date of August 20, 2007 through the end of the period. North America aftermarket services accounted for approximately 75% of the increase in revenues. The decrease in gross margin percentage was primarily due to reduced margins on aftermarket services provided internationally.

 

 

 

The increase in revenue, cost of sales and gross margin was primarily due to the inclusion of Universal’s results for the entire year ended December 31, 2008 compared to the prior year, which included Universal’s results only after the merger date of August 20, 2007 through the end of the period, partially offset by approximately $123.7 million less in installation revenues in the year ended December 31, 2008. Results for the year ended December 31, 2007 included the recognition of a $66 million installation project in the Eastern Hemisphere.

Our results for the year ended December 31, 2007 also included approximately $49.1 million of Universal’s revenues related to three projects in the Eastern Hemisphere accounted for under the completed contract method of accounting that were near completion on the merger date and were completed by December 31, 2007. Due to the adjustment to record Universal’s inventory at fair value pursuant to the allocation of the purchase price on the date of merger, the value of the inventory related to these projects was increased to their sales price, which resulted in a gross margin percentage of 0% on these projects. For further information regarding the purchase price allocation with the merger, see Note 3 to the Financial Statements.

 

 

 

The increase in SG&A expenses was primarily due to the inclusion of Universal’s results for the entire year ended December 31, 2008 compared to the prior year, which included Universal’s results only after the merger date of August 20, 2007 through the end of the period. As a percentage of revenue, SG&A for the years ended December 31, 2008 and 2007 was 12% and 10%, respectively.

 

During the year ended December 31, 2008, merger and integration expenses related to the merger between Hanover and Universal were primarily comprised of professional fees, amortization of retention bonus awards, change of control payments and severance for employees. During the year ended December 31, 2007, merger and integration expenses were primarily comprised of amortization of retention bonus awards, acceleration of vesting of restricted stock, stock options and long-term cash incentives, change of control payments for executives and severance for employees.

 

The increase in depreciation and amortization expense was primarily due to the inclusion of Universal’s results for the entire year ended December 31, 2008 compared to the prior year, which included Universal’s results only after the merger date of August 20, 2007 through the end of the period, and property, plant and equipment additions. Amortization expense of intangible assets from the Hanover and Universal merger and other acquisitions was $38.6 million and $15.1 million for the years ended December 31, 2008 and 2007, respectively.

 

We were involved in the Cawthorne Channel Project in Nigeria, in which Global contracted with Shell to process natural gas from some of Shell’s Nigerian oil and natural gas fields. The area in Nigeria where the Cawthorne Channel Project is located has experienced local civil unrest and violence and was not operational for much of the project’s life. As a result of operational difficulties and taking into consideration the project’s historical performance and declines in commodity prices, we undertook an assessment of our estimated future cash flows from the Cawthorne Channel Project. Based on the analysis we completed, we determined we would not recover all of our remaining investment in the Cawthorne Channel Project. Accordingly, we recorded an impairment charge of $21.6 million in our 2008 results to reduce the carrying amount of our assets associated with the Cawthorne Channel Project to their estimated fair value which is reflected in Fleet impairment expense in our consolidated statements of operations.

During 2008, management identified certain fleet units that will not be used in our contract operations business in the future and recorded a $1.5 million impairment. During 2008, we also recorded a $1.0 million impairment related to the loss sustained on offshore units that were on platforms which capsized during Hurricane Ike. In 2007, we recorded an impairment of fleet equipment of $61.9 million. Following completion of the merger between Hanover and Universal, our management reviewed the compression fleet assets used in our business that existed at the merger date. Management reviewed our fleet for units that were not of the type, configuration, make or model that management wanted to continue to offer due to the cost to refurbish the equipment, the incremental costs of maintaining more types of equipment and the increased financial flexibility of the new company to build new units in the configuration currently in demand by our customers. Prior to the merger, we had planned to rebuild or reconfigure these units over time to make them into the configurations currently in demand by customers. We performed a cash flow analysis of the expected proceeds from the disposition to determine the fair value for the fleet assets we decided to dispose of. The net book value of the fleet assets to be disposed of, previously owned by Hanover, exceeded the fair value by $61.9 million, which was recorded as an impairment of our long-lived assets in 2007. These impairments are recorded in Fleet impairment expense in the consolidated statements of operations.

 

We recorded a goodwill impairment charge of $1,148.4 million in 2008. In 2008, there were severe disruptions in the credit and capital markets and reductions in global economic activity which had significant adverse impacts on stock markets andoil-and-gas-relatedcommodity prices, both of which we believe contributed to a significant decline in our stock price and corresponding market capitalization. We determined that the deepening recession and financial market crisis, along with the continuing decline in the market value of our common stock resulted in an impairment of all the goodwill in our North America contract operations reporting unit. See Note 9 for further discussion of this goodwill impairment charge.

 

Interest expense in the year ended December 31, 2008 was impacted by a higher average debt balance due to the addition of Universal’s debt after the merger compared to our average debt balance before the merger and was impacted by a reduction in our weighted average effective interest rate. Interest expense for the year ended December 31, 2007 included a $7.0 million charge from the termination of two fair value hedges. Our weighted average effective interest rate, including the impact of interest rate swaps, decreased to 5.2% for the year ended December 31, 2008 from 6.6% (excluding the $7.0 million charge for termination of interest rate swaps) for the year ended December 31, 2007. The decrease in our effective interest rate was primarily due to the refinancing entered into after the merger.

 

The early extinguishment of debt in the year ended December 31, 2007 relates to the call premium and tender fees paid to retire various Hanover notes as part of the debt refinancing following the merger and a charge of $16.4 million related to the write-off of deferred financing costs in conjunction with that refinancing, which was completed during the third quarter of 2007. For further information regarding the debt refinancing, see Note 11 to the Financial Statements.

 

The increase in equity in income of non-consolidated affiliates was primarily due to higher equity income in our Venezuelan joint venture, PIGAP II, in the year ended December 31, 2008 and a $6.7 million impairment charge recorded in the third quarter of 2007 on our investment in the SIMCO Consortium and Harwat due to the decline in the value of our investment that was determined to be other than temporary. This decline in value of our investment was caused primarily by increased costs to operate the business that were not expected to improve in the near term. We had a 30.0% ownership interest in the PIGAP II joint venture that operates gas compression plants during the year ended December 31, 2008. During the year ended December 31, 2008, we recorded equity income of $20.2 million related to PIGAP II compared to $16.0 million in equity income for the year ended December 31, 2007. The increase in equity in income from our investment in PIGAP II was primarily due to an increase in the volume of gas processed from an expansion of the scope of the project during the year ended December 31, 2008.

 

The change in other (income) expense, net, was primarily due to foreign currency translation losses of $10.7 million for the year ended December 31, 2008 compared to a gain of $7.8 million for the year ended December 31, 2007. The foreign currency translation losses are primarily related to the remeasurement of our international subsidiaries’ net assets exposed to changes in foreign currency rates and a $3.9 million loss on a

foreign currency hedge in the year ended December 31, 2008. The increase in the foreign currency translation losses for year ended December 31, 2008 was primarily caused by the U.S. dollar strengthening compared to the Canadian dollar, Brazilian Real and Euro in the year ended December 31, 2008. The change in other (income) expense, net was also impacted by a $3.0 million decrease in gains on sales of used equipment in the year ended December 31, 2008.

 

 

 

The increase in our provision for income taxes was primarily due to an increase in income before income taxes, excluding a goodwill impairment charge of $1,148.4 million, partially offset by the tax deductible portion of the goodwill impairment of $143.1 million. The change in our provision for income taxes was further impacted by (i) a $10.8 million increase primarily related to benefits recorded in 2007 from the reversal of valuation allowances recorded against net operating losses of certain foreign subsidiaries, (ii) a $3.9 million charge for foreign tax audit assessments received in 2008, (iii) a $3.5 million charge for the tax effect of enacted state and foreign tax law changes in 2008 as compared to 2007 and (iv) a $5.3 million benefit from increased foreign tax credits claimed in 2008 as compared to 2007.

 

 

As of December 31, 2008, noncontrolling interest is primarily comprised of the portion of the Partnership’s earnings that is applicable to the interest in the Partnership not owned by us. We acquired our ownership of the Partnership through the merger with Universal (see Note 3 to the Financial Statements). Noncontrolling interest was higher in the year ended December 31, 2008 primarily due to the inclusion of the Partnership’s results for the entire period compared to the prior year, which included the Partnership’s results only after the merger date of August 20, 2007 through the end of the period.

 

 

 

The income from discontinued operations, net of tax for the years ended December 31, 2008 and 2007 of $46.8 million and the $44.8 million, respectively, relates to operations in Venezuela before substantially all of our assets and operations in Venezuela were expropriated in June 2009. See Note 2 to the Financial Statements for further information regarding the expropriation.

 

Our unrestricted cash balance was $83.7 million at December 31, 2009, compared to $123.9 million at December 31, 2008. Working capital from continuing operations decreased to $545.9 million at December 31, 2009 from $676.4 million at December 31, 2008.

Our cash flows from operating, investing and financing activities, as reflected in the consolidated statements of cash flows, are summarized in the table below (in thousands):

 

 

Operating Activities.  The increase in cash provided by operating activities for the year ended December 31, 2009 was primarily due to an increase in cash provided by a reduction in working capital, partially offset by a reduction in gross margin from our North America contract operations and fabrication segments as compared to the year ended December 31, 2008.

 

Investing Activities.  The decrease in cash used in investing activities was primarily attributable to reduced capital expenditures during the year ended December 31, 2009 and approximately $133.6 million cash used for acquisitions in the year ended December 31, 2008.

 

Financing Activities.  The increase in cash used in financing activities during the year ended December 31, 2009 compared to the year ended December 31, 2008 was primarily attributable to an increase in net debt repayments and the use of cash for the net cost of the call options purchased and the warrants sold in connection with the offering of our 4.25% convertible senior notes due June 2014 (the “4.25% Notes”) in the year ended December 31, 2009 compared to the year ended December 31, 2008. This increase was partially offset by reduced repurchases of our common stock during the year ended year ended December 31, 2009.

 

Capital Expenditures.  We generally invest funds necessary to fabricate fleet additions when our idle equipment cannot be reconfigured to economically fulfill a project’s requirements and the new equipment expenditure is expected to generate economic returns over its expected useful life that exceed our targeted return on capital. We currently plan to spend approximately $250 million to $300 million in net capital expenditures during 2010, including (1) contract operations equipment additions and (2) approximately $100 million to $110 million on equipment maintenance capital related to our contract operations business. Net capital expenditures are net of fleet sales.

 

Long-Term Debt.  As of December 31, 2009, we had approximately $2.3 billion in outstanding debt obligations, consisting of $570.0 million outstanding under our 2007 ABS Facility (as defined below), $780.0 million outstanding under our term loan, $68.9 million outstanding under our revolving credit facility, $143.8 million outstanding under our 4.75% convertible notes due 2014, $265.5 million outstanding under our 4.25% Notes, $285.0 million outstanding under the Partnership’s revolving credit facility, $117.5 million outstanding under the Partnership’s term loan and $30.0 million outstanding under the Partnership’s 2009 ABS Facility.

 

On August 20, 2007, we entered into a senior secured credit agreement (the “Credit Agreement”) with various financial institutions. The Credit Agreement consists of (a) a five-year revolving credit facility in the aggregate amount of $850 million, which includes a variable allocation for a Canadian tranche and the ability to issue letters of credit under the facility and (b) a six-year term loan, in the aggregate amount of $800 million with principal payments due on multiple dates through June 2013 (collectively, the “Credit Facility”). Subject to certain conditions as of December 31, 2009, at our request and with the approval of the lenders, the aggregate commitments under the Credit Facility may be increased by an additional $400 million less certain adjustments.

As of December 31, 2009, we had $68.9 million in outstanding borrowings and $303.5 million in letters of credit outstanding under our revolving credit facility and $780.0 million in outstanding borrowings under our term loan. Additional borrowings of up to approximately $477.6 million were available under the revolving credit facility.

 

Borrowings under the Credit Agreement bear interest, if they are in U.S. dollars, at a base rate or LIBOR at our option plus an applicable margin, as defined in the agreement. The applicable margin varies depending on our debt ratings. At December 31, 2009, all amounts outstanding were LIBOR loans and the applicable margin was 0.825%. The weighted average interest rate at December 31, 2009 on the outstanding balance, excluding the effect of interest rate swaps, was 1.1%.

 

The Credit Agreement contains various covenants with which we must comply, including, but not limited to, limitations on incurrence of indebtedness, investments, liens on assets, transactions with affiliates, mergers, consolidations, sales of assets and other provisions customary in similar types of agreements. We must also maintain, on a consolidated basis, required leverage and interest coverage ratios. Additionally, the Credit Agreement contains customary conditions, representations and warranties, events of default and indemnification provisions. Our indebtedness under the Credit Facility is collateralized by liens on substantially all of our personal property in the U.S. The assets of the Partnership and our wholly-owned subsidiary, Exterran ABS 2007 LLC (along with its subsidiary, “Exterran ABS”), are not collateral under the Credit Agreement. Exterran Canada, Limited Partnership’s indebtedness under the Credit Facility is collateralized by liens on substantially all of its personal property in Canada. We have executed a U.S. Pledge Agreement pursuant to which we and our Significant Subsidiaries (as defined in the Credit Agreement) are required to pledge our equity and the equity of certain subsidiaries. The Partnership and Exterran ABS are not pledged under this agreement and do not guarantee debt under the Credit Facility.

 

In August 2007, Exterran ABS entered into a $1.0 billion asset-backed securitization facility (the “2007 ABS Facility”), which was reduced to an $800 million facility in October 2009 concurrent with the closing of the Partnership’s new $150 million asset-backed securitization facility. The amount outstanding at any time is limited to the lower of (i) 80% of the value of the natural gas compression equipment owned by Exterran ABS and its subsidiaries, (ii) 4.5 times free cash flow or (iii) the amount calculated under an interest coverage test (as these limits are defined in the agreement). Based on these tests, the limit on the amount outstanding can be increased or decreased in future periods. As of December 31, 2009, we had $570.0 million in outstanding borrowings under the 2007 ABS Facility and $230.0 million of unfunded commitments. As of December 31, 2009, due to certain covenant limitations under the facility, only approximately $58.2 million of the $230.0 million in unfunded commitments could have been available for additional borrowings, if such facility were fully funded with all eligible contract compression assets available at that time. If our operations within Exterran ABS experience additional reductions in cash flows, the amount available for additional borrowings could be further reduced. As a result of our expectations for further reductions in our North America contract operations business, we currently expect the limit on the amount outstanding to be further reduced in 2010. If the outstanding borrowings exceed the amount allowed based on the limitations, we can utilize either certain cash flows from Exterran ABS’s operations or borrowings under our revolving credit facility, or a combination of both, to reduce the amount of borrowings outstanding to the amount allowed pursuant to the limitations. In February 2010, we made a $40.0 million payment on the 2007 ABS Facility using cash flows from operations.

 

Interest and fees payable to the noteholders accrue on these notes at a variable rate consisting of one month LIBOR plus an applicable margin of 0.825%. The weighted average interest rate at December 31, 2009 on borrowings under the 2007 ABS Facility, excluding the effect of interest rate swaps, was 1.1%. The 2007 ABS Facility is revolving in nature and is payable in July 2012.

 

Repayment of the 2007 ABS Facility notes has been secured by a pledge of all of the assets of Exterran ABS, consisting primarily of specified compression services contracts and a fleet of natural gas compressors. Under the 2007 ABS Facility, we had $12.9 million of restricted cash as of December 31, 2009.

 

In June 2009, we issued under our shelf registration statement $355.0 million aggregate principal amount of 4.25% Notes, including $30.0 million issued under the underwriter’s overallotment option. The 4.25% Notes are convertible upon the occurrence of certain conditions into shares of our common stock at an initial

conversion rate of 43.1951 shares of our common stock per $1,000 principal amount of the convertible notes, equivalent to an initial conversion price of approximately $23.15 per share of common stock. The conversion rate will be subject to adjustment following certain dilutive events and certain corporate transactions. We may not redeem the notes prior to the maturity date of the notes.

 

The 4.25% Notes are our senior unsecured obligations and rank senior in right of payment to our existing and future indebtedness that is expressly subordinated in right of payment to the 4.25% Notes; equal in right of payment to our existing and future unsecured indebtedness that is not so subordinated; junior in right of payment to any of our secured indebtedness to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness and liabilities incurred by our subsidiaries. The 4.25% Notes are not guaranteed by any of our subsidiaries.

 

In connection with the offering of the 4.25% Notes, we purchased call options on our stock at approximately $23.15 per share of common stock and sold warrants on our stock at approximately $32.67 per share of common stock. These transactions economically adjust the effective conversion price to $32.67 for $325.0 million of the 4.25% Notes and therefore are expected to reduce the potential dilution to our common stock upon any such conversion. We used $36.3 million of the net proceeds from this debt offering and the full $53.1 million of the proceeds from the warrants sold to pay the cost of the purchased call options, and the remaining net proceeds from this debt offering to repay approximately $173.8 million of indebtedness under our revolving credit facility and approximately $135.0 million of indebtedness outstanding under the 2007 ABS Facility.

 

The Partnership, as guarantor, and EXLP Operating LLC, a wholly-owned subsidiary of the Partnership (together with the Partnership, the “Partnership Borrowers”), are parties to a senior secured credit agreement (the “Partnership Credit Agreement”) that provides for a five-year, $315 million revolving credit facility that matures in October 2011. As of December 31, 2009, there was $285.0 million in outstanding borrowings under the revolving credit facility and $30.0 million was available for additional borrowings.

 

The Partnership’s revolving credit facility bears interest at a base rate or LIBOR, at the Partnership’s option, plus an applicable margin, as defined in the agreement. At December 31, 2009 all amounts outstanding were LIBOR loans and the applicable margin was 1.75%. The weighted average interest rate on the outstanding balance of the Partnership’s revolving credit facility, at December 31, 2009, excluding the effect of interest rate swaps, was 2.1%.

 

In May 2008, the Partnership Borrowers entered into an amendment to the Partnership Credit Agreement that increased the aggregate commitments under that facility to provide for a $117.5 million term loan facility. The $117.5 million term loan was funded during July 2008 and $58.3 million was drawn on the Partnership’s revolving credit facility, which together were used to repay the debt assumed by the Partnership concurrent with the closing of the acquisition by the Partnership from us of certain contract compression assets and to pay other costs incurred. The $117.5 million term loan isnon-amortizingbut must be repaid with the net cash proceeds from any equity offerings of the Partnership until paid in full.

 

The term loan bears interest at a base rate or LIBOR, at the Partnership’s option, plus an applicable margin. Borrowings under the term loan are subject to the same credit agreement and covenants as the Partnership’s revolving credit facility, except for an additional covenant requiring mandatory prepayment of the term loan from net cash proceeds of any future equity offerings of the Partnership, on a dollar-for-dollar basis. At December 31, 2009, all amounts outstanding were LIBOR loans and the applicable margin was 2.25%. The weighted average interest rate on the outstanding balance of the Partnership’s term loan at December 31, 2009, excluding the effect of interest rate swaps, was 2.5%.

 

Borrowings under the Partnership Credit Agreement are secured by substantially all of the personal property assets of the Partnership Borrowers, other than the assets of EXLP ABS 2009 LLC and its subsidiaries, which secure the Partnership’s asset-backed securitization facility discussed below. In addition, all of the membership interests of the Partnership’s restricted subsidiaries have been pledged to secure the obligations under the Partnership Credit Agreement. Subject to certain conditions, at the Partnership’s request, and with the approval of the lenders, the aggregate commitments under the Partnership’s senior secured credit facility may be

increased by an additional $17.5 million. This amount will be increased on a dollar-for-dollar basis with each payment under the term loan facility.

 

In October 2009, the Partnership entered into a new $150 million asset-backed securitization facility (the “2009 ABS Facility”). The 2009 ABS Facility notes are revolving in nature and are payable in July 2013. Interest and fees payable to the noteholders accrue on these notes at a variable rate consisting of an applicable margin of 3.5% plus, at the Partnership’s option, either LIBOR or a base rate. The weighted average interest rate on the outstanding balance of the 2009 ABS Facility at December 31, 2009, excluding the effect of interest rate swaps, was 3.8%. Repayment of the 2009 ABS Facility notes has been secured by a pledge of all of the assets of EXLP ABS 2009 LLC and its subsidiaries, consisting primarily of specified compression services contracts and a fleet of natural gas compressor units. The amount outstanding at any time is limited to the lower of (i) 75% of the value of the natural gas compression equipment owned by EXLP ABS 2009 LLC and its subsidiaries (as defined in the agreement), (ii) 4.0 times free cash flow or (iii) the amount calculated under an interest coverage test. Additionally, the Partnership Credit Agreement limits the amount we can borrow under the 2009 ABS Facility to two times the Partnership’s EBITDA (as defined in the Partnership Credit Agreement). As of December 31, 2009, there was $30.0 million in outstanding borrowings under the 2009 ABS Facility and $120.0 million of unfunded commitments. Under the 2009 ABS Facility, the Partnership had $0.4 million of restricted cash as of December 31, 2009.

 

Our bank credit facilities, asset-backed securitization facilities and the agreements governing certain of our other indebtedness include various covenants with which we must comply, including, but not limited to, limitations on incurrence of indebtedness, investments, liens on assets, transactions with affiliates, mergers, consolidations, sales of assets and other provisions customary in similar types of agreements. For example, under our Credit Agreement we must maintain various consolidated financial ratios including a ratio of EBITDA (as defined in the Credit Agreement) to Total Interest Expense (as defined in the Credit Agreement) of not less than 2.25 to 1.0, a ratio of consolidated Total Debt (as defined in the Credit Agreement) to EBITDA of not greater than 5.0 to 1.0 and a ratio of Senior Secured Debt (as defined in the Credit Agreement) to EBITDA of not greater than 4.0 to 1.0. As of December 31, 2009, we maintained a 6.1 to 1.0 EBITDA to Total Interest Expense ratio, a 3.5 to 1.0 consolidated Total Debt to EBITDA ratio and a 2.8 to 1.0 Senior Secured Debt to EBITDA ratio. If we fail to remain in compliance with our financial covenants we would be in default under our credit agreements. In addition, if we experience a material adverse effect on our assets, liabilities, financial condition, business, operations or prospects that, taken as a whole, impacted our ability to perform our obligations under our credit agreements, this could lead to a default under our credit agreements. A default under one or more of our debt agreements, including a default by the Partnership under its credit facilities, would trigger cross-default provisions under certain of our debt agreements, which would accelerate our obligation to repay our indebtedness under those agreements. As of December 31, 2009, we were in compliance with all financial covenants under our credit agreements. If our operations in Venezuela had been excluded from our calculation of EBITDA as of December 31, 2009, we would have had a 5.9 to 1.0 EBITDA to Total Interest Expense ratio, a 3.7 to 1.0 consolidated Total Debt to EBITDA ratio and a 2.9 to 1.0 Senior Secured Debt to EBITDA ratio.

 

The Partnership Credit Agreement contains various covenants with which the Partnership must comply, including restrictions on the use of proceeds from borrowings and limitations on its ability to: incur additional debt or sell assets, make certain investments and acquisitions, grant liens and pay dividends and distributions. The Partnership must maintain various consolidated financial ratios, including a ratio of EBITDA (as defined in the Partnership Credit Agreement) to Total Interest Expense (as defined in the Partnership Credit Agreement) of not less than 2.5 to 1.0, and a ratio of Total Debt (as defined in the Partnership Credit Agreement) to EBITDA of not greater than 5.0 to 1.0. The Partnership Credit Agreement allows for the Partnership’s Total Debt to EBITDA ratio to be increased from 5.0 to 1.0 to 5.5 to 1.0 during a quarter when an acquisition closes meeting certain thresholds and for the following two quarters after the acquisition closes. Therefore, because the November 2009 Contract Operations Acquisition closed in the fourth quarter of 2009 and met the applicable thresholds, the maximum allowed ratio of Total Debt to EBITDA was increased from 5.0 to 1.0 to 5.5 to 1.0 for the period from December 31, 2009 through June 30, 2010. As of December 31, 2009, the Partnership maintained a 5.2 to 1.0 EBITDA to Total Interest Expense ratio and a 4.0 to 1.0 Total

Debt to EBITDA ratio. If the Partnership continues to experience a deterioration in the demand for its services and is unable to consummate further acquisitions from us, amend its senior secured credit facility or restructure its debt, it estimates that it could be in violation of the maximum Total Debt to EBITDA covenant ratio contained in its senior secured credit facility in 2010. A violation of the Partnership’s Total Debt to EBITDA covenant would be an event of default under the Partnership Credit Agreement which would trigger cross-default provisions under certain of our debt agreements. As of December 31, 2009, the Partnership was in compliance with all financial covenants under the Partnership Credit Agreement.

 

We have entered into interest rate swap agreements related to a portion of our variable rate debt. See Part II, Item 7A (“Quantitative and Qualitative Disclosures About Market Risk”) of this report for further discussion of our interest rate swap agreements.

 

The interest rate we pay under our Credit Agreement can be affected by changes in our credit rating. As of December 31, 2009, our credit ratings as assigned by Moody’s and Standard & Poor’s were:

 

 

Historically, we have financed capital expenditures with a combination of net cash provided by operating and financing activities. As a result of the continuing challenges in the global economy and financial markets and the decline in our stock price, our ability to access the capital markets may be restricted at a time when we would like, or need, to do so, which could have an adverse impact on our ability to maintain our fleet and to grow. If any of our lenders become unable to perform their obligations under our credit facilities, our borrowing capacity under these facilities could be reduced. Inability to borrow additional amounts under those facilities could limit our ability to fund our future growth and operations. Additionally, PDVSA has assumed control over substantially all of our assets and operations in Venezuela, as discussed further in Note 2 to the Financial Statements, which has impacted our cash provided by operations. Based on current market conditions, we expect that net cash provided by operating activities will be sufficient to finance our operating expenditures, capital expenditures and scheduled interest and debt repayments through December 31, 2010; however, to the extent it is not, we may borrow additional funds under our credit facilities or we may seek additional debt or equity financing.

 

Stock Repurchase Program.  On August 20, 2007, our board of directors authorized the repurchase of up to $200 million of our common stock through August 19, 2009. In December 2008, our board of directors increased the share repurchase program, from $200 million to $300 million, and extended the expiration date of the authorization, from August 19, 2009 to December 15, 2010. Since the program was initiated, we have repurchased 5,416,221 shares of our common stock at an aggregate cost of approximately $199.9 million. We did not repurchase any shares under this program during the year ended December 31, 2009.

 

Dividends.  We have not paid any cash dividends on our common stock since our formation, and we do not anticipate paying such dividends in the foreseeable future. Our board of directors anticipates that all cash flows generated from operations in the foreseeable future will be retained and used to repay our debt, repurchase our stock or develop and expand our business, except for a portion of the cash flow generated from operations of the Partnership which will be used to pay a distribution on its units not owned by us. Any future determinations to pay cash dividends on our common stock will be at the discretion of our board of directors and will depend on our results of operations and financial condition, credit and loan agreements in effect at that time and other factors deemed relevant by our board of directors.

 

Partnership Distributions to Unitholders.  The Partnership’s partnership agreement requires it to distribute all of its “available cash” quarterly. Under the partnership agreement, available cash is defined generally to mean, for each fiscal quarter, (1) cash on hand at the Partnership at the end of the quarter in excess of the amount of

reserves its general partner determines is necessary or appropriate to provide for the conduct of its business, to comply with applicable law, any of its debt instruments or other agreements or to provide for future distributions to its unitholders for any one or more of the upcoming four quarters, plus, (2) if the Partnership’s general partner so determines, all or a portion of the Partnership’s cash on hand on the date of determination of available cash for the quarter.

 

Under the terms of the partnership agreement, there is no guarantee that unitholders will receive quarterly distributions from the Partnership. The Partnership’s distribution policy, which may be changed at any time, is subject to certain restrictions, including (1) restrictions contained in the Partnership’s credit facilities (2) the Partnership’s general partner’s establishment of reserves to fund future operations or cash distributions to the Partnership’s unitholders, (3) restrictions contained in the Delaware Revised Uniform Limited Partnership Act and (4) the Partnership’s lack of sufficient cash to pay distributions.

 

Through our ownership of common and subordinated units and all of the equity interests in the general partner of the Partnership, we expect to receive cash distributions from the Partnership. Our rights to receive distributions of cash from the Partnership as holder of subordinated units are subordinated to the rights of the common unitholders to receive such distributions.

 

On February 12, 2010, the Partnership distributed $0.4625 per limited partner unit, or approximately $11.6 million, including distributions to the Partnership’s general partner on its incentive distribution rights. The distribution covers the period from October 1, 2009 through December 31, 2009. The record date for this distribution was February 9, 2010.

 

Contractual obligations.  The following summarizes our contractual obligations at December 31, 2009 and the effect such obligations are expected to have on our liquidity and cash flow in future periods (in thousands):