Archrock, Inc. - Annual Report: 2010 (Form 10-K)

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

 

Form 10-K

Commission file no. 001-33666

Exterran Holdings, Inc.

(Exact name of registrant as specified in its charter)

 

 

16666 Northchase Drive, Houston, Texas 77060
(Address of principal executive offices, zip code)

 

(281) 836-7000

(Registrant’s telephone number, including area code)

 

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

 

 

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

None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ

 

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

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes þ     No o

 

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

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o     No þ

 

The aggregate market value of the common stock of the registrant held by non-affiliates as of June 30, 2010 was $1,148,791,227. For purposes of this disclosure, common stock held by persons who hold more than 5% of the outstanding voting shares and common stock held by executive officers and directors of the registrant have been excluded in that such persons may be deemed to be “affiliates” as that term is defined under the rules and regulations promulgated under the Securities Act of 1933, as amended. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

 

Number of shares of the common stock of the registrant outstanding as of February 17, 2011: 63,223,749 shares.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the registrant’s definitive proxy statement for the 2011 Meeting of Stockholders, which is expected to be filed with the Securities and Exchange Commission within 120 days after December 31, 2010, are incorporated by reference into Part III of this Form 10-K.

 

 

TABLE OF CONTENTS

 

PART I

 

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

 

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; anticipated cost savings, 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 non-consolidated affiliates; 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,” “will continue” 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 at www.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 in February 2007 as a wholly owned subsidiary of Universal Compression Holdings, Inc. (“Universal”). 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 “Exterran,” “our,” “we” and “us” refer to Hanover for periods prior to the merger date and to Exterran Holdings, Inc. and its subsidiaries 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.

 

General

 

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 fabrication services primarily related to the manufacturing of critical process equipment for refinery and petrochemical facilities, the fabrication of tank farms and the fabrication of evaporators and brine heaters for desalination plants. In our Total Solutions projects, which we offer to our customers on either a contract operations basis or a sale basis, we provide the engineering, design, project management, procurement and construction services necessary to incorporate our products into complete production, processing and compression facilities. 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, 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, 2010, public unitholders held a 42% 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 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 debt and/or additional interests in the Partnership. As of December 31, 2010, the Partnership had a fleet of 3,951 compressor units comprising approximately 1,572,000 horsepower, or 44% (by available horsepower) of our and the Partnership’s combined total U.S. horsepower.

 

Industry Overview

 

Natural Gas Compression

 

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.

 

Production and Processing Equipment

 

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. 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. 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.

 

Market Conditions

 

We believe that the predominant 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. Since we expect the demand for natural gas and natural gas byproducts to

increase over the long term, we believe the demand for compression and production and processing equipment and related services will increase as well.

 

Natural gas consumption in the U.S. for the twelve months ended November 30, 2010 increased by approximately 5% over the twelve months ended November 30, 2009, is expected to increase by 0.3% in 2011, and is expected to increase by an average of 0.3% per year thereafter until 2035, according to the U.S. Energy Information Administration (“EIA”).

 

Natural gas marketed production in the U.S. for the twelve months ended November 30, 2010 increased by approximately 3% over the twelve months ended November 30, 2009. In 2009, the U.S. accounted for an estimated annual production of approximately 22 trillion cubic feet of natural gas, or 20% 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 2035, or 15% of the projected worldwide total of approximately 155 trillion cubic feet.

 

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. In addition, we see opportunities to provide compression and processing services to producers of natural gas liquids.

 

The EIA reports that natural gas consumption outside of the U.S. grew 34% from 1999 through 2009. Despite this growth in 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. Total natural gas consumption worldwide is projected to increase by an average of 1.3% per year until 2035, according to the EIA, and therefore, we believe that over the long term, demand for natural gas infrastructure in international markets will increase. We believe this anticipated increase in demand for infrastructure will be further supported by 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 anticipated construction of natural gas-fueled power plants built to meet international energy demand. Additionally, we believe fabrication of production and processing equipment will increase over time to support the infrastructure required to meet this increasing 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.

 

As energy industry capital spending declined in 2009, our fabrication business segment experienced a reduction in demand. Although we began to see an improvement in market activities in the latter part of 2010, particularly in North America, this decline in demand for our fabrication products has led to a reduction in our fabrication backlog and revenue. As industry spending decreased, lead times for major components from our suppliers decreased and, in turn, our lead times in delivering certain of our products to our customers decreased. We believe that this also resulted in a reduction in our fabrication backlog.

 

Our critical process equipment fabrication 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 given the longer lead times for the development of projects. With the signs of a global economic recovery and the increase in oil prices, we expect to see an increase in investment activities in this industry.

 

We also fabricate evaporators and brine heaters for desalination plants and tank farms primarily for use in North Africa and the Middle East. Demand for these products is driven primarily by population growth, improvements in the standard of living and investment in infrastructure. We expect continued investment in these projects, and therefore increased demand for the equipment, in the regions we serve over the next few years. However, the reductions in global economic activity led to a reduction in our fabrication backlog related to these projects during 2009 and 2010.

Operations

 

Business Segments

 

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 24 to the Consolidated Financial Statements included in Part IV, Item 15 (“Financial Statements”) of this report.

 

Compressor Fleet

 

The size and horsepower of our natural gas compressor fleet on December 31, 2010 is summarized in the following table (horsepower in thousands):

 

 

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:

 

 

Contract Operations — North America and International

 

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 natural gas fired 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, size, and utilization of the unit.

 

We also provide contract production and processing services, similar to the contract compression services described above, utilizing our fleet of oil and 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 a site-by-site basis for a specific monthly service rate that is generally reduced 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 typically 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 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, 2010, our North America contract operations segment provided contract operations services primarily using a fleet of 8,590 natural gas compression units that had an aggregate capacity of approximately 3,701,000 horsepower. For the year ended December 31, 2010, 25% of our total revenue and 38% of our total gross margin 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, 2010, our international contract operations segment provided contract operations services using a fleet of 1,019 units that had an aggregate capacity of approximately 1,200,000 horsepower and a fleet of production and processing equipment. For the year ended December 31, 2010, 19% of our total revenue and 36% of our total gross margin was generated from international contract operations.

 

Aftermarket Services

 

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, 2010, 13% of our total revenue and 6% of our total gross margin was generated from aftermarket services.

 

Fabrication

 

Compressor and Accessory Fabrication

 

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, 2010, 19% of our total revenue and 6% of our total gross margin was generated from our compressor and accessory fabrication business line.

 

As of December 31, 2010, our compressor and accessory fabrication backlog was $220.2 million, compared to $296.9 million at December 31, 2009. At December 31, 2010, all future revenue related to our compressor and accessory fabrication backlog is expected to be recognized before December 31, 2011.

 

Production and Processing Equipment Fabrication

 

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 fabrication services primarily related to the manufacturing of critical process equipment for refinery and petrochemical facilities, the fabrication of tank farms and the fabrication of evaporators and brine heaters for desalination plants. For the year ended December 31, 2010, 24% of our total revenue and 14% of our total gross margin was generated from our production and processing equipment fabrication business line.

As of December 31, 2010, our production and processing equipment fabrication backlog was $483.3 million, compared to $515.6 million at December 31, 2009. Typically, we expect our production and processing equipment backlog to be produced within a three to 36 month period. At December 31, 2010, $86.0 million of future revenue related to our production and processing equipment backlog was expected to be recognized after December 31, 2011.

 

Business Strategy

 

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

 

 

Competitive Strengths

 

We believe we have the following key competitive strengths:

 

 

 

Oil and Natural Gas Industry Cyclicality and Volatility

 

Changes in oil and natural gas exploration and production spending will normally result in changes in demand for our products and services; however, we believe our contract operations business will typically be less impacted by commodity prices than certain other energy service products and services 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.

Seasonal Fluctuations

 

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.

 

Market and Customers

 

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 approximately 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.

 

Sales and Marketing

 

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.

 

Sources and Availability of Raw Materials

 

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 fabricate 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.

 

Competition

 

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. The ability to fabricate these large custom-engineered systems near the point of end-use is often a competitive advantage.

 

International Operations

 

We operate in many geographic markets outside North America. At December 31, 2010, approximately 18% of our revenue was generated by our operations in Latin America (primarily in Argentina, Mexico and Brazil) and approximately 36% of our revenue was generated in the Eastern Hemisphere. Changes in local economic or political conditions, particularly in 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 and Canada.

 

Additional risks inherent in our international business activities are described in “Risk Factors.” For financial data relating to our geographic concentrations, see Note 24 to the Financial Statements.

 

Environmental and Other Regulations

 

Government Regulation

 

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 currently applicable 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.

 

Air Emissions

 

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.

 

On August 20, 2010, the Environmental Protection Agency (“EPA”) published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines. The rule will require us to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment, such as oxidation catalysts or non-selective catalytic reduction equipment, on a portion of our engines located at sites that are major sources of hazardous air pollutants and all our engines over a certain size regardless of location, following prescribed maintenance practices for engines (which are consistent with our existing practices), and implementing additional emissions testing and monitoring. On October 19, 2010, we submitted a legal challenge to the U.S. Court of Appeals for the D.C. Circuit and a Petition for Administrative Reconsideration to the EPA for some monitoring aspects of the rule. The legal challenge has been held in abeyance since December 3, 2010, pending the EPA’s consideration of the Petition for Administrative Reconsideration. On January 5, 2011, the EPA approved the request for reconsideration of the monitoring issues and that reconsideration process is ongoing. At this point, we cannot predict when, how or if an EPA or a court ruling would modify the final rule, and as a result we cannot currently accurately predict the cost to comply with the rule’s requirements. Compliance with the final rule is required by October 2013.

 

In addition, the Texas Commission on Environmental Quality (“TCEQ”) has finalized revisions to certain air permit programs that significantly increase the air permitting requirements for new and certain existing oil and gas production and gathering sites for 23 counties in the Barnett Shale production area. The final rule establishes new emissions standards for engines, which could impact the operation of specific categories of engines by requiring the use of alternative engines, compressor packages or the installation of aftermarket emissions control equipment. The rule will become effective for the Barnett Shale production area in April 2011, with the lower emissions standards becoming applicable between 2015 and 2030 depending on the type of engine and the permitting requirements. The cost to comply with the revised air permit programs is not expected to be material at this time. However, the TCEQ has stated it will consider expanding application of the new air permit program statewide. At this point, we cannot predict the cost to comply with such requirements if the geographic scope is expanded.

 

In June 2010, the EPA formally proposed modifications to existing regulations under the CAA that established new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The proposed rule modifications, if adopted as drafted by the EPA, may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment 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 EPA expects to finalize the proposed rules in May 2011 with an effective date targeted for July 2011.

 

These new regulations and proposals, when finalized, and any other new regulations requiring the installation of more sophisticated pollution control equipment could have a material adverse impact on our business, financial condition, results of operations and cash flows.

 

Climate Change

 

In recent years, the U.S. Congress has been considering 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, passed by the House of Representatives, would, if enacted by the full Congress, have required 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. It presently appears unlikely that

comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other initiatives are expected to be proposed that may be relevant to greenhouse gas emissions issues. 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.

 

Independent of Congress, the EPA is beginning to adopt regulations controlling greenhouse gas emissions under its existing CAA authority. For example, 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. On November 30, 2010, the EPA finalized additional portions of this inventory rule relating to petroleum and natural gas systems that require inventories for that category of facilities beginning in January 2011 and reporting of those inventories beginning in March 2012. Also, 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. Further, the EPA in June 2010 published a final rule providing for the tailored applicability of criteria that determine which stationary sources and modification projects become subject to permitting requirements for greenhouse gas emissions under two of the agency’s major air permitting programs. The EPA reported that the rulemaking was necessary because without it certain permitting requirements would apply as of January 2011 at an emissions level that would have greatly increased the number of required permits and, among other things, imposed undue costs on small sources and overwhelmed the resources of permitting authorities. In the rule, the EPA established two initial steps of phase-in to minimize those burdens, excluding certain smaller sources from greenhouse gas permitting until at least April 30, 2016. On January 2, 2011, the first step of the phase-in applied only to new projects at major sources (as defined under those CAA permitting programs) that, among other things, increase net greenhouse gas emissions by 75,000 tons per year. In July 2011, the second step of the phase-in will capture sources that have the potential to emit at least 100,000 tons per year of greenhouse gases. Several industry groups and States have challenged both the EPA’s December 15, 2009 determination that greenhouse gases present an endangerment and the EPA’s June 2010 greenhouse gas permitting rules in the D.C. Circuit Court of Appeals. However, absent a court stay or other modification, this new permitting program may affect some of our customers’ largest new or modified facilities going forward.

 

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.

 

Water Discharges

 

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.

 

Waste Management and Disposal

 

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 abrasive blasting 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 any clean-up activities. However, we cannot provide any assurance that we will not receive any such order in the future.

 

Occupational Health and Safety

 

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 organize and/or disclose 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.

 

International Operations

 

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.

Employees

 

As of December 31, 2010, we had approximately 10,100 employees. We believe that our relations with our employees are satisfactory.

 

Available Information

 

Our website address is www.exterran.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and 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 at 1-800-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:

 

 

As described in Part I (“Disclosure Regarding Forward-Looking Statements”), this report contains forward-looking statements regarding us, our business and our industry. The risk factors described below, among others, could cause our actual results to differ materially from the expectations reflected in the forward-looking statements. If any of the following risks actually occurs, our business, financial condition, operating results and cash flows could be negatively impacted.

 

Failure to timely and cost-effectively execute on larger projects could adversely affect our business.

 

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.

 

We may incur losses on fixed-price contracts, which constitute a significant portion of our fabrication business.

 

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. Any 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, financial condition, results of operations and cash flows.

 

A reduction in demand for oil or natural gas or prices for those commodities, or instability in the North America or global energy markets, could adversely affect our business.

 

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 and early 2010, 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 the years ended 2010, 2009 and 2008, we recorded long-lived asset impairments of $146.9 million, $97.0 million and $24.1 million, respectively. In the fourth quarter of 2010, we recorded a $136.0 million impairment for idle units we retired from our fleet and expect to sell. We expect it to take several years to sell these compressor units and, if we are not able to sell these units for the amount we estimated in our impairment analysis, we could be required to record an additional impairment. The impairment of our goodwill, intangible assets or other long-lived assets could have a material adverse effect on our results of operations.

 

The currently available supply of compression equipment owned by our customers and competitors could cause a further reduction in demand for our products and services and a further reduction in our pricing.

 

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 may continue to limit in the near term, our ability to significantly improve our horsepower utilization and pricing and, therefore, 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 1% from December 31, 2009 to December 31, 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.

 

The erosion of the financial condition of our customers could adversely affect our business.

 

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 canceling month-to-month contracts, 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.

 

There are many risks associated with conducting operations in international markets.

 

We operate in many countries outside the U.S., and these activities accounted for a substantial amount of our revenue for the year ended December 31, 2010. We are exposed to risks inherent in doing business in each of the countries in which we operate. Our operations are subject to various risks unique to each country that 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.

 

We could be adversely affected by violations of the U.S. Foreign Corrupt Practices Act and similar worldwide anti-bribery laws.

 

Our international operations require us to comply with a number of U.S. and international laws and regulations, including those involving anti-bribery and anti-corruption. For example, the U.S. Foreign Corrupt Practices Act (“FCPA”) and similar international laws and regulations prohibit improper payments to foreign officials for the purpose of obtaining or retaining business. The scope and enforcement of anti-corruption laws and regulations may vary.

 

We operate in many parts of the world that have experienced governmental corruption to some degree and, in certain circumstances, strict compliance with anti-bribery laws may conflict with local customs and practices. Our training and compliance program and our internal control policies and procedures may not always protect us

from reckless or negligent acts committed by our employees or agents. Violations of these laws, or allegations of such violations, could disrupt our business and result in a material adverse effect on our business and operations. We may be subject to competitive disadvantages to the extent that our competitors are able to secure business, licenses or other preferential treatment by making payments to government officials and others in positions of influence or using other methods that are prohibited by U.S. and international laws and regulations.

 

To effectively compete in some foreign jurisdictions, we utilize local agents. Although we have procedures and controls in place to monitor internal and external compliance, if we are found to be liable for FCPA or other anti-bribery law violations (either due to our own acts or our inadvertence, or due to the acts or inadvertence of others, including actions taken by our agents), we could suffer from civil and criminal penalties or other sanctions, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

We are exposed to exchange rate fluctuations in the international markets in which we operate. A decrease in the value of any of these currencies relative to the U.S. dollar could reduce profits from international operations and the value of our international net assets.

 

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 perform period-to-period comparisons of our reported results of operations. For example, other (income) expense, net for the year ended December 31, 2010 includes foreign currency gains of $5.4 million compared to a gain of $15.2 million for the year ended December 31, 2009.

 

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.

 

We have a substantial amount of debt that could limit our ability to fund future growth and operations and increase our exposure to risk during adverse economic conditions.

 

At December 31, 2010, we had approximately $1.9 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:

 

 

 

We may be vulnerable to interest rate increases due to our floating rate debt obligations.

 

As of December 31, 2010, after taking into consideration interest rate swaps, we had approximately $131.3 million of outstanding indebtedness that was effectively subject to floating interest 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. A 1% increase in the effective interest rate on our outstanding debt subject to floating interest rates would result in an annual increase in our interest expense of approximately $1.3 million.

 

Covenants in our debt agreements may impair our ability to operate our business.

 

Our senior secured credit facilities, asset-backed securitization facility and the agreements governing certain of our other indebtedness contain various covenants with which we or certain of our subsidiaries must comply, including, but not limited to, restrictions on the use of proceeds from borrowings and limitations on our ability to incur additional indebtedness, enter into transactions with affiliates, merge or consolidate, sell assets, make certain investments and acquisitions, make loans, grant liens, repurchase equity and pay dividends and distributions. For example, we must maintain various consolidated financial ratios including a ratio of EBITDA (defined in our senior secured credit agreement (the “Credit Agreement”) as Adjusted EBITDA) 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, 2010, we maintained a 4.3 to 1.0 EBITDA to Total Interest Expense ratio, a 3.9 to 1.0 consolidated Total Debt to EBITDA ratio and a 1.9 to 1.0 Senior Secured Debt to EBITDA ratio. As of December 31, 2010, we were in compliance with all financial covenants under our debt agreements. If we fail to remain in compliance with our financial covenants we would be in default under our debt agreements. In addition, if we experience a material adverse effect on our assets, liabilities, financial condition, business or operations that, taken as a whole, impact our ability to perform our obligations under our debt agreements, this could lead to a default under our debt agreements.

 

Our Credit Agreement limits our Total Debt to EBITDA ratio to not greater than 5.0 to 1.0. Due to this limitation, only $422.0 million of the combined $1,217.9 million of undrawn capacity under our senior secured credit facility and our asset-backed securitization facility was available for additional borrowings as of December 31, 2010.

 

The Partnership’s senior secured credit agreement (the “Partnership Credit Agreement”) also contains various covenants with which the Partnership must comply, including, but not limited to, restrictions on the use of proceeds from borrowings and limitations on its ability to incur additional indebtedness, enter into transactions with affiliates, merge or consolidate, sell assets, make certain investments and acquisitions, make loans, grant liens, repurchase equity 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 3.0 to 1.0 (which will decrease to 2.75 to 1.0 following the occurrence of certain events specified in the Partnership Credit Agreement) and a ratio of Total Debt (as defined in the Partnership Credit Agreement) to EBITDA of not greater than 4.75 to 1.0. The Partnership Credit Agreement allows for the Partnership’s Total Debt to EBITDA ratio to be increased from 4.75 to 1.0 to 5.25 to 1.0 during a quarter when an acquisition meeting certain thresholds is completed 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 third quarter of 2010, the maximum allowed ratio of Total Debt to EBITDA is 5.25 to 1.0 through March 31, 2011, reverting to 4.75 to 1.0 for the quarter ending June 30, 2011 and subsequent quarters. As of December 31, 2010, the Partnership maintained a 5.8 to 1.0 EBITDA to Total Interest Expense ratio and a 3.7 to 1.0 Total Debt to EBITDA ratio.

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 facility, 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 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.

 

Many of our contract operations services contracts have short initial terms, and we cannot be sure that such contracts will be renewed after the end of the initial contractual term.

 

The length of our contract operations services contracts with customers varies based on operating conditions and customer needs. 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.

 

We depend on particular suppliers and are vulnerable to product shortages and price increases.

 

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.

 

We face significant competitive pressures that may cause us to lose market share and harm our financial performance.

 

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 that may result in substantial liability. We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.

 

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 tax treatment of the Partnership depends on its status as a partnership for U.S. federal income tax purposes, as well as it not being subject to a material amount of entity-level taxation by individual states. The Partnership could lose its status as a partnership for a number of reasons, including not having enough “qualifying income.” If the Internal Revenue Service treats the Partnership as a corporation or if the Partnership becomes subject to a material amount of entity-level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to the Partnership’s unitholders and undermine the cost of capital advantage we believe the Partnership has.

 

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.

 

Despite the fact that the Partnership is a limited partnership under Delaware law, a publicly traded partnership such as the Partnership will be treated as a corporation for federal income tax purposes unless 90% or more of its gross income from its business activities are “qualifying income” under Section 7704(d) of the Internal Revenue Code. “Qualifying income” includes income and gains derived from the exploration, development, production, processing, transportation, storage and marketing of natural gas and natural gas products or other passive types of income such as interest and dividends. Although we do not believe based upon our current operations that the Partnership is treated as a corporation, the Partnership could be treated as a corporation for federal income tax purposes or otherwise subject to taxation as an entity if its gross income is not properly classified as qualifying income, there is a change in the Partnership’s business or there is a change in current law.

 

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 and the amount of distributions that we receive from the Partnership.

 

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 tax treatment of publicly traded partnerships or our investment in the Partnership could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

 

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 recently considered substantive changes to the existing U.S. federal income tax laws that would have affected certain publicly traded partnerships. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the “qualifying income” exception for us to be treated as a partnership for U.S. federal income tax purposes. 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 and the amount of distributions that we receive from the Partnership.

 

New regulations, proposed regulations and proposed modifications to existing regulations under the CAA, if implemented, could result in increased compliance costs.

 

On August 20, 2010, the EPA published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines. The rule will require us to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment, such as oxidation catalysts or non-selective catalytic reduction equipment, on a portion of our engines located at major sources of hazardous air pollutants and all our engines over a certain size regardless of location, following prescribed maintenance practices for engines (which are consistent with our existing practices), and implementing additional emissions testing and monitoring. On October 19, 2010, we submitted a legal challenge to the U.S. Court of Appeals for the D.C. Circuit and a Petition for Administrative Reconsideration to the EPA for some monitoring aspects of the rule. The legal challenge has been held in abeyance since December 3, 2010, pending the EPA’s consideration of the Petition for Administrative Reconsideration. On January 5, 2011, the EPA approved the request for reconsideration of the monitoring issues and that reconsideration process is ongoing. At this point, we cannot predict when, how or if an EPA or a court ruling would modify the final rule, and as a result we cannot currently accurately predict the cost to comply with the rule’s requirements. Compliance with the final rule is required by October 2013.

 

In addition, the TCEQ has finalized revisions to certain air permit programs that significantly increase the air permitting requirements for new and certain existing oil and gas production and gathering sites for 23 counties in the Barnett Shale production area. The final rule establishes new emissions standards for engines, which could impact the operation of specific categories of engines by requiring the use of alternative engines, compressor packages or the installation of aftermarket emissions control equipment. The rule will become effective for the Barnett Shale production area in April 2011, with the lower emissions standards becoming applicable between 2015 and 2030 depending on the type of engine and the permitting requirements. The cost to comply with the revised air permit programs is not expected to be material at this time. However, the TCEQ has stated it will consider expanding application of the new air permit program statewide. At this point, we cannot predict the cost to comply with such requirements if the geographic scope is expanded.

 

In June 2010, the EPA formally proposed modifications to existing regulations under the CAA that established new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The proposed rule modifications, if adopted as drafted by the EPA, may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment 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 EPA expects to finalize the proposed rules in May 2011 with an effective date targeted for July 2011.

 

These new regulations and proposals, when finalized, and any other new regulations requiring the installation of more sophisticated pollution 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 governmental regulations; failure to comply with these regulations may result in administrative, civil and criminal enforcement measures.

 

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. Many of these laws and regulations are complex, change frequently, are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase 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, profitability and 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, including our customers, which in turn could have a negative impact on us.

 

Climate change legislation and regulatory initiatives could result in increased compliance costs.

 

In recent years, the U.S. Congress has been considering 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, passed by the House of Representatives, would, if enacted by the full Congress, have required 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. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other initiatives are expected to be proposed that may be relevant to greenhouse gas emissions issues. 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.

 

Independent of Congress, the EPA is beginning to adopt regulations controlling greenhouse gas emissions under its existing CAA authority. For example, 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. On November 30, 2010, the EPA finalized additional portions of this inventory rule relating to petroleum and natural gas systems that require inventories for that category of facilities beginning in January 2011 and reporting of those inventories beginning in March 2012. Also, 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. Further, the EPA in June 2010 published a final rule providing for the tailored applicability of criteria that determine which stationary sources and modification projects become subject to permitting requirements for greenhouse gas emissions under two of the agency’s major air permitting programs. The EPA reported that the rulemaking was necessary because without it certain permitting requirements would apply as of January 2011 at an emissions level that would have greatly increased the number of required permits and, among other things, imposed undue costs on small sources and overwhelmed the resources of permitting authorities. In the rule, the EPA established two initial steps of phase-in to minimize those burdens, excluding certain smaller sources from greenhouse gas permitting until at least April 30, 2016. On January 2, 2011, the first step of the phase-in applied only to new projects at major sources (as defined under those CAA permitting programs) that, among other things, increase net greenhouse gas emissions by 75,000 tons per year. In July 2011, the second step of the phase-in will capture sources that have the potential to emit at least 100,000 tons per year of greenhouse gases. This new permitting program may affect some of our customers’ largest new or modified facilities going forward.

 

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 price of our common stock and the Partnership’s common units may be volatile.

 

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.

 

We may not be able to consummate additional contributions or sales of portions of our U.S. contract operations business to the Partnership.

 

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 facility and/or public or private offerings of equity or debt. If the Partnership is not able to fund future acquisitions of our U.S. contract operations business, or if we are otherwise 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.

 

Our charter and bylaws contain provisions 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.

 

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, 2010:

 

 

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.

 

 

 

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 17, 2011, the closing price of our common stock was $24.09 per share. As of February 10, 2011, there were approximately 1,100 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, 2005. The results for the period from December 31, 2005 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, 2010 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.

 

Comparison of Five Year Cumulative Total Return

 

 

The performance graph shall not be deemed incorporated by reference by any general statement incorporating by reference this Annual Report on Form 10-K into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under those Acts.

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. 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 could repurchase shares in open market purchases or in privately negotiated transactions in accordance with applicable insider trading and other securities laws and regulations. We also could implement all or part of the repurchases under a Rule 10b5-1 trading plan, so as to provide the flexibility to extend our share repurchases beyond the quarterly purchase window. During the year ended December 31, 2010, we did not repurchase any shares of our common stock under this program. Over the life of the program, we 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, 2010, 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):

 

 

NON-GAAP FINANCIAL MEASURES

 

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 operating 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 accounting principles generally accepted in the U.S. (“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 define EBITDA, as adjusted, as net income (loss) plus income (loss) from discontinued operations (net of tax), cumulative effect of accounting changes (net of tax), income taxes, interest expense (including debt extinguishment costs and gain or loss on termination of interest rate swaps), depreciation and amortization expense, impairment charges, merger and integration expenses, restructuring charges and other charges. We believe EBITDA, as adjusted, is an important measure of operating performance because it allows management, investors and others to evaluate and compare our core operating results from period to period by removing the impact of our capital structure (interest expense from our outstanding debt), asset base (depreciation and amortization), tax consequences, impairment charges, merger and integration expenses, restructuring charges and other charges. Management uses EBITDA, as adjusted, as a supplemental measure to review current period operating performance, comparability measures and performance measures for period to period comparisons. Our EBITDA, as adjusted, may not be comparable to a similarly titled measure of another company because other entities may not calculate EBITDA in the same manner.

 

EBITDA, as adjusted, is not a measure of financial performance under GAAP, and should not be considered in isolation or as an alternative to net income (loss), cash flows from operating activities and other measures determined in accordance with GAAP. Items excluded from EBITDA, as adjusted, are significant and necessary components to the operations of our business, and, therefore, EBITDA, as adjusted, should only be used as a supplemental measure of our operating performance.

 

The following table reconciles our net income (loss) to EBITDA, as adjusted (in thousands):

 

 

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements, and the notes thereto, and the other financial information appearing elsewhere in this report. The following discussion includes forward-looking statements that involve certain risks and uncertainties. See Disclosure Regarding Forward-Looking Statements and Risk Factors of this report.

 

Overview

 

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 fabrication services primarily related to the manufacturing of critical process equipment for refinery and petrochemical facilities, the fabrication of tank farms and the fabrication of evaporators and brine heaters for desalination plants. In our Total Solutions projects, which we offer to our customers on either a contract operations basis or a sale basis, we provide the engineering design, project management, procurement and construction services necessary to incorporate our products into complete production, processing and compression facilities. 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.

 

Industry Conditions and Trends

 

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, demand and 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 will typically be 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 and Production.  Natural gas consumption in the U.S. for the twelve months ended November 30, 2010 increased by approximately 5% over the twelve months ended November 30, 2009, is expected to increase by 0.3% in 2011, and is expected to increase by an average of 0.3% per year thereafter until 2035, according to the EIA. Natural gas consumption worldwide is projected to increase by 1.3% per year until 2035, according to the EIA.

 

Natural gas marketed production in the U.S. for the twelve months ended November 30, 2010 increased by approximately 3% over the twelve months ended November 30, 2009. In 2009, the U.S. accounted for an estimated annual production of approximately 22 trillion cubic feet of natural gas, or 20% 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 2035, or 15% of the projected worldwide total of approximately 155 trillion cubic feet.

Our Performance Trends and Outlook

 

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 utilize products and services from 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.

 

During 2010, we began to see an increase in overall natural gas activity in North America; however, given our focus on the production of, rather than the exploration for, natural gas, we did not experience an increase in customer activity in our contract operations and fabrication business segments in the North America market until the second half of 2010. Consequently, although our total operating horsepower in North America decreased by approximately 1% or 30,000 in the year ended December 31, 2010, our horsepower increased by approximately 21,000 in the second half of 2010. We believe the activity levels in North America will continue to increase in 2011, particularly in shale plays and areas focused on the production of natural gas liquids. We anticipate this activity will result in higher demand for our compression and production and processing equipment, which we believe should result in increasing revenues through 2011. However, we believe this increase would be impacted if there is a significant change in oil or natural gas prices. In addition, we believe that there continues to be uncertainty around natural gas supply and demand and natural gas prices that together with the current available supply of idle and underutilized compression equipment owned by our customers and competitors, that could make it challenging for us to significantly improve our North America contract operations horsepower utilization and pricing.

 

In international markets, we believe there will continue to be demand for our contract operations and Total Solutions projects, and we expect to have opportunities to grow our international business through our contract operations, aftermarket services and fabrication business segments over the long term. However, as industry capital spending declined in 2009 and 2010, 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 for the year ended December 31, 2010.

 

Our level of capital spending depends on our forecast for the demand for our products and services and the equipment we require to provide services to our customers. As we believe there will be increased activity in certain North America natural gas plays, we anticipate investing more capital in our contract operations fleet than we have in the recent past. Based on current market conditions, we expect that net cash provided by operating activities and availability under our credit facilities will be sufficient to finance our operating expenditures, capital expenditures and scheduled interest and debt repayments through December 31, 2011; however, to the extent it is not, we may seek additional debt or equity financing.

 

We have credit facilities that mature in the next few years that we expect to refinance over time and prior to their maturity date. We cannot predict the potential terms of any new or revised credit facilities; however, based on current market conditions, we expect that the interest rate under any replacement facility would be higher than in the current facilities and therefore would lead to higher interest expense in future periods. For example, on November 3, 2010, the Partnership entered into an amendment and restatement of its senior secured credit facility that resulted in an increase in the interest rates on its senior secured credit facility. See “— Liquidity and Capital Resources” for additional information about this refinancing.

 

In August 2010, the Partnership acquired from us additional contract operations customer service agreements with 43 customers and a fleet of approximately 580 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 debt and/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.

Certain Key Challenges and Uncertainties

 

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 and Pricing.  Our ability to increase our revenues in our North America contract operations business is dependent in large part on our ability to increase the utilization of our idle fleet and to add new compression units to our fleet in areas where we see key market opportunities. During 2010, we began to see an increase in overall natural gas activity in North America; however, given our focus on the production of, rather than the exploration for, natural gas, we did not experience an increase in customer activity in our contract operations and fabrication business segments in the North America market until the second half of 2010. Consequently, although our total operating horsepower in North America decreased by approximately 1% or 30,000 in the year ended December 31, 2010, our horsepower increased by approximately 21,000 in the second half of 2010. We believe the activity levels in North America will continue to increase in 2011, particularly in shale plays and areas focused on the production of natural gas liquids. We anticipate this activity will result in higher demand for our compression and production and processing equipment, which we believe should result in increasing revenues through 2011. However, we believe this increase would be impacted if there is a significant change in oil or natural gas prices. In addition, we believe that there continues to be uncertainty around natural gas supply and demand and natural gas prices that together with the current available supply of idle and underutilized compression equipment owned by our customers and competitors, could make it challenging for us to significantly improve our North America contract operations horsepower utilization and pricing.

 

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 conditions and/or performance 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.

 

Personnel, Hiring, Training and Retention.  Both in North America and internationally, we believe our ability to grow will be challenged by our ability to hire, train and retain qualified personnel. 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 Markets.  Our results of operations depend upon the level of activity in the global energy markets, 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 longer lead times for the development of international energy projects may continue to negatively impact the level of capital spending by our customers and, therefore, our business activity in the near term.

 

Summary of Results

 

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 and EBITDA, as adjusted.  We recorded a consolidated net loss attributable to Exterran stockholders of $101.8 million, $549.4 million and $947.3 million for the years ended December 31, 2010, 2009 and 2008, respectively. We recorded EBITDA, as

adjusted, of $455.1 million, $616.0 million and $699.9 million for the years ended December 31, 2010, 2009 and 2008, respectively. Net loss attributable to Exterran stockholders and EBITDA, as adjusted in the year ended December 31, 2010 was negatively impacted by reduced gross margin in our North America contract operations and our fabrication businesses caused by challenging market conditions. Net loss attributable to Exterran stockholders for the year ended December 31, 2010 was also negatively impacted by long-lived asset impairments of $146.9 million. Net loss attributable to Exterran stockholders for the years ended December 31, 2009 and 2008 was also negatively impacted by goodwill impairments of $150.8 million and $1,148.4 million, respectively. For a reconciliation of EBITDA, as adjusted, to net income, its most directly comparable financial measure, calculated and presented in accordance with GAAP, please read Part II, Item 6 (“Selected Financial Data — Non-GAAP Financial Measure”) of this report.

 

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

 

 

 

 

Operating Highlights

 

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

 

 

 

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

 

Summary of Business Segment Results

 

North America Contract Operations
(Dollars 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 3% reduction in our revenue per average operating horsepower in the year ended December 31, 2010 compared to the year ended December 31, 2009. 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 Measures in Part II, Item 6 of this report. Our operating horsepower declined by 30,000 and 588,000 during the years ended December 31, 2010 and 2009, respectively, although our operating horsepower increased by approximately 21,000 in the second half of 2010. The decrease in average operating horsepower and pricing was due to the challenging market conditions in the North America natural gas energy industry and the full year impact of the reduction of contract operation services by customers during 2009. The decrease in gross margin and gross margin percentage was also due to the decline in average revenue per horsepower and an increase in our field operating expenses.

 

International Contract Operations
(Dollars in thousands)

 

 

The increase in revenue and gross margin in the year ended December 31, 2010 compared to the year ended December 31, 2009 was primarily the result of a $60.5 million increase in revenue in Indonesia and Brazil due to the start-up of new projects and a $9.0 million increase in revenues in Brazil due to the early termination of a project. Gross margin percentage in the year ended December 31, 2010 compared to the prior year benefited from revenue with little incremental cost from the early termination of the project in Brazil. This increase was offset by lower margins in Brazil (excluding the impact of the project terminated early) and Argentina due to higher operating costs, primarily caused by inflation and increased compensation costs.

 

Aftermarket Services
(Dollars in thousands)

 

 

The increase in revenue in the year ended December 31, 2010 compared to the year ended December 31, 2009 was primarily due to a $22.8 million increase in international revenues as a result of growth in the Eastern Hemisphere and Brazil that was partially offset by a $9.5 million decrease in North America revenues in the year ended December 31, 2010. The decrease in North America revenues and the decrease in overall gross margin percentage in the year ended December 31, 2010 compared to the prior year were primarily due to changes in market conditions that have led to a more competitive environment.

Fabrication
(Dollars in thousands)

 

 

The decrease in revenue in the year ended December 31, 2010 compared to the year ended December 31, 2009 was primarily due to a $61.0 million reduction in compressor and accessory fabrication product line revenue and a $205.2 million reduction in revenue from our Belleli subsidiary that provides engineering, procurement and fabrication services primarily related to the manufacturing of critical process equipment for refinery and petrochemical facilities, the fabrication of tank farms and the fabrication of evaporators and brine heaters for desalination plants. The decrease in fabrication revenue was due to weaker market conditions in 2009 and early 2010 that led to lower North American compression and accessory fabrication orders and an overall slowdown in international project awards. Although gross margin percentage was relatively stable, gross margin in dollar terms declined as a result of the reduction in revenues.

 

Costs and Expenses
(Dollars in thousands)

 

 

The increase in SG&A expense during the year ended December 31, 2010 was primarily due to an increase in compensation costs primarily driven by the growth in our international contract operations and international aftermarket services businesses. As a percentage of revenue, SG&A expense for the year ended December 31, 2010 and 2009 was 15% and 12%, respectively. The increase in SG&A expense as a percentage of revenue was due to the reduction in revenues in our North America contract operations and our fabrication businesses without a corresponding decrease in SG&A expense during the year ended December 31, 2010 compared to the prior year.

 

The increase in depreciation and amortization expense during the year ended December 31, 2010 compared to the prior year was primarily due to property, plant and equipment additions for new international contract operations projects.

 

During December 2010, we completed an evaluation of our longer-term strategies and, as a result, determined to retire and sell approximately 1,800 idle compressor units, or approximately 600,000 horsepower, that were previously used to provide services in our North America and international contract operations businesses. As a result of our decision to sell these compressor units, we performed an impairment review and based on that review, have recorded a $136.0 million asset impairment to reduce the book value of each unit to its estimated fair value. The fair value of each unit was estimated based on the expected net sale proceeds as compared to other fleet units we have recently sold, as well as our review of other units that were recently for sale by third

parties. We expect it will take several years to sell these compressor units and, if we are not able to sell these units for the amount we estimated in our impairment analysis, we could be required to record additional impairments in future periods.

 

This decision is part of our longer-term strategy to upgrade our fleet. As part of this strategy, we also currently plan to invest more than we have in the recent past to add newly built compressor units to our fleet. We expect to focus this investment on key growth areas, including providing compression and processing services to producers of natural gas from shale plays and natural gas liquids.

 

As a result of a decline in market conditions in North America during 2010 and 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. We performed a cash flow analysis of the expected proceeds from the salvage value of 323 and 1,232 units, representing 61,400 and 264,900 horsepower, respectively, for the years ended December 31, 2010 and 2009, respectively. The net book value of these assets exceeded their fair value by $7.6 million and $91.0 million for the years ended December 31, 2010 and 2009, respectively, and this difference was recorded as a long-lived asset impairment. In addition, in the fourth quarter of 2010, 105 fleet units that were previously utilized in our international contract operations segment were damaged in a flood, resulting in a long-lived asset impairment of $3.3 million. Long-lived asset impairment for the year ended December 31, 2009 also includes facility impairments of $6.0 million. See Note 14 to the Financial Statements for further discussion of the long-lived asset impairments.

 

Restructuring charges were $14.3 million for the year ended December 31, 2009. These expenses were due to our efforts to adjust our costs to our forecasted business activity levels and included severance, retention 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.

 

We recorded a goodwill impairment charge of $150.8 million in the second quarter of 2009 related to our international contract operations segment in conjunction with the expropriation of our assets and operations in Venezuela. See Note 9 to the Financial Statements for further discussion of this charge.

 

The increase in interest expense during the year ended December 31, 2010 compared to the year ended December 31, 2009 was primarily due to an increase in the average effective interest rate on our debt, including the impact of interest rate swaps, to 6.3% for the year ended December 31, 2010 from 4.8% for the year ended December 31, 2009. The increase in our average effective interest rate is primarily due to the refinancing of portions of our outstanding debt at higher interest rates, including the 11.67% effective interest rate on our 4.25% convertible senior notes issued in June 2009 and due 2014 (the “4.25% Notes”). This increase was partially offset by a lower average debt balance during the year ended December 31, 2010 compared to the year ended December 31, 2009.

 

Equity in loss of non-consolidated affiliates for the year ended December 31, 2009 related to impairments recorded due to a loss in fair value of our investments in non-consolidated affiliates in Venezuela that was not temporary. We currently do not expect to have significant 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 investments 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 decrease in other (income) expense, net, was primarily due to a $30.9 million decrease in gains on asset sales for the year ended December 31, 2010 compared to the year ended December 31, 2009. In addition, foreign currency gain was $5.4 million for the year ended December 31, 2010 compared to a gain of $15.2 million for the year ended December 31, 2009. Our foreign currency gains and losses are primarily related to the remeasurement of our international subsidiaries’ net assets exposed to changes in foreign currency rates. The foreign currency 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 change in other (income) expense, net was also impacted by $5.1 million of importation penalties in Brazil for the year ended December 31, 2010.

 

Income Taxes
(Dollars in thousands)

 

 

The increase in our effective tax rate in the year ended December 31, 2010 compared to the year ended December 31, 2009 was impacted by the $96.6 million impairment reflected in equity in loss of non-consolidated affiliates and the $150.8 million non-deductible goodwill impairment, which together led to only an $8.4 million tax benefit during the year ended December 31, 2009. Additionally in 2009, we had a $14.5 million reduction in deferred tax assets resulting from the restructuring of certain international operations, a $7.7 million charge for unrecognized tax benefits related to uncertain tax positions in foreign jurisdictions and a $5.0 million charge for valuation allowances recorded against net operating losses of certain foreign subsidiaries. Our effective tax rate was further increased due to a $3.9 million net tax benefit recorded on the sale of loans and interest in an entity related to a project in Nigeria in the year ended December 31, 2010. These factors that increased our effective tax rate were partially offset by the impact of larger pre-tax losses in low-tax, or tax-free jurisdictions in the year ended December 31, 2010 compared to the prior year.

 

Discontinued Operations
(Dollars in thousands)

 

 

Income from discontinued operations, net of tax for the year ended December 31, 2010 includes a benefit of $41.0 million from payments received from PDVSA and its affiliates for the fixed assets for two projects. These payments relate to the recovery of the loss we recognized on the value of the equipment for these projects in the second quarter of 2009. Additionally, in January 2010, the Venezuelan government announced a devaluation of the Venezuelan bolivar. This devaluation resulted in a translation gain of approximately $12.2 million on the remeasurement of our net liability position in Venezuela. The functional currency of our Venezuela subsidiary is the U.S. dollar and we had more liabilities than assets denominated in bolivars in Venezuela at the time of the devaluation. The exchange rate used to remeasure our net liabilities changed from 2.15 bolivars per U.S. dollar at December 31, 2009 to 4.3 bolivars per U.S. dollar in January 2010.

 

As discussed in Note 2 to the Financial Statements, on June 2, 2009, PDVSA commenced taking possession of our assets and operations in a number of our locations in Venezuela. As of June 30, 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 tax benefit of $18.6 million primarily from the reversal of deferred income taxes related to our Venezuelan operations in the year ended December 31, 2009.

Noncontrolling Interest

 

As of December 31, 2010, noncontrolling interest is primarily comprised of the portion of the Partnership’s earnings that is applicable to the limited partner interest in the Partnership that we do not own. As of December 31, 2010, public unitholders held a 42% ownership interest in the Partnership.

 

Year Ended December 31, 2009 Compared to Year Ended December 31, 2008

 

Summary of Business Segment Results

 

North America Contract Operations
(Dollars 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. 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.

 

International Contract Operations
(Dollars in thousands)

 

 

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.

Aftermarket Services
(Dollars in thousands)

 

 

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.

 

Fabrication
(Dollars in thousands)

 

 

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.

 

Costs and expenses
(Dollars in thousands)

 

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 salvage value 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 this amount was recorded as a long-lived asset impairment. During 2008, management identified certain fleet units that would 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 Long-lived asset impairment expense in the consolidated statements of operations. In addition, during the year ended December 31, 2009 we recorded facility impairments of $6.0 million. See Note 14 to the Financial Statements for further discussion of the long-lived asset impairments.

 

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 Long-lived asset 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 $14.3 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 and oil-and-gas-related commodity 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 gain of $15.2 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 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 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.

 

Income Taxes
(Dollars in thousands)

 

 

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.

 

Discontinued Operations
(Dollars in thousands)

 

 

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 an $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.

 

Noncontrolling Interest

 

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.

 

Liquidity and Capital Resources

 

Our unrestricted cash balance was $44.6 million at December 31, 2010, compared to $83.7 million at December 31, 2009. Working capital decreased to $402.4 million at December 31, 2010 from $582.1 million at December 31, 2009.

 

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 decrease in cash provided by operating activities for the year ended December 31, 2010 compared to the year ended December 31, 2009 was primarily due to a reduction in gross margin from our North America contract operations and fabrication segments caused by weaker market conditions.

 

Investing Activities.  The decrease in cash used in investing activities for the year ended December 31, 2010 compared to the year ended December 31, 2009 was attributable to a decrease in capital expenditures in our

contract operations businesses and $109.4 million of net proceeds from the sale of Partnership units during the year ended December 31, 2010.

 

Financing Activities.  The increase in cash used in financing activities during the year ended December 31, 2010 compared to the year ended December 31, 2009 was primarily attributable to an increase in net repayments of long-term debt during the year ended December 31, 2010, partially offset by the net cost of the call options purchased and the warrants sold in connection with the offering of the 4.25% Notes in the 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 $225 million to $275 million in net capital expenditures during 2011, including (1) contract operations equipment additions and (2) approximately $85 million to $95 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, 2010, we had approximately $1.9 billion in outstanding debt obligations, consisting of $615.9 million outstanding under our term loan facility, $50.4 million outstanding under our revolving credit facility, $143.8 million outstanding under our 4.75% convertible notes due 2014, $281.8 million outstanding under our 4.25% Notes, $350.0 million outstanding under our 7.25% senior notes due 2018, $6.0 million outstanding under our asset-backed securitization facility, $299.0 million outstanding under the Partnership’s revolving credit facility, and $150.0 million outstanding under the Partnership’s term loan facility.

 

In August 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 senior secured credit facility, 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, 2010, 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, 2010, we had $50.4 million in outstanding borrowings under our revolving credit facility, $275.7 million in letters of credit outstanding under our revolving credit facility and $615.9 million in outstanding borrowings under our term loan.

 

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, 2010, all amounts outstanding were LIBOR loans and the applicable margin was 0.65%. The weighted average interest rate at December 31, 2010 on the outstanding balance, excluding the effect of interest rate swaps, was 0.9%.

 

The Credit Agreement contains various covenants with which we or certain of our subsidiaries must comply, including, but not limited to, restrictions on the use of proceeds from borrowings and limitations on our ability to incur additional indebtedness, enter into transactions with affiliates, merge or consolidate, sell assets, make certain investments and acquisitions, make loans, grant liens, repurchase equity and pay dividends and distributions. 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. Our wholly-owned significant domestic subsidiaries (as defined in the Credit Agreement) guarantee the debt under the Credit Agreement. We have executed a U.S. Pledge Agreement pursuant to which we and our significant subsidiaries are required to pledge their equity and the equity of certain subsidiaries. Further, we and our wholly-owned significant domestic subsidiaries have granted a lien on substantially all of our and their U.S. assets. The Partnership and Exterran ABS 2007 LLC (along with its subsidiary, “Exterran ABS,”) do not guarantee the debt under the Credit Agreement, their assets are not collateral under the Credit Agreement and the equity interests in Exterran ABS and the general partner units in the Partnership are not pledged under the Credit Agreement.

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, and was further reduced to a $700 million facility in November 2010 concurrent with the closing of the Partnership’s $550 million senior secured credit facility. The amount outstanding at any time is limited to the lowest 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 indenture). Based on these tests, the limit on the amount outstanding can be increased or decreased in future periods. As of December 31, 2010, we had $6.0 million in outstanding borrowings under the 2007 ABS Facility.

 

Interest and fees payable to the noteholders accrue on the 2007 ABS Facility at a variable rate consisting of one month LIBOR plus an applicable margin of 0.825%. The weighted average interest rate at December 31, 2010 on borrowings under the 2007 ABS Facility 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 $0.4 million of restricted cash as of December 31, 2010.

 

As of December 31, 2010, we had undrawn capacity of $523.9 million and $694.0 million under our revolving credit facility and 2007 ABS Facility, respectively. Our Credit Agreement limits our Total Debt to EBITDA ratio (as defined in the Credit Agreement) to not greater than 5.0 to 1.0. Due to this limitation, only $422.0 million of the combined $1,217.9 million of undrawn capacity under our revolving credit facility and the 2007 ABS Facility was available for additional borrowings as of December 31, 2010.

 

In November 2010, we issued $350 million aggregate principal amount of 7.25% senior notes due December 2018 (the “7.25% Notes”). The 7.25% Notes have not been registered under the Securities Act of 1933, as amended (the “Securities Act”), or any state securities laws, and unless so registered, the securities may not be offered or sold in the U.S. except pursuant to an exemption from, or in a transaction not subject to, the registration requirements of the Securities Act and applicable state securities laws. We offered and issued the 7.25% Notes only to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to persons outside the U.S. pursuant to Regulation S.

 

The 7.25% Notes are guaranteed on a senior unsecured basis by all of our existing subsidiaries that guarantee indebtedness under the Credit Agreement and certain of our future subsidiaries. The Partnership and its subsidiaries have not guaranteed the 7.25% Notes. The 7.25% Notes and the guarantees are our and the guarantors’ general unsecured senior obligations, respectively, rank equally in right of payment with all of our and the guarantors’ other senior obligations, and are effectively subordinated to all of our and the guarantors’ existing and future secured debt to the extent of the value of the collateral securing such indebtedness. In addition, the 7.25% Notes and guarantees are structurally subordinated to all existing and future indebtedness and other liabilities, including trade payables, of our non-guarantor subsidiaries.

 

Prior to December 1, 2013, we may redeem all or a part of the 7.25% Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, we may redeem up to 35% of the aggregate principal amount of the 7.25% Notes prior to December 1, 2013 with the net proceeds of a public or private equity offering at a redemption price of 107.250% of the principal amount of the 7.25% Notes, plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the 7.25% Notes issued under the indenture remains outstanding after such redemption and the redemption occurs within 120 days of the date of the closing of such equity offering. On or after December 1, 2013, we may redeem all or a part of the 7.25% Notes at redemption prices (expressed as percentages of principal amount) equal to 105.438% for the twelve-month period beginning on December 1, 2013, 103.625% for the twelve-month period beginning on December 1, 2014, 101.813% for the twelve-month period beginning on December 1, 2015 and 100.000% for the twelve-month period beginning on December 1, 2016 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date on the 7.25% Notes.

In June 2009, we issued under our shelf registration statement $355.0 million aggregate principal amount of the 4.25% Notes. 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 4.25% Notes prior to their maturity date.

 

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.