UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For fiscal year ended December 31, 2011

or

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

For the transition period from             to             .

Commission file no. 001-33666

Exterran Holdings, Inc.

(Exact name of registrant as specified in its charter)

Delaware	74-3204509
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

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:

Title of Each Class	Name of Each Exchange on Which Registered
Common Stock, $0.01 par value	New York Stock Exchange

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  ¨    No  x

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  ¨    No  x

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  x    No  ¨

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  x    No  ¨

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.  x

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):

Large accelerated filer x Accelerated filer ¨ Non-accelerated filer ¨ (Do not check if a smaller reporting company) Smaller reporting company ¨

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

The aggregate market value of the common stock of the registrant held by non-affiliates as of June 30, 2011 was $522,611,064. 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 16, 2012: 64,269,404 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive proxy statement for the 2012 Meeting of Stockholders, which is expected to be filed with the Securities and Exchange Commission within 120 days after December 31, 2011, are incorporated by reference into Part III of this Form 10-K.

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business		2
Item 1A.	Risk Factors		18
Item 1B.	Unresolved Staff Comments		30
Item 2.	Properties		31
Item 3.	Legal Proceedings		32
Item 4.	Mine Safety Disclosures		32
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		33
Item 6.	Selected Financial Data		36
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		42
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		64
Item 8.	Financial Statements and Supplementary Data		65
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		65
Item 9A.	Controls and Procedures		65
Item 9B.	Other Information		67
PART III
Item 10.	Directors, Executive Officers and Corporate Governance		67
Item 11.	Executive Compensation		67
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		67
Item 13.	Certain Relationships and Related Transactions and Director Independence		68
Item 14.	Principal Accountant Fees and Services		68
PART IV
Item 15.	Exhibits and Financial Statement Schedules		69
SIGNATURES			75

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 (the “Exchange Act”), 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 “believe,” “expect,” “intend,” “project,” “anticipate,” “estimate,” “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. Known material factors that could cause our actual results to differ from those in these forward-looking statements are described below, in Part I, Item 1A (“Risk Factors”) and Part II, Item 7(“Management’s Discussion and Analysis of Financial Condition and Results of Operations”) of this report. Important factors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things:

• conditions in the oil and natural gas industry, including a sustained decrease in the level of supply or demand for oil or natural gas or a sustained decrease in the price of oil or natural gas, which could cause a decline in the demand for our natural gas compression and oil and natural gas production and processing equipment and services;

• our reduced profit margins or the loss of market share resulting from competition or the introduction of competing technologies by other companies;

• the success of our subsidiaries, including Exterran Partners, L.P. (along with its subsidiaries, the “Partnership”);

• changes in economic or political conditions in the countries in which we do business, including civil uprisings, riots, terrorism, kidnappings, violence associated with drug cartels, legislative changes and the expropriation, confiscation or nationalization of property without fair compensation;

• changes in currency exchange rates, including the risk of currency devaluations by foreign governments, and restrictions on currency repatriation;

• the inherent risks associated with our operations, such as equipment defects, malfunctions and natural disasters;

• loss of the Partnership’s status as a partnership for federal income tax purposes;

• a decline in the Partnership’s quarterly distribution of cash to us attributable to our ownership interest in the Partnership;

• the risk that counterparties will not perform their obligations under our financial instruments;

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• the financial condition of our customers;

• our ability to timely and cost-effectively obtain components necessary to conduct our business;

• employment and workforce factors, including our ability to hire, train and retain key employees;

• our ability to implement certain business and financial objectives, such as:

• winning profitable new business;

• sales of additional United States of America (“U.S.”) contract operations contracts and equipment to the Partnership;

• timely and cost-effective execution of projects;

• enhancing our asset utilization, particularly with respect to our fleet of compressors;

• integrating acquired businesses;

• generating sufficient cash; and

• accessing the capital markets at an acceptable cost;

• liability related to the use of our products and services;

• changes in governmental safety, health, environmental and other regulations, which could require us to make significant expenditures; and

• our level of indebtedness and ability to fund our business.

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.

Item 1.  Business

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

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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 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 have an equity interest in the Partnership, a master limited partnership that provides natural gas contract operations services to customers throughout the U.S. As of December 31, 2011, public unitholders held a 65% 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, 2011, the Partnership had a fleet of 4,434 compressor units comprising approximately 1,873,000 horsepower, or 53% (by then available horsepower) of our and the Partnership’s combined total U.S. horsepower. The Partnership fleet included 399 compressor units with an aggregate horsepower of 221,000 leased from Exterran Holdings, Inc. and excluded 44 compressor units with an aggregate horsepower of 18,000 leased to Exterran Holdings, Inc. as of December 31, 2011.

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.

• Wellhead and Gathering Systems — Natural gas compression that is used to transport natural gas from the wellhead through the gathering system is considered “field compression.” Compression at the wellhead is utilized because, at some point during the life of natural gas wells, reservoir pressures typically fall below the line pressure of the natural gas gathering or pipeline system used to transport the natural gas to market. At that point, natural gas no longer naturally flows into the pipeline. Compression equipment is applied in both field and gathering systems to boost the pressure levels of

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the natural gas flowing from the well allowing it to be transported to market. Changes in pressure levels in natural gas fields require periodic changes to the size and/or type of on-site compression equipment. Additionally, compression is used to reinject natural gas into producing oil wells to maintain reservoir pressure and help lift liquids to the surface, which is known as secondary oil recovery or natural gas lift operations. Typically, these applications require low- to mid-range horsepower compression equipment located at or near the wellhead. Compression equipment is also used to increase the efficiency of a low-capacity natural gas field by providing a central compression point from which the natural gas can be produced and injected into a pipeline for transmission to facilities for further processing.

• Pipeline Transportation Systems — Natural gas compression that is used during the transportation of natural gas from the gathering systems to storage or the end user is referred to as “pipeline compression.” Natural gas transported through a pipeline loses pressure over the length of the pipeline. Compression is staged along the pipeline to increase capacity and boost pressure to overcome the friction and hydrostatic losses inherent in normal operations. These pipeline applications generally require larger horsepower compression equipment (1,500 horsepower and higher).

• Storage Facilities — Natural gas compression is used in natural gas storage projects for injection and withdrawals during the normal operational cycles of these facilities.

• Processing Applications — Compressors may also be used in combination with natural gas production and processing equipment and to process natural gas into other marketable energy sources. In addition, compression services are used for compression applications in refineries and petrochemical plants.

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 ability to efficiently meet their changing compression needs over time while limiting the underutilization of their existing compression equipment;

• access to the compression service provider’s specialized personnel and technical skills, including engineers and field service and maintenance employees, which we believe generally leads to improved production rates and/or increased throughput;

• the ability to increase their profitability by transporting or producing a higher volume of natural gas through decreased compression downtime and reduced operating, maintenance and equipment costs by allowing the compression service provider to efficiently manage their compression needs; and

• the flexibility to deploy their capital on projects more directly related to their primary business by reducing their compression equipment and maintenance capital requirements.

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.

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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 natural 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 is 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. Because 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, 2011 increased by approximately 4% over the twelve months ended November 30, 2010, is expected to increase by 2.0% in 2012, and is expected to increase by an average of 0.5% 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, 2011 increased by approximately 8% over the twelve months ended November 30, 2010. In 2010, the U.S. accounted for an estimated annual production of approximately 23 trillion cubic feet of natural gas, or 19% of the worldwide total of approximately 119 trillion cubic feet. The EIA estimates that the U.S.’s natural gas production level will be approximately 26 trillion cubic feet in 2035, or 16% of the projected worldwide total of approximately 169 trillion cubic feet.

We believe the long-term outlook for natural gas compression in the U.S. will continue to benefit from increased production from unconventional sources and from the aging of producing natural gas fields that will require more compression to continue producing the same volume of natural gas. In addition, we see opportunities to provide compression and processing services to producers of natural gas liquids. However, production of natural gas has recently exceeded consumption, leading to high natural gas storage levels and a low natural gas price environment in North America. This could decrease natural gas production, particularly in dry gas areas, which could negatively impact our business.

The EIA reports that natural gas consumption outside of the U.S. grew 41% from 2000 through 2010. 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, more infrastructure is required to utilize this

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natural gas. Total natural gas consumption worldwide is projected to increase by an average of 1.6% 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 demand for production and processing equipment will increase over time to support the anticipated increased infrastructure.

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 and in 2011, particularly in North America, this decline in demand for our fabrication products has led to a reduction in our Eastern Hemisphere fabrication backlog due to the longer lead times for the development of international energy projects. 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 contributed to the reduction in our fabrication backlog.

Our critical process equipment fabrication business has also experienced a reduction in backlog given the longer lead times for the development of projects. In addition, we 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 recent years as well.

Operations

Business Segments

Our revenues and income are derived from four business segments:

• North America Contract Operations. Our North America contract operations segment primarily provides natural gas compression and production and processing services to meet specific customer requirements utilizing Exterran-owned assets within the U.S. and Canada.

• International Contract Operations. Our international contract operations segment provides substantially the same services as our North America contract operations segment except it services locations outside the U.S. and Canada. Services provided in our international contract operations segment often include engineering, procurement and on-site construction of large natural gas compression stations and/or crude oil or natural gas production and processing facilities.

• Aftermarket Services. Our aftermarket services segment provides a full range of services to support the surface production, compression and processing needs of customers, from parts sales and normal maintenance services to full operation of a customer’s owned assets.

• Fabrication. Our fabrication segment provides (i) design, engineering, fabrication, installation and sale of natural gas compression units and accessories and equipment used in the production, treating and processing of crude oil and natural gas; and (ii) engineering, procurement and fabrication services

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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 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 22 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, 2011 is summarized in the following table:

Range of Horsepower Per Unit	Number of Units		Aggregate Horsepower (in thousands)		% of Horsepower
0 – 200		4,249		472		10	%
201 – 500		2,145		646		13	%
501 – 800		775		474		10	%
801 – 1,100		561		540		11	%
1,101 – 1,500		1,354		1,834		37	%
1,501 and over		464		926		19	%
Total		9,548		4,892		100	%

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:

• enables us to minimize our fleet operating costs and maintenance capital requirements;

• enables us to reduce inventory costs;

• facilitates low-cost compressor resizing; and

• allows us to develop improved technical proficiency in our maintenance and overhaul operations, which enables us to achieve high run-time rates while maintaining low operating costs.

As of December 31, 2011, the Partnership’s fleet included 4,434 of these compressor units comprising approximately 1,873,000 horsepower, or 53% (by then available horsepower) of our and the Partnership’s combined total U.S. horsepower. The Partnership fleet included 399 compressor units with an aggregate horsepower of 221,000 leased from Exterran Holdings, Inc. and excluded 44 compressor units with an aggregate horsepower of 18,000 leased to Exterran Holdings, Inc. as of December 31, 2011.

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 services 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.

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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 by internal natural gas fired combustion engines. 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. Most of these services are what we call Total Solutions projects, in which we provide the engineering, design, project management, procurement and construction services necessary to incorporate our products into production, processing and compression facilities.

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, 2011, our North America contract operations segment provided contract operations services primarily using a fleet of 8,485 natural gas compression units that had an aggregate capacity of approximately 3,632,000 horsepower and production and processing facilities. For the year ended December 31, 2011, 22% of our total revenue and 40% of our total gross margin was generated from North America contract operations. 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 Part II, Item 6 (“Selected Financial Data — Non-GAAP Financial Measures”) of this report.

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, 2011, our international contract operations segment provided contract

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operations services using a fleet of 1,063 natural gas compression units that had an aggregate capacity of approximately 1,260,000 horsepower and a fleet of production and processing equipment. For the year ended December 31, 2011, 17% of our total revenue and 35% 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, 2011, 15% of our total revenue and 8% 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 and compressor manufacturers in the industry. We also sell pre-packaged compressor units designed to our standard specifications. For the year ended December 31, 2011, 18% of our total revenue and 5% of our total gross margin was generated from our compressor and accessory fabrication business line.

As of December 31, 2011, our compressor and accessory fabrication backlog was $249.7 million, compared to $220.2 million at December 31, 2010. At December 31, 2011, all future revenue related to our compressor and accessory fabrication backlog is expected to be recognized before December 31, 2012.

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, condensate stabilizers, 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, which is used for processing wellhead production from onshore or shallow-water offshore platform production primarily into U.S. markets. In addition, we sell custom-engineered, built-to-specification production and processing equipment. Some of these projects are in remote areas 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 products to our customers’ specifications. 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, 2011, 28% of our total revenue and 12% of our total gross margin was generated from our production and processing equipment fabrication business line.

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As of December 31, 2011, our production and processing equipment fabrication backlog was $416.0 million, compared to $483.3 million at December 31, 2010. Typically, we expect our production and processing equipment backlog to be produced within a three to 36 month period. At December 31, 2011, $27.6 million of future revenue related to our production and processing equipment backlog was expected to be recognized after December 31, 2012.

Business Strategy

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

• Grow our North America business.  We plan to continue to invest in strategically growing our North America business. Our North America contract operations business is our largest business segment based on gross margin, representing 40% of our gross margin in 2011. We see opportunities to grow this business by continuing to put idle units back to work and adding new horsepower in key growth areas, including providing compression and processing services to producers of natural gas from shale plays and natural gas liquids. We intend to utilize the Partnership as our primary vehicle for the long-term growth of our U.S. contract operations business. Because we believe that the Partnership will have a lower cost of capital due to its partnership structure, we intend to offer the Partnership the opportunity to purchase the remainder of our U.S. contract operations business over time, but we are not obligated to do so. 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 sale and the availability to the Partnership of debt and equity capital on reasonable terms. We intend to use proceeds from the sale of our U.S. contract operations business to the Partnership from time to time to fund the growth of our business or to repay debt of Exterran Holdings, Inc.

• Focus on key international market.  International markets continue to represent a significant growth opportunity for our business, due in large part to the fact that over 70% of the world’s natural gas production resides in markets outside North America. We believe that many of these markets are underserved in the products and services we offer, and that natural gas production in these regions will grow over the long term at a pace greater than that of North America. In addition, we typically see higher returns and margins in international markets relative to North America due to more complex equipment requirements and Total Solutions applications. We expect to allocate additional resources toward key areas of our international business and rebuilding our fabrication backlog in the Eastern Hemisphere.

• Lower costs and improve profitability.  To enhance our competitive position, we embarked in 2011 on a multi-year plan to improve the profitability of our operations. Our profitability initiatives are expected to impact all of our business segments and geographies. As the largest provider of compression services in the world, we intend to use our scale to achieve cost savings in our operations. We are also focused on increasing productivity and optimizing our processes in our core lines of business. By making our systems and processes more efficient, we intend to lower our internal costs and improve our profitability.

Competitive Strengths

We believe we have the following key competitive strengths:

• Breadth and quality of product and service offerings.  We provide our customers with a broad variety of products and services, including outsourced compression, production and processing services, as well as the sale of compression and oil and natural gas production and processing equipment and installation services. For those customers that outsource their compression or production and

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processing needs, we believe our contract operations services generally allow our customers to achieve higher production rates than they would achieve with their own operations, resulting in increased revenue for our customers. In addition, outsourcing allows our customers flexibility for their evolving compression and production and processing needs while limiting their capital requirements. By offering a broad range of services that complement our core strengths, we believe that we can provide comprehensive integrated solutions to meet our customers’ needs. In our Total Solutions projects, we can provide the engineering, design, project management and procurement and construction services necessary to incorporate our products into production, processing and compression facilities. We believe the breadth and quality of our services, the depth of our customer relationships and our presence in many major oil and natural gas-producing regions place us in a position to capture additional business on a global basis.

• Focus on providing superior customer service.  We believe we operate in a relationship-driven, service-intensive industry and therefore need to provide superior customer service. We believe that our regionally-based network, local presence, experience and in-depth knowledge of customers’ operating needs and growth plans enable us to be responsive to the needs of our customers and meet their evolving demands on a timely basis. In addition, we focus on achieving a high level of mechanical reliability for the services we provide in order to maximize our customers’ production levels. Our sales efforts concentrate on demonstrating our commitment to enhancing our customers’ cash flow through superior customer service, product design, fabrication, installation and after-market support.

• Size and geographic scope.  We operate in the major onshore and offshore oil and natural gas producing regions of North America and many international markets. We believe we have sufficient fleet size, personnel, logistical capabilities, geographic scope, fabrication capabilities and range of services and product offerings to meet the needs of our customers on a timely and cost-effective basis. We believe our size, geographic scope and broad customer base provide us with improved operating expertise and business development opportunities.

• Ability to leverage the Partnership.  We believe that the Partnership provides us a lower cost of capital over time relative to our competitors that pay entity-level federal income taxes. We have completed six sales to the Partnership, including the Partnership’s initial public offering in 2006, of compressor units comprising approximately 1.8 million horsepower as well as gas processing assets. These transactions have provided us significant capital to reduce our debt and fund our capital expenditures. In addition, we have received equity interests in these transactions that we believe will allow us to participate in the Partnership’s future growth.

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:

• compression, production and processing services are necessary for natural gas to be delivered from the wellhead to end users;

• the need for compression services and equipment has grown over time due to the increased production of natural gas, the natural pressure decline of natural gas producing basins and the increased percentage of natural gas production from unconventional sources; and

• our contract operations businesses are tied primarily to natural gas and oil production and consumption, which are generally less cyclical in nature than exploration activities.

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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 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 critical process equipment for refinery and petrochemical facilities and other vessels used in production, processing and treating of crude oil and natural gas. Steel 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

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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 with 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, 2011, approximately 17% of our revenue was generated by our operations in Latin America (primarily in Argentina, Brazil and Mexico) and approximately 27% of our revenue was generated in the Eastern Hemisphere. Changes in local economic or political conditions 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 select international markets. The risks inherent in establishing new business ventures or expanding existing operations, 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 operations 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 Mexico.

Additional risks inherent in our international business activities are described in “Risk Factors.” For financial data relating to our geographic concentrations, see Note 22 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

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“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 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 natural 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 became effective for the Barnett Shale production area in April 2011, and the lower emissions standards will become applicable between 2015 and 2030 depending on the type of engine and the permitting requirements. Our cost to comply with the revised air permit programs is not expected to be material at this time. Although the TCEQ had previously stated it would consider expanding application of the new air permit program statewide, the Texas Legislature adopted legislation prohibiting such an expansion in the near term, including by preventing the TCEQ from expending funds to extend the rule’s geographic scope prior to August 31, 2013 and prior to conducting and providing to the Texas Legislature an economic impact study regarding any such expansion. At this point, we cannot predict whether or when such a geographic expansion of those rules might occur or the cost to comply with any such requirements.

On August 23, 2011, the EPA published proposed regulations focused on reducing the emissions of certain chemicals by the oil and natural gas industry, including volatile organic compounds, sulfur dioxide and certain air toxics. Because, based on our review of the proposed regulations, it appeared our business could be affected by certain portions of those proposed regulations, we submitted comments to the EPA prior to the end of the comment period on November 30, 2011. At this point, however, we cannot predict how or if the EPA will address those comments, what applicable requirements may eventually be adopted with respect to these proposed regulations or the cost to comply with such requirements.

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

Climate Change

The U.S. Congress has considered legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane, that are understood to contribute to global warming. One bill, passed by the House of Representatives, if enacted by the full Congress, would 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 continue 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. The EPA has adopted rules requiring many facilities, including petroleum and natural gas systems, to inventory and report their greenhouse gas emissions. In addition, the EPA in June 2010 published a final rule providing for the tailored applicability of air permitting requirements for greenhouse gas emissions. 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 began requiring permitting for otherwise minor sources of air emissions that have the potential to emit at least 100,000 tons per year of greenhouse gases. No later than July 2012, the EPA must complete another rulemaking to determine whether it will expand this permitting program to additional, smaller sources via a third step of phase-in. If the EPA decides to proceed with a “Phase III” expansion of this program, it could first take effect prior to July 1, 2013 and it could require permitting of sources emitting as little as 50,000 tons per year. These rules triggered reporting obligations for one site we operated in 2011, and we anticipate the same obligation in 2012. These rules will also affect some of our and our customers’ largest new or modified facilities going forward.

Although it is not currently possible to predict how any 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

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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 Safety and Health

We are subject to the requirements of OSHA and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the safety and health 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

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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, 2011, we had approximately 10,400 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 Securities and Exchange Commission (“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:

• our Code of Business Conduct;

• our Corporate Governance Principles; and

• the charters of our audit, compensation, and nominating and corporate governance committees.

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Item 1A.  Risk Factors

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.

A sustained 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. 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 sustained reduction in oil or natural gas prices or significant instability in energy markets. Even the perception of longer-term lower oil or natural gas prices by oil and natural gas exploration, development and production companies can result in their decision to cancel, reduce or postpone major expenditures or to reduce or shut in well production. Recently, natural gas prices in North America have fallen to the lowest levels seen in nearly a decade. As a result of this substantial reduction in commodity prices, certain companies have announced a reduction in their natural gas drilling and production activities, particularly in dry gas areas. If the current price levels for natural gas continue, the level of production activity and the demand for our contract operations services and oil and natural gas production and processing equipment could decrease, which could have a material adverse affect on our business, financial condition, results of operations and cash flows. A reduction in demand for our products and services could also force us to reduce our pricing substantially.

Additionally, in North America, compression services for our customers’ production from unconventional natural gas sources 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 sustained decrease in demand for oil or 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. 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 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, 2011 and 2009, we recorded goodwill impairments of $196.8 million and $150.8 million, respectively; and during the years ended December 31, 2011, 2010 and, 2009, we recorded long-lived asset impairments of $7.0 million, $146.9 million and $97.0 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. Selling these compressor units is expected to take several years 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 intangible assets or other long-lived assets could have a material adverse effect on our results of operations.

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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, 2011, we had approximately $1.8 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:

• make it more difficult for us to satisfy our contractual obligations;

• increase our vulnerability to general adverse economic and industry conditions;

• limit our ability to fund future working capital, capital expenditures, acquisitions or other corporate requirements;

• increase our vulnerability to interest rate fluctuations because the interest payments on a portion of our debt are based upon variable interest rates and a portion can adjust based upon our credit statistics;

• limit our flexibility in planning for, or reacting to, changes in our business and our industry;

• place us at a disadvantage compared to our competitors that have less debt or less restrictive covenants in such debt; and

• limit our ability to refinance our debt in the future or borrow additional funds.

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

Our senior secured credit facility 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 are also subject to financial covenants, including a ratio of Adjusted EBITDA (as defined in the credit agreement) to Total Interest Expense (as defined in the credit agreement) of not less than 2.25 to 1.0, a ratio of consolidated Total Debt (as defined in the credit agreement) to Adjusted EBITDA of not greater than 5.0 to 1.0 and a ratio of Senior Secured Debt (as defined in the credit agreement) to Adjusted EBITDA of not greater than 4.0 to 1.0. As of December 31, 2011, we maintained a 4.3 to 1.0 Adjusted EBITDA to Total Interest Expense ratio, a 4.3 to 1.0 consolidated Total Debt to Adjusted EBITDA ratio and a 1.5 to 1.0 Senior Secured Debt to Adjusted EBITDA ratio. As of December 31, 2011, 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 were to experience a material adverse effect on our assets, liabilities, financial condition, business or operations that, taken as a whole, impacts our ability to perform our obligations under our debt agreements, this could lead to a default under our debt agreements.

At December 31, 2011, we had undrawn capacity of $449.9 million under our revolving credit facility. Our senior secured credit agreement limits our Total Debt (as defined in the credit agreement) to Adjusted EBITDA ratio of not greater than 5.0 to 1.0. Due to this limitation, $190.3 million of the $449.9 million of undrawn capacity under our revolving credit facility was available for additional borrowings as of December 31, 2011.

The Partnership’s senior secured credit agreement (the “Partnership Credit Agreement”) 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

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with affiliates, merge or consolidate, sell assets, make certain investments and acquisitions, make loans, grant liens, repurchase equity and pay dividends and distributions. It also contains various covenants requiring mandatory prepayments of the term loans from the net cash proceeds of certain future asset transfers and debt issuances. 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 such an acquisition closes. The Partnership completed an acquisition from us meeting these thresholds in the second quarter of 2011; therefore, the Partnership’s Total Debt to EBITDA ratio was temporarily increased from 4.75 to 1.0 to 5.25 to 1.0 through December 31, 2011, reverting to 4.75 to 1.0 for the quarter ending March 31, 2012 and subsequent quarters. As of December 31, 2011, the Partnership maintained a 7.3 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.

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

Over the past several years, 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.

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

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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, 2011. 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:

• difficulties in managing international operations, including our ability to timely and cost effectively execute projects;

• unexpected changes in regulatory requirements, laws or policies by foreign agencies or governments;

• work stoppages;

• training and retaining qualified personnel in international markets;

• the burden of complying with multiple and potentially conflicting laws and regulations;

• tariffs and other trade barriers;

• actions by governments or national oil companies that result in the nullification or renegotiation on less than favorable terms of existing contracts, or otherwise result in the deprivation of contractual rights, and other difficulties in enforcing contractual obligations;

• governmental actions that result in restricting the movement of property or that impede our ability to import or export parts or equipment;

• foreign currency exchange rate risks, including the risk of currency devaluations by foreign governments;

• difficulty in collecting international accounts receivable;

• potentially longer receipt of payment cycles;

• changes in political and economic conditions in the countries in which we operate, including general political unrest, the nationalization of energy related assets, civil uprisings, riots, kidnappings, violence associated with drug cartels and terrorist acts;

• potentially adverse tax consequences or tax law changes;

• currency controls or restrictions on repatriation of earnings;

• expropriation, confiscation or nationalization of property without fair compensation;

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• the risk that our international customers may have reduced access to credit because of higher interest rates, reduced bank lending or a deterioration in our customers’ or their lenders’ financial condition;

• complications associated with installing, operating and repairing equipment in remote locations;

• limitations on insurance coverage;

• inflation;

• the geographic, time zone, language and cultural differences among personnel in different areas of the world; and

• difficulties in establishing new international offices and the risks inherent in establishing new relationships in foreign countries.

In addition, we may 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 severe 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

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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, 2011 includes a foreign currency loss of $17.1 million compared to a gain of $5.4 million for the year ended December 31, 2010.

To the extent we 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 depend on distributions from our subsidiaries, including the Partnership, to meet our capital needs.

To generate the funds necessary to meet our obligations and fund our business, we depend on the cash flows and distributions from our operating subsidiaries, including cash distributions from the Partnership to us attributable to our ownership interest in the Partnership. Applicable law and contractual restrictions (including restrictions in the Partnership’s debt instruments and partnership agreement) may negatively impact our ability to obtain such distributions from our subsidiaries, including the rights of the creditors of the Partnership that would often be superior to our interests in the Partnership. Furthermore, a decline in the Partnership’s revenues or increases in its expenses, principal and interest payments under existing and future debt instruments, working capital requirements or other cash needs would limit the amount of cash the Partnership has available to distribute to its equity holders, including us, which would reduce the amount of cash available for payment of our debt and to fund our business requirements, and as a result could have a material adverse effect on our business, results of operations and financial condition.

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

As of December 31, 2011, after taking into consideration interest rate swaps, we had approximately $264.0 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 $2.6 million.

Many of our North America 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. In North America, our initial contract terms typically 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 North America contract operations services contracts at comparable service rates or at all would lead to a reduction in revenues and net income and could require us to record additional asset impairments.

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Many of our international contract operations services contracts are long-term, substantial contracts and the termination of any of such contracts could have a material impact on our business.

Our international contract operations services contracts are typically longer-term contracts for more comprehensive projects than our North America contract operations services contracts. As a result, the termination of any such contract may lead to a reduction in our revenues and net income, which could 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.

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Threats of cyber attacks or terrorism could affect our business.

We may be threatened by problems such as cyber attacks, computer viruses or terrorism that may disrupt our operations and harm our operating results. Our industry requires the continued operation of sophisticated information technology systems and network infrastructure. Despite our implementation of security measures, our technology systems are vulnerable to disability or failures due to hacking, viruses, acts of war or terrorism and other causes. If our information technology systems were to fail and we were unable to recover in a timely way, we might be unable to fulfill critical business functions, which could have a material adverse effect on our business, operating results, and financial condition.

In addition, our assets may be targets of terrorist activities that could disrupt our ability to service our customers. We may be required by our regulators or by the future terrorist threat environment to make investments in security that we cannot currently predict. The implementation of security guidelines and measures and maintenance of insurance, to the extent available, addressing such activities could increase costs. These types of events could materially adversely affect our business and operating results. In addition, these types of events could require significant management attention and resources, and could adversely affect our reputation among customers and the public.

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 its 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

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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.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional delays to our exploration and production customers in drilling and completing natural gas wells, which could adversely affect demand for our contract operations services and production and processing equipment.

Hydraulic fracturing is an important and common practice that exploration and production operators use to stimulate production of hydrocarbons, particularly natural gas, from dense subsurface rock formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions but the U.S. Environmental Protection Agency, or EPA, recently asserted federal regulatory authority under the Federal Safe Drinking Water Act over hydraulic fracturing involving the use of diesel. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states have adopted and other states are considering adopting legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. In the event that new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where our natural gas exploration and production customers operate, those customers could incur potentially significant added costs to comply with such requirements and experience delays or curtailment in the pursuit of production or development activities, which could reduce demand for our contract operations services and oil and natural gas production and processing equipment, and as a result could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. More recently, the EPA announced plans to develop effluent limitations for the treatment and discharge of wastewater resulting from hydraulic

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fracturing activities by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory mechanisms, which events could delay or curtail production of natural gas by exploration and production operators, some of which are our customers, and thus reduce demand for our contract operations services and oil and natural gas production and processing equipment, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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 natural 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 became effective for the Barnett Shale production area in April 2011, and the lower emissions standards will become applicable between 2015 and 2030 depending on the type of engine and the permitting requirements. Our cost to comply with the revised air permit programs is not expected to be material at this time. Although the TCEQ had previously stated it would consider expanding application of the new air permit program statewide, the Texas Legislature adopted legislation prohibiting such an expansion in the near term, including by preventing the TCEQ from expending funds to extend the rule’s geographic scope prior to August 31, 2013 and prior to conducting and providing to the Texas Legislature an economic impact study regarding any such expansion. At this point, we cannot predict whether or when such a geographic expansion of those rules might occur or the cost to comply with any such requirements.

On August 23, 2011, the EPA published proposed regulations focused on reducing the emissions of certain chemicals by the oil and natural gas industry, including volatile organic compounds, sulfur dioxide and certain air toxics. Because, based on our review of the proposed regulations, it appeared our business could be affected by certain portions of those proposed regulations, we submitted comments to the EPA prior to the end of the comment period on November 30, 2011. At this point, however, we cannot predict how or if the EPA will address those comments, what applicable requirements may eventually be adopted with respect to these proposed regulations or the cost to comply with such requirements.

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

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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, safety and health, 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.

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

The U.S. Congress has considered legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane, that are understood to contribute to global warming. One bill, passed by the House of Representatives, if enacted by the full Congress, would 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 continue 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. The EPA has adopted rules requiring many facilities, including petroleum and natural gas systems, to inventory and report their greenhouse gas emissions. In addition, the EPA in June 2010 published a final rule providing for the tailored applicability of air permitting requirements for greenhouse gas emissions. 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 began requiring permitting for otherwise minor sources of air emissions that have the potential to emit at least 100,000 tons per year of greenhouse gases. No later than July 2012, the EPA must complete another rulemaking to determine whether it will expand this permitting program to additional, smaller sources via a third step of phase-in. If the EPA decides to proceed with a “Phase III” expansion of this program, it could first take effect prior to July 1, 2013 and it could require permitting of sources emitting as little as 50,000 tons per year. These rules triggered reporting obligations for one site we operated in 2011, and we anticipate the same obligation in 2012. These rules will also affect some of our and our customers’ largest new or modified facilities going forward.

Although it is not currently possible to predict how any 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.

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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:

• our reaching agreement with the Partnership regarding the terms of such sales, which will require the approval of the conflicts committee of the board of directors of the Partnership’s general partner, which is comprised exclusively of directors who are deemed independent from us;

• the Partnership’s ability to finance such purchases on acceptable terms, which could be impacted by general equity and debt market conditions as well as conditions in the markets specific to master limited partnerships; and

• the Partnership’s and our compliance with our respective debt agreements.

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.

Item 1B.  Unresolved Staff Comments

None.

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Item 2.  Properties

The following table describes the material facilities we owned or leased as of December 31, 2011:

Location	Status		Square Feet		Uses
Houston, Texas		Leased		243,746	Corporate office
Oklahoma City, Oklahoma		Owned		41,250	North America contract operations and aftermarket services
Yukon, Oklahoma		Owned		72,000	North America contract operations and aftermarket services
Belle Chase, Louisiana		Owned		35,000	North America contract operations and aftermarket services
Casper, Wyoming		Owned		28,390	North America contract operations and aftermarket services
Davis, Oklahoma		Owned		393,870	North America contract operations and aftermarket services
Edmonton, Alberta, Canada		Owned		53,557	North America contract operations and aftermarket services
Farmington, New Mexico		Owned		42,097	North America contract operations and aftermarket services
Houma, Louisiana		Owned		60,000	North America contract operations and aftermarket services
Kilgore, Texas		Owned		32,995	North America contract operations and aftermarket services
Midland, Texas		Owned		53,300	North America contract operations and aftermarket services
Midland, Texas		Owned		22,180	North America contract operations and aftermarket services
Pampa, Texas		Leased		24,000	North America contract operations and aftermarket services
Victoria, Texas		Owned		59,852	North America contract operations and aftermarket services
Camacari, Brazil		Owned		86,111	International contract operations and aftermarket services
Neuquen, Argentina		Leased		47,500	International contract operations and aftermarket services
Reynosa, Mexico		Owned		22,235	International contract operations and aftermarket services
Comodoro Rivadavia, Argentina		Owned		26,000	International contract operations and aftermarket services
Neuquen, Argentina		Owned		30,000	International contract operations and aftermarket services
Santa Cruz, Bolivia		Leased		22,017	International contract operations and aftermarket services
Bangkok, Thailand		Leased		23,022	Aftermarket services
Port Harcourt, Nigeria		Leased		32,808	Aftermarket services
Broussard, Louisiana		Owned		74,402	Fabrication, North America contract operations and aftermarket services
Houston, Texas		Owned		343,750	Fabrication
Houston, Texas		Owned		244,000	Fabrication
Schulenburg, Texas		Owned		22,675	Fabrication
Broken Arrow, Oklahoma		Owned		141,549	Fabrication
Aldridge, United Kingdom		Owned		44,700	Fabrication
Columbus, Texas		Owned		219,552	Fabrication
Jebel Ali Free Zone, UAE		Leased		112,378	Fabrication
Hamriyah Free Zone, UAE		Leased		212,742	Fabrication
Mantova, Italy		Owned		654,397	Fabrication
Singapore, Singapore		Leased		111,693	Fabrication

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

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Item 3.  Legal Proceedings

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 any of 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.

ITEM 4.  Mine Safety Disclosures

Not applicable.

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PART II

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

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.

	Price
	High		Low
Year ended December 31, 2010
First Quarter	$	26.46	$	19.24
Second Quarter	$	30.28	$	22.53
Third Quarter	$	29.96	$	20.00
Fourth Quarter	$	27.00	$	21.70
Year ended December 31, 2011
First Quarter	$	25.43	$	21.09
Second Quarter	$	24.31	$	19.37
Third Quarter	$	20.21	$	8.07
Fourth Quarter	$	12.61	$	8.26

On February 16, 2012, the closing price of our common stock was $12.19 per share. As of February 9, 2012, there were approximately 1,086 holders of record of our common stock.

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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, 2006. The results for the period from December 31, 2006 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, 2011 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.

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.

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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 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 distributions 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. 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.

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Item 6.   Selected Financial Data

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, 2011, 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 the Financial Statements contained in this report (in thousands, except per share data):

	Years Ended December 31,
	2011		2010		2009		2008		2007(1)
Statement of Operations Data:
Revenues	$	2,683,470	$	2,461,533	$	2,715,601	$	3,024,119	$	2,425,788
Gross margin(2)		738,097		804,461		915,582		1,025,732		754,466
Selling, general and administrative		359,382		358,255		337,620		352,899		247,983
Merger and integration expenses		—		—		—		11,384		46,201
Depreciation and amortization		365,870		401,478		352,785		330,886		232,492
Long-lived asset impairment(3)		7,012		146,903		96,988		24,109		61,945
Restructuring charges(4)		11,627		—		14,329		—		—
Goodwill impairment(5)		196,807		—		150,778		1,148,371		—
Interest expense		149,473		136,149		122,845		129,784		130,303
Debt extinguishment charges(6)		—		—		—		—		70,150
Equity in (income) loss of non-consolidated affiliates		471		609		91,154		(23,974)		(12,498)
Other (income) expense, net(7)		(5,425)		(13,763)		(53,360)		(3,118)		(19,771)
Provision for (benefit from) income taxes		(13,465)		(66,606)		51,667		37,219		1,558
Loss from continuing operations		(333,655)		(158,564)		(249,224)		(981,828)		(3,897)
Income (loss) from discontinued operations, net of tax(5)		(5,963)		45,323		(296,239)		46,752		44,773
Net income (loss) attributable to noncontrolling interest		990		(11,416)		3,944		12,273		6,307
Net income (loss) attributable to Exterran stockholders		(340,608)		(101,825)		(549,407)		(947,349)		34,569
Loss per share from continuing operations(8):
Basic	$	(5.34)	$	(2.37)	$	(4.12)	$	(15.39)	$	(0.22)
Diluted	$	(5.34)	$	(2.37)	$	(4.12)	$	(15.39)	$	(0.22)
Weighted average common and equivalent shares outstanding(8):
Basic		62,624		61,995		61,406		64,580		45,580
Diluted		62,624		61,995		61,406		64,580		45,580
Other Financial Data:
EBITDA, as adjusted(9)	$	398,734	$	448,305	$	600,858	$	710,842	$	540,087
Capital expenditures:
Contract Operations Equipment:
Growth	$	139,638	$	127,738	$	247,272	$	257,119	$	169,613
Maintenance		91,886		72,266		83,353		130,980		109,182
Other		51,267		35,986		38,276		77,637		44,003
Cash flows provided by (used in):
Operating activities	$	120,324	$	364,375	$	477,518	$	486,055	$	238,712
Investing activities		50,724		6,400		(301,000)		(582,901)		(302,268)
Financing activities		(190,618)		(408,032)		(224,004)		86,398		135,727
Balance Sheet Data:
Cash and cash equivalents	$	22,039	$	44,616	$	83,745	$	123,906	$	144,801
Working capital(10)		454,046		402,401		582,128		777,909		670,482
Property, plant and equipment, net		3,004,452		3,092,652		3,404,354		3,436,222		3,306,303
Total assets		4,360,662		4,741,536		5,292,948		6,092,627		6,863,523
Debt		1,773,039		1,897,147		2,260,936		2,512,429		2,333,924
Total Exterran stockholders’ equity		1,437,236		1,609,448		1,639,997		2,043,786		3,162,260

(1) Universal’s financial results have been included in our consolidated financial statements after the merger date on August 20, 2007.

(2) Gross margin, a non-GAAP financial measure, is defined, reconciled to net income (loss) and discussed further in Part II, Item 6 (“Selected Financial Data — Non-GAAP Financial Measures”) of this report.

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(3) For the year ended December 31, 2011: During 2011, we reviewed the idle compression assets used in our contract operations segments for units that were 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 these units to determine the fair value of the assets. The net book value of these assets exceeded the fair value by $6.6 million for the year ended December 31, 2011, and was recorded as a long-lived asset impairment. In addition, in the fourth quarter of 2011, we recorded a $0.4 million impairment of non-fleet long-lived assets.

For the year ended December 31, 2010: 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, 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. During 2010, we also 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 determined that 323 units representing 61,400 horsepower would be retired from the fleet. We performed a cash flow analysis of the expected proceeds from the disposition of these units to determine the fair value of the assets. The net book value of these assets exceeded the fair value by $7.6 million and this amount 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.

For the year ended December 31, 2009: 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 were not of the type, configuration, make or model that were 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. In addition, during the year ended December 31, 2009, we recorded $6.0 million of facility impairments.

For the year ended December 31, 2008: 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 at that time. During 2008, we also recorded a $1.0 million impairment related to the loss sustained on offshore units that were on platforms that capsized during Hurricane Ike.

We were involved in a project in the Cawthorne Channel in Nigeria (the “Cawthorne Channel Project”) to process natural gas from certain Nigerian oil and natural gas fields. 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 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.

For the year ended December 31, 2007: Following the completion of the merger with Universal, management reviewed our fleet for units that would not be of the type, configuration, make or model that management would want to continue to offer after the merger due to the cost to refurbish the equipment, the

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incremental costs of maintaining more types of equipment and the increased financial flexibility of the new company to build new units in the configuration currently in demand by our customers. As a result of this review, we recorded an impairment to our fleet assets of $61.9 million in 2007.

(4) For the year ended December 31, 2011: In November 2011, we announced a workforce cost reduction program across all of our business segments as a first step in a broader overall profit improvement initiative. These actions were the result of a review of our cost structure aimed at identifying ways to reduce our on-going operating costs and to adjust the size of our workforce to be consistent with current and expected activity levels.

For the year ended December 31, 2009: As a result of the reduced level of demand for our products and services, our management approved a plan in March 2009 to close certain facilities to consolidate our compression fabrication activities in our fabrication segment. These actions were the result of significant fabrication capacity stemming from the 2007 merger that created Exterran and the lack of consolidation of this capacity since that time, as well as the anticipated continuation of current weaker global economic and energy industry conditions. The consolidation of those compression fabrication activities was completed in September 2009. In August 2009, we announced our plan to consolidate certain fabrication operations in Houston, including the closure of two facilities in Texas. However, due to a subsequent improvement in bookings for certain of our production and processing equipment products, we ultimately decided to close only one of the fabrication facilities in Texas. In addition, we implemented cost reduction programs during 2009 primarily related to workforce reductions across all of our segments.

(5) For the year ended December 31, 2011: As a result of the level of decline in our stock price and corresponding market capitalization in the third quarter of 2011, we performed a goodwill impairment test of our aftermarket services and fabrication reporting units’ goodwill as of September 30, 2011. We determined the fair value of these reporting units using the expected present value of future cash flows. This decline in our market capitalization led us to increase the estimate of the market’s implied weighted average cost of capital and reduce the present value of the forecasted cash flows. The test indicated that our aftermarket services and fabrication reporting units’ goodwill was impaired and therefore we recorded a full impairment of the goodwill associated with these reporting units in the third quarter of 2011.

For the year ended December 31, 2009: 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. 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, which is reflected in Income (loss) from discontinued operations. In addition, 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. The $32.6 million of goodwill related to our Venezuela contract operations and aftermarket services businesses was also written off in the second quarter of 2009 as part of our loss from discontinued operations. The decrease in value of our international contract operations reporting unit was primarily caused by the loss of our operations in Venezuela.

For the year ended December 31, 2008: In 2008, there were severe disruptions in the credit and capital markets and reductions in global economic activity, which had significant adverse impacts on stock markets and oil-and-gas-related commodity prices, both of which we believe contributed to a significant decline in our company’s 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 a $1,148.4 million impairment of all of the goodwill in our North America contract operations reporting unit.

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(6) In the third quarter of 2007, we refinanced a significant portion of Universal’s and Hanover’s debt that existed before the merger. We recorded $70.2 million of debt extinguishment charges related to this refinancing. The charges related to a call premium and tender fees paid to retire various Hanover notes that were part of the debt refinancing and a charge of $16.4 million related to the write-off of deferred financing costs in conjunction with the refinancing.

(7) During the year ended December 31, 2009, we recorded a pre-tax gain of approximately $20.8 million on the sale of our investment in the subsidiary that owned the barge mounted processing plant and certain other related assets used on the Cawthorne Channel Project and a foreign currency gain of $15.2 million. 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.

(8) As a result of the merger between Hanover and Universal, each outstanding share of common stock of Universal was converted into one share of Exterran common stock and each outstanding share of Hanover common stock was converted into 0.325 shares of Exterran common stock.

(9) EBITDA, as adjusted, a non-GAAP financial measure, is defined, reconciled to net income (loss) and discussed further in Part II, Item 6 (“Selected Financial Data — Non-GAAP Financial Measures”) of this report.

(10) Working capital is defined as current assets minus current liabilities.

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.

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

	Years Ended December 31,
	2011		2010		2009		2008		2007
Net income (loss)	$	(339,618)	$	(113,241)	$	(545,463)	$	(935,076)	$	40,876
Selling, general and administrative		359,382		358,255		337,620		352,899		247,983
Merger and integration expenses		—		—		—		11,384		46,201
Depreciation and amortization		365,870		401,478		352,785		330,886		232,492
Long-lived asset impairment		7,012		146,903		96,988		24,109		61,945
Restructuring charges		11,627		—		14,329		—		—
Goodwill impairment		196,807		—		150,778		1,148,371		—
Interest expense		149,473		136,149		122,845		129,784		130,303
Debt extinguishment charges		—		—		—		—		70,150
Equity in (income) loss of non-consolidated affiliates		471		609		91,154		(23,974)		(12,498)
Other (income) expense, net		(5,425)		(13,763)		(53,360)		(3,118)		(19,771)
Provision for (benefit from) income taxes		(13,465)		(66,606)		51,667		37,219		1,558
(Income) loss from discontinued operations, net of tax		5,963		(45,323)		296,239		(46,752)		(44,773)
Gross margin	$	738,097	$	804,461	$	915,582	$	1,025,732	$	754,466

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, non-cash gains or losses from foreign currency exchange rate changes recorded on intercompany obligations, 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), our subsidiaries’ capital structure (non-cash gains or losses from foreign currency exchange rate changes on intercompany obligations), 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.

In the third quarter of 2011, we revised our definition of EBITDA, as adjusted, to add back non-cash gains or losses from foreign currency exchange rate changes recorded on intercompany obligations. This adjustment was made because management uses the resulting EBITDA, as adjusted, as a supplemental measure to review current period operating performance. In addition, this adjustment is included in the Adjusted EBITDA definition used in various financial covenant calculations under our senior secured credit facility. We have also made this change to prior periods included herein for comparative purposes.

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.

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

	Years Ended December 31,
	2011		2010		2009		2008		2007
Net income (loss)	$	(339,618)	$	(113,241)	$	(545,463)	$	(935,076)	$	40,876
(Income) loss from discontinued operations, net of tax		5,963		(45,323)		296,239		(46,752)		(44,773)
Merger and integration expenses		—		—		—		11,384		46,201
Depreciation and amortization		365,870		401,478		352,785		330,886		232,492
Long-lived asset impairment		7,012		146,903		96,988		24,109		61,945
Restructuring charges		11,627		—		14,329		—		—
Investment in non-consolidated affiliates impairment		471		609		96,593		—		6,743
Goodwill impairment		196,807		—		150,778		1,148,371		—
Interest expense		149,473		136,149		122,845		129,784		130,303
Debt extinguishment charges		—		—		—		—		70,150
(Gain) loss on currency exchange rate remeasurement of intercompany balances		14,594		(6,801)		(15,097)		10,917		(5,408)
Gain on sale of our investment in the subsidiary that owns the barge mounted processing plant and other related assets used on the Cawthorne Channel Project		—		(4,863)		(20,806)		—		—
Provision for (benefit from) income taxes		(13,465)		(66,606)		51,667		37,219		1,558
EBITDA, as adjusted	$	398,734	$	448,305	$	600,858	$	710,842	$	540,087

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

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 in 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 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 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, 2011 increased by approximately 4% over the twelve months ended November 30, 2010. The EIA estimates that natural gas consumption in the U.S. will increase by 2.0% in 2012 and will increase by an average of 0.5% per year thereafter until 2035. Natural gas consumption worldwide is projected to increase by 1.6% per year until 2035, according to the EIA.

Natural gas marketed production in the U.S. for the twelve months ended November 30, 2011 increased by approximately 8% over the twelve months ended November 30, 2010. In 2010, the U.S. accounted for an estimated annual production of approximately 23 trillion cubic feet of natural gas, or 19% of the worldwide total of approximately 119 trillion cubic feet. The EIA estimates that the U.S.’s natural gas production level will be approximately 26 trillion cubic feet in 2035, or 16% of the projected worldwide total of approximately 169 trillion cubic feet.

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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, our customers’ decisions regarding whether to utilize our products and services rather than utilize products and services from our competitors and their decisions regarding whether to own and operate the equipment themselves. 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 2011, we saw an increase in drilling activity and an increase in order activity and bookings in our fabrication business segment in the North America market, particularly in shale plays and areas focused on the production of oil and natural gas liquids. This activity led to higher demand for our compression and production and processing equipment, which resulted in higher fabrication revenues in 2011 compared to 2010. Our North America contract operations business has also benefited from the increase in activity in shale plays and areas focused on the production of oil and natural gas liquids. The new development activity has increased the amount of compression horsepower in the industry and in our business; however, these increases have been significantly offset by horsepower declines in more mature and predominantly conventional and dry gas markets. We also believe that the low natural gas price environment and the recent investment of capital in new equipment by our competitors and other third parties could create uncertainty in our business outlook.

In international markets, we believe there will continue to be demand for our contract operations and fabricated 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, in 2011, we saw decreases in our international backlog in our fabrication business segment due to the longer lead times for the development of international energy projects, which could negatively impact our revenue in 2012.

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 in 2012 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, 2012; however, to the extent it is not, we may seek additional debt or equity financing.

In November 2011, we announced a workforce cost reduction program across all of our business segments as a first step in a broader overall profit improvement initiative. These actions are the result of a review of our cost structure aimed at identifying ways to reduce our on-going operating costs and to adjust the size of our workforce to be consistent with current and expected activity levels. A significant portion of the workforce cost reduction program was completed in the fourth quarter of 2011, with the remainder expected to be completed in 2012. Our plan includes reducing our headcount associated with cost of sales and SG&A which we estimate will equate to approximately $20 million to $25 million in annual savings.

During the year ended December 31, 2011, we incurred $11.6 million of restructuring charges that were related to consulting services and termination benefits. These charges are reflected as Restructuring charges in our consolidated statements of operations. We currently estimate that we will incur additional charges with respect to the workforce cost reduction program of approximately $3.1 million.

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

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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 international markets 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 Market and Natural Gas Pricing.  During 2011, we saw an increase in drilling activity and an increase in order activity and bookings in our fabrication business segment in the North America market, particularly in shale plays and areas focused on the production of oil and natural gas liquids. This activity led to higher demand for our compression and production and processing equipment, which resulted in higher fabrication revenues in 2011 compared to 2010. Our North America contract operations business has also benefited from the increase in activity in shale plays and areas focused on the production of oil and natural gas liquids. The new development activity has increased the amount of compression horsepower in the industry and our business; however, these increases were significantly offset by horsepower declines in more mature and predominantly conventional and dry gas markets. Production of natural gas has recently exceeded consumption, leading to high natural gas storage levels and a low natural gas price environment in North America. This could decrease natural gas production, particularly in dry gas areas, and as a result the demand for our natural gas compression services and oil and natural gas production and processing equipment could be adversely affected. In addition, the recent investment of capital in new equipment by our competitors and other third parties could create uncertainty in our business outlook.

Execution on Larger Contract Operations and Fabrication Projects.  Over the past several years, 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. 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 or 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 reflected in discontinued operations for all periods presented.

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Net income (loss) attributable to Exterran stockholders and EBITDA, as adjusted. We recorded a consolidated net loss attributable to Exterran stockholders of $340.6 million, $101.8 million and $549.4 million for the years ended December 31, 2011, 2010 and 2009, respectively. We recorded EBITDA, as adjusted, of $398.7 million, $448.3 million and $600.9 million for the years ended December 31, 2011, 2010 and 2009, respectively. Net loss attributable to Exterran stockholders for the year ended December 31, 2011 was negatively impacted by goodwill impairments of $196.8 million. Net loss attributable to Exterran stockholders for the year ended December 31, 2010 was negatively impacted by long-lived asset impairments of $146.9 million. Net loss attributable to Exterran stockholders for the year ended December 31, 2009 was negatively impacted by $150.8 million of goodwill impairments, long-lived asset impairments of $97.0 million and a $296.2 million loss from discontinued operations. EBITDA, as adjusted, for the year ended December 31, 2009 benefited from higher gross margin from operations caused by stronger market conditions than in the years ended December 31, 2011 and 2010. EBITDA, as adjusted, is a non-GAAP financial measure. For a reconciliation of EBITDA, as adjusted, to net income (loss), 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 Measures”) 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):

	Years Ended December 31,
	2011			2010			2009
Revenue:
North America Contract Operations	$	603,529		$	608,065		$	695,315
International Contract Operations		445,059			465,144			391,995
Aftermarket Services		409,423			322,097			308,873
Fabrication		1,225,459			1,066,227			1,319,418
	$	2,683,470		$	2,461,533		$	2,715,601
Gross Margin(1):
North America Contract Operations	$	293,460		$	307,379		$	396,601
International Contract Operations		260,654			289,787			242,742
Aftermarket Services		60,761			45,790			62,987
Fabrication		123,222			161,505			213,252
	$	738,097		$	804,461		$	915,582
Gross margin percentage(2):
North America Contract Operations		49	%		51	%		57	%
International Contract Operations		59	%		62	%		62	%
Aftermarket Services		15	%		14	%		20	%
Fabrication		10	%		15	%		16	%

(1) Defined as revenue less cost of sales, excluding depreciation and amortization expense. 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 of this report.

(2) Defined as gross margin divided by revenue.

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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):

	Years Ended December 31,
	2011			2010			2009
Total Available Horsepower (at period end):
North America		3,632			3,701			4,321
International		1,260			1,200			1,234
Total		4,892			4,901			5,555
Total Operating Horsepower (at period end):
North America		2,880			2,837			2,867
International		960			981			1,032
Total		3,840			3,818			3,899
Total Operating Horsepower (average during the year):
North America		2,836			2,832			3,143
International		978			1,024			1,033
Total		3,814			3,856			4,176
Horsepower Utilization (at period end):
North America		79	%		77	%		66	%
International		76	%		82	%		84	%
Total		78	%		78	%		70	%

	December 31,
	2011		2010		2009
Compressor and Accessory Fabrication Backlog	$	249.7	$	220.2	$	296.9
Production and Processing Equipment Fabrication Backlog		416.0		483.3		515.6
Fabrication Backlog	$	665.7	$	703.5	$	812.5

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

Summary of Business Segment Results

North America Contract Operations

(Dollars in thousands)

	Years Ended December 31,						Increase (Decrease)
	2011			2010
Revenue	$	603,529		$	608,065			(1	)%
Cost of sales (excluding depreciation and amortization expense)		310,069			300,686			3	%
Gross margin	$	293,460		$	307,379			(5	)%
Gross margin percentage		49	%		51	%		(2	)%

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The decrease in revenue was primarily attributable to a $5.9 million reduction of revenue in our contract water treatment business in the year ended December 31, 2011 compared to the year ended December 31, 2010. The decrease in revenue was partially offset by an increase in revenue from two gas processing plants that began operations during 2011. Average operating horsepower remained consistent during the years ended December 31, 2011 and 2010. The decrease in gross margin (defined as revenue less cost of sales, excluding depreciation and amortization expense) and gross margin percentage in the year ended December 31, 2011 compared to the year ended December 31, 2010 was primarily due to an increase in lube oil expense, costs to deploy idle fleet assets on customer contracts and fuel expense. 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 of this report.

International Contract Operations

(Dollars in thousands)

	Years Ended December 31,						Increase (Decrease)
	2011			2010
Revenue	$	445,059		$	465,144			(4	)%
Cost of sales (excluding depreciation and amortization expense)		184,405			175,357			5	%
Gross margin	$	260,654		$	289,787			(10	)%
Gross margin percentage		59	%		62	%		(3	)%

The decrease in revenue, gross margin and gross margin percentage in the year ended December 31, 2011 compared to the year ended December 31, 2010 was primarily due to the recognition of $19.2 million of revenue with little incremental cost from the early termination of a project in Brazil recorded in the year ended December 31, 2010. Gross margin and gross margin percentage in the year ended December 31, 2011 were also impacted by higher operating costs in Argentina and Brazil caused primarily by inflation.

Aftermarket Services

(Dollars in thousands)

	Years Ended December 31,						Increase (Decrease)
	2011			2010
Revenue	$	409,423		$	322,097			27	%
Cost of sales (excluding depreciation and amortization expense)		348,662			276,307			26	%
Gross margin	$	60,761		$	45,790			33	%
Gross margin percentage		15	%		14	%		1	%

The increase in revenue in the year ended December 31, 2011 compared to the year ended December 31, 2010 was primarily due to increases in North America and Eastern Hemisphere revenue of $45.7 million and $36.9 million, respectively. Revenue and gross margin in the Eastern Hemisphere for the year ended December 31, 2011 included $3.9 million from the renegotiation of the rates, retroactive to April 2010, on an operations and maintenance contract in Gabon.

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Fabrication

(Dollars in thousands)

	Years Ended December 31,						Increase (Decrease)
	2011			2010
Revenue	$	1,225,459		$	1,066,227			15	%
Cost of sales (excluding depreciation and amortization expense)		1,102,237			904,722			22	%
Gross margin	$	123,222		$	161,505			(24	)%
Gross margin percentage		10	%		15	%		(5	)%

The increase in revenue for the year ended December 31, 2011 compared to the year ended December 31, 2010 was primarily due to $331.8 million of higher revenue in North America caused by improved market conditions. This increase was partially offset by a $189.6 million reduction of revenue in the Eastern Hemisphere. The decrease in gross margin and gross margin percentage was primarily due to reduced margins from our Belleli subsidiary which 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, lower margins in 2011 on two projects in the Eastern Hemisphere and increased revenue from compression projects in North America, which typically have lower margins than the margins on our international fabrication projects.

Costs and Expenses

(Dollars in thousands)

	Years Ended December 31,						Increase (Decrease)
	2011			2010
Selling, general and administrative	$	359,382		$	358,255			0	%
Depreciation and amortization		365,870			401,478			(9	)%
Long-lived asset impairment		7,012			146,903			(95	)%
Restructuring charges		11,627			—			n/a
Goodwill impairment		196,807			—			n/a
Interest expense		149,473			136,149			10	%
Other (income) expense, net		(5,425	)		(13,763	)		(61	)%

The increase in SG&A expense during the year ended December 31, 2011 was primarily due to a $13.8 million increase in compensation and benefit costs, partially offset by a $12.9 million reduction in state and local taxes (primarily in North America and Brazil). SG&A expense as a percentage of revenue was 13% and 15% for the years ended December 31, 2011 and 2010, respectively.

Depreciation and amortization decreased by $35.6 million, primarily due to the impact of the $136.0 million long-lived asset impairment recorded in the fourth quarter of 2010, which decreased depreciation and amortization expense by approximately $18.6 million in the year ended December 31, 2011, and $15.7 million of reduced depreciation and amortization on international contract operations projects including a project in Brazil that was terminated early in the second quarter of 2010.

During 2011, we reviewed the idle compression assets used in our contract operations segments for units that were 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 these units to determine the fair value of the assets. The net book value of these assets exceeded the fair value by $6.6 million, for the year ended December 31, 2011, and this difference was recorded as a long-lived asset impairment. In addition, in the fourth quarter of 2011, we recorded a $0.4 million impairment of non-fleet long-lived assets.

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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, 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. Selling these compressor units is expected to take several years 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.

As a result of a decline in market conditions during 2010, 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 units, representing approximately 61,400 horsepower for the year ended December 31, 2010. The net book value of these assets exceeded their fair value by $7.6 million for the year ended December 31, 2010 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. See Note 13 to the Financial Statements for further discussion of the long-lived asset impairments.

In November 2011, we announced a workforce cost reduction program across all of our business segments as a first step in a broader overall profit improvement initiative. These actions were the result of a review of our cost structure aimed at identifying ways to reduce our on-going operating costs and to adjust the size of our workforce to be consistent with current and expected activity levels. A significant portion of the workforce cost reduction program was completed in 2011, with the remainder expected to be completed in 2012. During the year ended December 31, 2011, we incurred $11.6 million of restructuring charges that were related to consulting services and termination benefits. See Note 14 to the Financial Statements for further discussion of these charges.

As a result of the level of decline in our stock price and corresponding market capitalization in the third quarter of 2011, we performed a goodwill impairment test of our aftermarket services and fabrication reporting units’ goodwill as of September 30, 2011. This decline in our market capitalization led us to increase the estimate of the market’s implied weighted average cost of capital and reduce the present value of the forecasted cash flows. The test indicated that our aftermarket services and fabrication reporting units’ goodwill was impaired and therefore we recorded a full impairment of the goodwill associated with these reporting units in the third quarter of 2011. See Note 8 to the Financial Statements for further discussion of the goodwill impairments.

The increase in interest expense for the year ended December 31, 2011 compared to the year ended December 31, 2010 was primarily due to the refinancing of portions of our outstanding debt at higher interest rates, including our 7.25% senior notes due December 2018, which we issued in November 2010. In addition, we expensed $1.6 million of unamortized deferred financing costs due to the refinancing of our senior secured credit facility and $1.4 million of unamortized deferred financing costs due to the termination of our asset-backed securitization facility in the year ended December 31, 2011. The increase in interest expense was partially offset by a lower average debt balance during the year ended December 31, 2011 compared to the year ended December 31, 2010.

The change in other (income) expense, net was primarily due to a foreign currency loss of $17.1 million for the year ended December 31, 2011 compared to a gain of $5.4 million for the year ended December 31, 2010. 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. For the year ended December 31, 2011, foreign currency loss included $12.6 million in translation losses compared to $4.6 million in translation gains in the year ended December 31, 2010, related to the re-measurement of our Brazil subsidiary’s U.S. dollar denominated inter-

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company debt. Other (income) expense, net was $14.5 million higher for the year ended December 31, 2011 compared to the prior year from non-income tax based tax receivables in Brazil that we determined were realizable. The change in other (income) expense, net was also impacted by $0.7 million and $5.1 million of importation penalties in Brazil for the years ended December 31, 2011 and 2010, respectively.

Income Taxes

(Dollars in thousands)

	Years Ended December 31,				Increase (Decrease)
	2011		2010
Benefit from income taxes	$	(13,465)	$	(66,606)		(80	)%
Effective tax rate		3.9%		29.6%		(25.7	)%

The decrease in our effective tax rate for the year ended December 31, 2011 compared to the year ended December 31, 2010 was primarily due to a $48.6 million valuation allowance recorded against the deferred tax asset for Brazil net operating loss carryforwards. Although the net operating losses have an unlimited carryforward period, cumulative losses in recent years and losses expected in the near term result in it no longer being more likely than not that we will realize the deferred tax asset in the foreseeable future. Due to annual limitations on the utilization of net operating loss carryforwards, we would need to generate more than $400 million of taxable income in Brazil to fully realize the deferred tax asset.

A $196.8 million goodwill impairment charge, of which only $42.6 million is deductible for income tax purposes, further decreased our effective tax rate for the year ended December 31, 2011. The decrease was also impacted by 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.

Discontinued Operations

(Dollars in thousands)

	Years Ended December 31,				Increase (Decrease)
	2011		2010
Income (loss) from discontinued operations, net of tax	$	(5,963)	$	45,323		(113	)%

Income (loss) from discontinued operations, net of tax for the years ended December 31, 2011 and 2010 related to our operations in Venezuela that were expropriated in June 2009, including the costs associated with our pending arbitration proceeding. As discussed in Note 2 to the Financial Statements, in June 2009, PDVSA commenced taking possession of our assets and operations in a number of our locations in Venezuela and, by the end of the second quarter of 2009, PDVSA had assumed control over substantially all of our assets and operations in Venezuela. Income (loss) from discontinued operations, net of tax, for the year ended December 31, 2010 includes a benefit of $41.0 million of payments received from PDVSA and its affiliates as consideration for the fixed assets of two projects. 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 and is reflected in Income (loss) from discontinued operations, net of tax, for the year ended December 31, 2010. 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.

Noncontrolling Interest

As of December 31, 2011, noncontrolling interest is primarily comprised of the portion of the Partnership’s earnings that is applicable to the limited partner interest in the Partnership owned by the public. As of December 31, 2011, public unitholders held a 65% ownership interest in the Partnership.

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

Summary of Business Segment Results

North America Contract Operations

(Dollars in thousands)

	Years Ended December 31,						Increase (Decrease)
	2010			2009
Revenue	$	608,065		$	695,315			(13	)%
Cost of sales (excluding depreciation and amortization expense)		300,686			298,714			1	%
Gross margin	$	307,379		$	396,601			(22	)%
Gross margin percentage		51	%		57	%		(6	)%

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 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)

	Years Ended December 31,						Increase (Decrease)
	2010			2009
Revenue	$	465,144		$	391,995			19	%
Cost of sales (excluding depreciation and amortization expense)		175,357			149,253			17	%
Gross margin	$	289,787		$	242,742			19	%
Gross margin percentage		62	%		62	%		0	%

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)

	Years Ended December 31,						Increase (Decrease)
	2010			2009
Revenue	$	322,097		$	308,873			4	%
Cost of sales (excluding depreciation and amortization expense)		276,307			245,886			12	%
Gross margin	$	45,790		$	62,987			(27	)%
Gross margin percentage		14	%		20	%		(6	)%

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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 led to a more competitive environment.

Fabrication

(Dollars in thousands)

	Years Ended December 31,						Increase (Decrease)
	2010			2009
Revenue	$	1,066,227		$	1,319,418			(19	)%
Cost of sales (excluding depreciation and amortization expense)		904,722			1,106,166			(18	)%
Gross margin	$	161,505		$	213,252			(24	)%
Gross margin percentage		15	%		16	%		(1	)%

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)

	Years Ended December 31,						Increase (Decrease)
	2010			2009
Selling, general and administrative	$	358,255		$	337,620			6	%
Depreciation and amortization		401,478			352,785			14	%
Long-lived asset impairment		146,903			96,988			51	%
Restructuring charges		—			14,329			(100	)%
Goodwill impairment		—			150,778			(100	)%
Interest expense		136,149			122,845			11	%
Equity in (income) loss of non-consolidated affiliates		609			91,154			(99	)%
Other (income) expense, net		(13,763	)		(53,360	)		(74	)%

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.

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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, 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. Selling these compressor units is expected to take several years 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 was part of our longer-term strategy to upgrade our fleet.

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 13 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 14 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 8 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 was 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 reserve and will continue to reserve the right to seek full compensation for any and all expropriated assets and investments under all applicable legal regimes, including investment treaties and customary international law, as well as to seek resolution through direct discussions with Venezuela and/or PDVSA, 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 7 to the Financial Statements for further discussion of our investments in non-consolidated affiliates.

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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)

	Years Ended December 31,						Increase (Decrease)
	2010			2009
Provision for (benefit from) income taxes	$	(66,606	)	$	51,667			(229	)%
Effective tax rate		29.6	%		(26.2	)%		55.8	%

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)

	Years Ended December 31,					Increase (Decrease)
	2010		2009
Income (loss) from discontinued operations, net of tax	$	45,323	$	(296,239	)		115	%

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 related 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.

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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.

Liquidity and Capital Resources

Our unrestricted cash balance was $22.0 million at December 31, 2011, compared to $44.6 million at December 31, 2010. Working capital increased to $454.0 million at December 31, 2011 from $402.4 million at December 31, 2010. The increase in working capital was primarily caused by increases in accounts receivable, reductions in deferred revenue and billings on uncompleted contracts in excess of costs and estimated earnings, partially offset by a reduction in inventory. The decrease in deferred revenue and billings on uncompleted contracts in excess of costs and estimated earnings was primarily due to the completion of projects and a reduction in the volume of projects in process in the Eastern Hemisphere at December 31, 2011 compared to the prior year end.

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):

	Years Ended December 31,
	2011			2010
Net cash provided by (used in) continuing operations:
Operating activities	$	118,988		$	368,255
Investing activities		50,724			(83,109	)
Financing activities		(190,618	)		(408,032	)
Effect of exchange rate changes on cash and cash equivalents		(3,007	)		(1,872	)
Discontinued operations		1,336			85,629
Net change in cash and cash equivalents	$	(22,577	)	$	(39,129	)

Operating Activities.  The decrease in cash provided by operating activities for the year ended December 31, 2011 compared to the year ended December 31, 2010 was primarily due to an increase in cash used for working capital during the year ended December 31, 2011 compared to the year ended December 31, 2010 and a reduction in gross margin from operations in the year ended December 31, 2011.

Investing Activities.  The increase in cash provided by investing activities for the year ended December 31, 2011 compared to the year ended December 31, 2010 was primarily attributable to $289.9 million of net proceeds from the sale of Partnership units during the year ended December 31, 2011 compared to $109.4 million of net proceeds from the sale of Partnership units during the year ended December 31, 2010. This was partially offset by an increase in capital expenditures from $236.0 million during the year ended December 31, 2010 to $282.8 million during the year ended December 31, 2011.

Financing Activities.  The decrease in cash used in financing activities during the year ended December 31, 2011 compared to the year ended December 31, 2010 was primarily attributable to a decrease in net repayments of long-term debt during the year ended December 31, 2011.

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 $325 million to $375 million in net capital expenditures during 2012, including (1) contract operations equipment additions and (2) approximately $105 million to $115 million on equipment maintenance capital related to our contract operations business. Net capital expenditures are net of fleet sales.

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Long-Term Debt.  As of December 31, 2011, we had approximately $1.8 billion in outstanding debt obligations, consisting of $433.5 million outstanding under our revolving credit facility, $143.8 million outstanding under our 4.75% convertible notes due 2014, $300.1 million outstanding under our 4.25% Notes due June 2014, $350.0 million outstanding under our 7.25% senior notes due 2018, $395.5 million outstanding under the Partnership’s revolving credit facility and $150.0 million outstanding under the Partnership’s term loan facility.

At December 31, 2011, taking into account guarantees through letters of credit, bid bonds and performance bonds, we had undrawn capacity of $449.9 million under our revolving credit facility. Our senior secured credit agreement limits our Total Debt (as defined in the credit agreement) to Adjusted EBITDA ratio of not greater than 5.0 to 1.0. Due to this limitation, $190.3 million of the $449.9 million of undrawn capacity under our revolving credit facility was available for additional borrowings as of December 31, 2011.

In July 2011, we entered into a new five-year, $1.1 billion senior secured revolving credit facility (the “2011 Credit Facility”), which matures in July 2016 and replaced our former senior secured credit facility. We incurred approximately $7.8 million in transaction costs related to the 2011 Credit Facility. These costs are included in Intangible and other assets, net and amortized over the facility term. As a result of the termination of our former senior secured credit facility, we expensed approximately $1.6 million of deferred financing costs associated with our former senior secured credit facility in the third quarter of 2011.

Borrowings under the 2011 Credit Facility bear interest at a base rate or LIBOR, at our option, plus an applicable margin. Depending on our Total Leverage Ratio (as defined in the credit agreement), the applicable margin for revolving loans varies (i) in the case of LIBOR loans, from 1.50% to 2.50% and (ii) in the case of base rate loans, from 0.50% to 1.50%. The base rate is the highest of the prime rate announced by Wells Fargo Bank, National Association, the Federal Funds Rate plus 0.5% and one-month LIBOR plus 1.0%. At December 31, 2011, all amounts outstanding under the 2011 Credit Facility were LIBOR loans and the applicable margin was 2.25%. The weighted average annual interest rate at December 31, 2011 on the outstanding balance under the 2011 Credit Facility, excluding the effect of interest rate swaps, was 2.6%.

Our Significant Domestic Subsidiaries (as defined in the credit agreement) guarantee the debt under the 2011 Credit Facility. Borrowings under the 2011 Credit Facility are secured by substantially all of the personal property assets and certain real property assets of us and our Significant Domestic Subsidiaries, including all of the equity interests of our U.S. subsidiaries (other than certain excluded subsidiaries) and 65% of the equity interests in certain of our first-tier foreign subsidiaries. The Partnership does not guarantee the debt under the 2011 Credit Facility, its assets are not collateral under the 2011 Credit Facility and the general partner units in the Partnership are not pledged under the 2011 Credit Facility. Subject to certain conditions, at our request, and with the approval of the lenders, the aggregate commitments under the 2011 Credit Facility may be increased by up to an additional $300 million.

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 are also subject to financial covenants, including a ratio of Adjusted EBITDA (as defined in the credit agreement) to Total Interest Expense (as defined in the credit agreement) of not less than 2.25 to 1.0, a ratio of consolidated Total Debt to Adjusted EBITDA of not greater than 5.0 to 1.0 and a ratio of Senior Secured Debt (as defined in the credit agreement) to Adjusted EBITDA of not greater than 4.0 to 1.0. As of December 31, 2011, we maintained a 4.3 to 1.0 Adjusted EBITDA to Total Interest Expense ratio, a 4.3 to 1.0 consolidated Total Debt to Adjusted EBITDA ratio and a 1.5 to 1.0 Senior Secured Debt to Adjusted EBITDA ratio. If we fail to remain in compliance with our financial covenants we would be in default under our debt agreements. In addition, if we were to experience a material adverse effect on our assets, liabilities, financial condition, business or operations that, taken as a whole, impacts our ability to perform our obligations under our debt agreements, this could lead to a default under our debt agreements. 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

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certain of our other debt agreements, which would accelerate our obligation to repay our indebtedness under those agreements. As of December 31, 2011, we were in compliance with all financial covenants under the credit agreement.

In August 2007, Exterran ABS 2007 LLC, our wholly-owned subsidiary, entered into an asset-backed securitization facility. In March 2011, we repaid the $6.0 million outstanding balance under this facility and terminated it. As a result of this termination, we expensed $1.4 million of unamortized deferred financing costs, which is reflected in interest expense in our consolidated statements of operations.

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 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 $355.0 million aggregate principal amount of 4.25% convertible senior notes due June 2014 (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.

In November 2010, the Partnership, as guarantor, and EXLP Operating LLC, a wholly-owned subsidiary of the Partnership, as borrower, entered into an amendment and restatement of their senior secured credit agreement (the “Partnership Credit Agreement”) to provide for a new five-year, $550.0 million senior secured credit facility consisting of a $400.0 million revolving credit facility and a $150.0 million term loan facility. In March 2011, the revolving borrowing capacity under this facility was increased by $150.0 million to $550.0 million. Concurrent with the execution of the Partnership Credit Agreement in November 2010, the Partnership borrowed $304.0 million under its revolving credit facility and $150.0 million under its term loan facility and used the proceeds to

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(i) repay the entire $406.1 million outstanding under the Partnership’s previous senior secured credit facility, (ii) repay the entire $30.0 million outstanding under the Partnership’s asset-backed securitization facility and terminate that facility, (iii) pay $14.8 million to terminate the interest rate swap agreements to which the Partnership was a party and (iv) pay customary fees and other expenses relating to the Partnership Credit Agreement.

As of December 31, 2011, the Partnership had $154.5 million of undrawn capacity under its revolving credit facility. The Partnership Credit Agreement limits the Partnership’s Total Debt to EBITDA ratio (as defined in the Partnership Credit Agreement) 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 such an acquisition closes. The Partnership completed an acquisition from us meeting these thresholds in the second quarter of 2011; therefore, the maximum allowed ratio of Total Debt to EBITDA was 5.25 to 1.0 through December 31, 2011, reverting to 4.75 to 1.0 for the quarter ending March 31, 2012 and subsequent quarters.

The Partnership is currently working to increase the borrowing capacity under its revolving credit facility by approximately $200.0 million, which it expects to close in the first quarter of 2012. Concurrently with closing, we expect to decrease the borrowing capacity under our revolving credit facility by approximately $200.0 million.

The Partnership’s revolving credit facility bears interest at a base rate or LIBOR, at the Partnership’s option, plus an applicable margin. Depending on the Partnership’s leverage ratio, the applicable margin for revolving loans varies (i) in the case of LIBOR loans, from 2.25% to 3.25% and (ii) in the case of base rate loans, from 1.25% to 2.25%. The base rate is the highest of the prime rate announced by Wells Fargo Bank, National Association, the Federal Funds Effective Rate plus 0.5% and one-month LIBOR plus 1.0%. At December 31, 2011, all amounts outstanding under this facility were LIBOR loans and the applicable margin was 2.5%. The weighted average annual interest rate on the outstanding balance of this facility at December 31, 2011, excluding the effect of interest rate swaps, was 2.8%.

The Partnership’s term loan facility bears interest at a base rate or LIBOR, at the Partnership’s option, plus an applicable margin. Depending on the Partnership’s leverage ratio, the applicable margin for term loans varies (i) in the case of LIBOR loans, from 2.5% to 3.5% and (ii) in the case of base rate loans, from 1.5% to 2.5%. At December 31, 2011, all amounts outstanding under the term loan were LIBOR loans and the applicable margin was 2.75%. The average annual interest rate on the outstanding balance of the term loan at December 31, 2011 was 3.1%.

Borrowings under the Partnership Credit Agreement are secured by substantially all of the U.S. personal property assets of the Partnership and its Significant Domestic Subsidiaries (as defined in the Partnership Credit Agreement), including all of the membership interests of the Partnership’s Domestic Subsidiaries (as defined in the Partnership Credit Agreement).

The Partnership Credit Agreement 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. It also contains various covenants requiring mandatory prepayments of the term loans from the net cash proceeds of certain future asset transfers and debt issuances. 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. As discussed above, the Partnership completed an acquisition from us meeting these thresholds in the second quarter of 2011; therefore, the Partnership’s Total Debt to EBITDA ratio was temporarily increased from 4.75 to 1.0 to 5.25 to 1.0 through December 31, 2011, reverting to 4.75 to 1.0 for the quarter ending March 31, 2012 and

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subsequent quarters. As of December 31, 2011, the Partnership maintained a 7.3 to 1.0 EBITDA to Total Interest Expense ratio and a 3.7 to 1.0 Total Debt to EBITDA ratio. A violation of the Partnership’s Total Debt to EBITDA covenant would be an event of default under the Partnership Credit Agreement, which would trigger cross-default provisions under certain of our debt agreements. As of December 31, 2011, the Partnership was in compliance with all financial covenants under the Partnership Credit Agreement.

We have entered into interest rate swap agreements related to a portion of our variable rate debt. In the fourth quarter of 2010, we paid $43.0 million to terminate interest rate swap agreements with a total notional value of $585.0 million and a weighted average rate of 4.6%. These swaps qualified for hedge accounting and were previously included on our balance sheet as a liability and in accumulated other comprehensive income (loss). The liability was paid in connection with the termination, and the associated amount in accumulated other comprehensive income (loss) will be amortized into interest expense over the original term of the swaps. Of the total amount included in accumulated other comprehensive income (loss), $20.3 million was amortized into interest expense during the year ended December 31, 2011 and we expect $10.7 million to be amortized into interest expense in 2012. See Part II, Item 7A “Quantitative and Qualitative Disclosures About Market Risk” of this report for further discussion of our interest rate swap agreements.

We may from time to time seek to retire or purchase our outstanding debt though cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Historically, we have financed capital expenditures with a combination of net cash provided by operating and financing activities. Our ability to access the capital markets may be restricted at a time when we would like, or need, to do so, which could have an adverse impact on our ability to maintain our fleet and to grow. If any of our lenders become unable to perform their obligations under our credit facilities, our borrowing capacity under these facilities could be reduced. Inability to borrow additional amounts under those facilities could limit our ability to fund our future growth and operations. Based on current market conditions, we expect that net cash provided by operating activities and borrowings under our credit facilities will be sufficient to finance our operating expenditures, capital expenditures and scheduled interest and debt repayments through December 31, 2012; however, to the extent it is not, we may seek additional debt or equity financing.

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

Partnership Distributions to Unitholders.  The Partnership’s partnership agreement requires it to distribute all of its “available cash” quarterly. Under the partnership agreement, available cash is defined generally to mean, for each fiscal quarter, (1) cash on hand at the Partnership at the end of the quarter in excess of the amount of reserves its general partner determines is necessary or appropriate to provide for the conduct of its business, to comply with applicable law, any of its debt instruments or other agreements or to provide for future distributions to its unitholders for any one or more of the upcoming four quarters, plus, (2) if the Partnership’s general partner so determines, all or a portion of the Partnership’s cash on hand on the date of determination of available cash for the quarter.

Under the terms of the partnership agreement, there is no guarantee that unitholders will receive quarterly distributions from the Partnership. The Partnership’s distribution policy, which may be changed at any time, is

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subject to certain restrictions, including (1) restrictions contained in the Partnership’s revolving credit facility, (2) the Partnership’s general partner’s establishment of reserves to fund future operations or cash distributions to the Partnership’s unitholders, (3) restrictions contained in the Delaware Revised Uniform Limited Partnership Act and (4) the Partnership’s lack of sufficient cash to pay distributions.

Through our ownership of common units and all of the equity interests in the Partnership’s general partner, we expect to receive cash distributions from the Partnership.

On February 14, 2012, the Partnership distributed $0.4925 per limited partner unit, or approximately $19.6 million, including distributions to the Partnership’s general partner on its incentive distribution rights. The distribution covers the period from October 1, 2011 through December 31, 2011. The record date for this distribution was February 9, 2012.

Contractual obligations.    The following summarizes our contractual obligations at December 31, 2011 and the effect such obligations are expected to have on our liquidity and cash flow in future periods (in thousands):

	Total		2012			2013-2014		2015-2016		Thereafter
Long-term Debt(1):
Revolving credit facility due July 2016	$	433,500	$	—		$	—	$	433,500	$	—
Partnership’s revolving credit facility due November 2015		395,500		—			—		395,500		—
Partnership’s term loan facility due November 2015		150,000		—			—		150,000		—
4.25% convertible senior notes due June 2014(2)		355,000		—			355,000		—		—
4.75% convertible senior notes due January 2014		143,750		—			143,750		—		—
7.25% senior notes due December 2018		350,000		—			—		—		350,000
Other		140		140	(3)				—		—
Total long-term debt		1,827,890		140			498,750		979,000		350,000
Interest on long-term debt(4)		373,845		92,028			145,880		87,273		48,664
Purchase commitments		249,384		249,298			86		—		—
Facilities and other operating leases		55,575		14,188			14,829		10,631		15,927
Total contractual obligations	$	2,506,694	$	355,654		$	659,545	$	1,076,904	$	414,591

(1) For more information on our long-term debt, see Note 10 to the Financial Statements.

(2) These amounts include the full face value of the 4.25% Notes and are not reduced by the unamortized discount of $54.9 million as of December 31, 2011.

(3) These maturities are classified as long-term because we have the intent and ability to refinance these maturities with our existing long-term credit facilities.

(4) Interest amounts calculated using interest rates in effect as of December 31, 2011, including the effect of interest rate swaps.

At December 31, 2011, $14.7 million of unrecognized tax benefits (including discontinued operations) have been recorded as liabilities in accordance with the accounting standard for income taxes related to uncertain tax positions and we are uncertain as to if or when such amounts may be settled. Related to these unrecognized tax benefits, we have also recorded a liability for potential penalties and interest of $11.9 million (including discontinued operations).

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Off-Balance Sheet Arrangements

We have no material off-balance sheet arrangements.

Effects of Inflation

Our revenues and results of operations have not been materially impacted by inflation in the past three fiscal years.

Critical Accounting Estimates

This discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the U.S. (“GAAP”). The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates and accounting policies, including those related to bad debts, inventories, fixed assets, investments, intangible assets, income taxes, revenue recognition and contingencies and litigation. We base our estimates on historical experience and on other assumptions that we believe are reasonable under the circumstances. The results of this process form the basis of our judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions, and these differences can be material to our financial condition, results of operations and liquidity. We describe our significant accounting policies more fully in Note 1 to our Financial Statements.

Allowances and Reserves

We maintain allowances for doubtful accounts for estimated losses resulting from the inability of our customers to make required payments. The determination of the collectibility of amounts due from our customers requires us to use estimates and make judgments regarding future events and trends, including monitoring our customers’ payment history and current credit worthiness to determine that collectibility is reasonably assured, as well as consideration of the overall business climate in which our customers operate. Inherently, these uncertainties require us to make judgments and estimates regarding our customers’ ability to pay amounts due us in order to determine the appropriate amount of valuation allowances required for doubtful accounts. We review the adequacy of our allowance for doubtful accounts quarterly. We determine the allowance needed based on historical write-off experience and by evaluating significant balances aged greater than 90 days individually for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. During 2011, 2010, and 2009, we recorded bad debt expense of $1.6 million, $4.8 million and $5.9 million, respectively. A five percent change in the allowance for doubtful accounts would have had an impact on income before income taxes of approximately $0.6 million for the year ended December 31, 2011.

Inventory is a significant component of current assets and is stated at the lower of cost or market. This requires us to record provisions and maintain reserves for excess, slow moving and obsolete inventory. To determine these reserve amounts, we regularly review inventory quantities on hand and compare them to estimates of future product demand, market conditions and production requirements. These estimates and forecasts inherently include uncertainties and require us to make judgments regarding potential outcomes. During 2011, 2010, and 2009, we recorded additional inventory reserves of $4.9 million, $2.2 million and $5.3 million, respectively. Significant or unanticipated changes to our estimates and forecasts could impact the amount and timing of any additional provisions for excess or obsolete inventory that may be required. A five percent change in this inventory reserve balance would have had an impact on income before income taxes of approximately $0.8 million for the year ended December 31, 2011.

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Depreciation

Property, plant and equipment are carried at cost. Depreciation for financial reporting purposes is computed on the straight-line basis using estimated useful lives and salvage values. The assumptions and judgments we use in determining the estimated useful lives and salvage values of our property, plant and equipment reflect both historical experience and expectations regarding future use of our assets. The use of different estimates, assumptions and judgments in the establishment of property, plant and equipment accounting policies, especially those involving their useful lives, would likely result in significantly different net book values of our assets and results of operations.

Long-Lived Assets

We review for impairment of long-lived assets, including property, plant and equipment and identifiable intangibles that are being amortized, whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The determination that the carrying amount of an asset may not be recoverable requires us to make judgments regarding long-term forecasts of future revenues and costs related to the assets subject to review. These forecasts are uncertain as they require significant assumptions about future market conditions. Significant and unanticipated changes to these assumptions could require a provision for impairment in a future period. Given the nature of these evaluations and their application to specific assets and specific times, it is not possible to reasonably quantify the impact of changes in these assumptions. An impairment loss exists when estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. When necessary, an impairment loss is recognized and represents the excess of the asset’s carrying value as compared to its estimated fair value and is charged to the period in which the impairment occurred.

Income Taxes

Our income tax expense, deferred tax assets and liabilities, and reserves for unrecognized tax benefits reflect management’s best assessment of estimated current and future taxes to be paid. We operate in approximately 30 countries and, as a result, are subject to income taxes in both the U.S. and numerous foreign jurisdictions. Significant judgments and estimates are required in determining consolidated income tax expense.

Deferred income taxes arise from temporary differences between the financial statements and tax basis of assets and liabilities. In evaluating our ability to recover our deferred tax assets within the jurisdiction from which they arise, we consider all available positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, tax-planning strategies, and results of recent operations. In projecting future taxable income, we begin with historical results adjusted for the results of discontinued operations and changes in accounting policies and incorporate assumptions including the amount of future U.S. federal, state and foreign pretax operating income, the reversal of temporary differences and the implementation of feasible and prudent tax-planning strategies. These assumptions require significant judgment about the forecasts of future taxable income and are consistent with the plans and estimates we are using to manage the underlying businesses. In evaluating the objective evidence that historical results provide, we consider three years of cumulative operating income (loss).

Changes in tax laws and rates could also affect recorded deferred tax assets and liabilities in the future. Management is not aware of any such changes that would have a material effect on the Company’s results of operations, cash flows or financial position. The calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in a multitude of jurisdictions across our global operations.

The accounting standard for income taxes provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, on the basis of the technical merits. In addition,

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guidance is provided on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. We adjust these liabilities when our judgment changes as a result of the evaluation of new information not previously available. Because of the complexity of some of these uncertainties, the ultimate resolution may result in a payment that is materially different from our current estimate of the tax liabilities. These differences will be reflected as increases or decreases to income tax expense in the period in which new information is available.

We consider the earnings of certain non-U.S. subsidiaries to be indefinitely invested outside the U.S. on the basis of estimates that future domestic cash generation will be sufficient to meet future domestic cash needs. We have not recorded a deferred tax liability related to these unremitted foreign earnings as it is not practicable to estimate the amount of unrecognized deferred tax liabilities. Should we decide to repatriate any unremitted foreign earnings, we would have to adjust the income tax provision in the period we determined that such earnings will no longer be indefinitely invested outside the U.S.

Revenue Recognition — Percentage-of-Completion Accounting

We recognize revenue and profit for our fabrication operations as work progresses on long-term contracts using the percentage-of-completion method when the applicable criteria are met, which relies on estimates of total expected contract revenue and costs. We follow this method because reasonably dependable estimates of the revenue and costs applicable to various stages of a contract can be made and because the fabrication projects usually last several months. Recognized revenues and profit are subject to revisions as the contract progresses to completion. Revisions in profit estimates are charged to income in the period in which the facts that give rise to the revision become known. The typical duration of these projects is three to 36 months. Due to the long-term nature of some of our jobs, developing the estimates of cost often requires significant judgment.

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

Factors that must be considered in estimating the work to be completed and ultimate profit include labor productivity and availability, the nature and complexity of work to be performed, the impact of change orders, availability of raw materials and the impact of delayed performance. If the aggregate combined cost estimates for all of our fabrication businesses had been higher or lower by 1% in 2011, our results of operations before tax would have decreased or increased by approximately $11.0 million. As of December 31, 2011, we had recognized approximately $157.9 million in estimated earnings on uncompleted contracts.

Contingencies and Litigation

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. In addition, we currently have a minimal amount of insurance on our offshore assets. Losses up to deductible amounts are estimated and accrued based upon known facts, historical trends and industry averages. We review these estimates quarterly and believe such accruals to be adequate. However, insurance liabilities are difficult to estimate due to unknown factors, including the severity of an injury, the determination of our liability in proportion to other parties, the timeliness of reporting of occurrences, ongoing treatment or loss mitigation, general trends in litigation recovery outcomes and the effectiveness of safety and risk management programs. Therefore, if our actual experience differs from the

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assumptions and estimates used for recording the liabilities, adjustments may be required and would be recorded in the period in which the difference becomes known. As of December 31, 2011 and 2010, we had recorded approximately $6.3 million and $7.5 million, respectively, in claim reserves.

In the ordinary course of business, we are involved in various pending or threatened legal actions. While we are unable to predict the ultimate outcome of these actions, the accounting standard for contingencies requires management to make judgments about future events that are inherently uncertain. We are required to record (and have recorded) a loss during any period in which we believe a contingency is probable and can be reasonably estimated. In making determinations of likely outcomes of pending or threatened legal matters, we consider the evaluation of counsel knowledgeable about each matter.

The impact of an uncertain tax position taken or expected to be taken on an income tax return must be recognized in the financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authority in accordance with the accounting standard for income taxes. We regularly assess and, if required, establish accruals for tax contingencies pursuant to the applicable accounting standards that could result from assessments of additional tax by taxing jurisdictions in countries where we operate. The tax contingencies are subject to a significant amount of judgment and are reviewed and adjusted on a quarterly basis in light of changing facts and circumstances considering the outcome expected by management. As of December 31, 2011 and 2010, we had recorded approximately $50.7 million and $48.3 million (including penalties and interest and discontinued operations), respectively, of accruals for tax contingencies. If our actual experience differs from the assumptions and estimates used for recording the liabilities, adjustments may be required and would be recorded in the period in which the difference becomes known.

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements that may affect us, see Note 21 to the Financial Statements.

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risks primarily associated with changes in interest rates and foreign currency exchange rates. We use derivative financial instruments to minimize the risks and/or costs associated with financial activities by managing our exposure to interest rate fluctuations on a portion of our debt obligations. We do not use derivative financial instruments for trading or other speculative purposes.

We have significant international operations. The net assets and liabilities of these operations are exposed to changes in currency exchange rates. These operations may also have net assets and liabilities not denominated in their functional currency, which exposes us to changes in foreign currency exchange rates that impact income. We recorded a foreign currency loss in our consolidated statements of operations of $17.1 million in the year ended December 31, 2011 compared to a gain of $5.4 million in the year ended December 31, 2010. Our foreign currency gains and losses are primarily due to exchange rate fluctuations related to monetary asset balances denominated in currencies other than the functional currency. Changes in exchange rates may create gains or losses in future periods to the extent we maintain net assets and liabilities not denominated in the functional currency.

As of December 31, 2011, after taking into consideration interest rate swaps, we had approximately $264.0 million of outstanding indebtedness that was effectively subject to floating interest rates. 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 $2.6 million.

For further information regarding our use of interest rate swap agreements to manage our exposure to interest rate fluctuations on a portion of our debt obligations, see Note 11 to the Financial Statements.

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Item 8.  Financial Statements and Supplementary Data

The financial statements and supplementary information specified by this Item are presented in Part IV, Item 15 of this report.

Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A.  Controls and Procedures

Management’s Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, our principal executive officer and principal financial officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)), which are designed to provide reasonable assurance that we are able to record, process, summarize and report the information required to be disclosed in our reports under the Exchange Act within the time periods specified in the rules and forms of the Securities and Exchange Commission. Based on the evaluation, as of December 31, 2011 our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective to provide reasonable assurance that the information required to be disclosed in reports that we file or submit under the Exchange Act is accumulated and communicated to management, and made known to our principal executive officer and principal financial officer, on a timely basis to ensure that it is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Management’s Annual Report on Internal Control Over Financial Reporting

As required by Exchange Act Rules 13a-15(c) and 15d-15(c), our management, including the Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness as to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Based on the results of management’s evaluation described above, management concluded that our internal control over financial reporting was effective as of December 31, 2011.

The effectiveness of internal control over financial reporting as of December 31, 2011 was audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in its report found within this report.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Exterran Holdings, Inc.

Houston, Texas

We have audited the internal control over financial reporting of Exterran Holdings, Inc. and subsidiaries (the “Company”) as of December 31, 2011, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2011 of the Company and our report dated February 23, 2012 expressed an unqualified opinion on those financial statements and financial statement schedule.

/s/ DELOITTE & TOUCHE, LLP

Houston, Texas

February 23, 2012

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Item 9B.  Other Information

None.

PART III

Item 10.  Directors, Executive Officers and Corporate Governance

The information required in Part III, Item 10 of this report is incorporated by reference to the sections entitled “Election of Directors,” “Information Regarding Corporate Governance, the Board of Directors and Committees of the Board,” “Executive Officers” and “Beneficial Ownership of Common Stock — Section 16(a) Beneficial Ownership Reporting Compliance” in our definitive proxy statement, to be filed with the SEC within 120 days of the end of our fiscal year.

Item 11.  Executive Compensation

The information required in Part III, Item 11 of this report is incorporated by reference to the sections entitled “Compensation Discussion and Analysis” and “Information Regarding Executive Compensation” in our definitive proxy statement, to be filed with the SEC within 120 days of the end of our fiscal year.

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

Portions of the information required in Part III, Item 12 of this report are incorporated by reference to the section entitled “Beneficial Ownership of Common Stock” in our definitive proxy statement, to be filed with the SEC within 120 days of the end of our fiscal year.

Securities Authorized for Issuance under Equity Compensation Plans

The following table sets forth information as of December 31, 2011, with respect to the Exterran compensation plans under which our common stock is authorized for issuance, aggregated as follows:

Plan Category	(a) Number of  Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (#)		(b) Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights ($)		(c) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) (#)
Equity compensation plans approved by security holders(1)		1,990,894		26.70		4,974,395
Equity compensation plans not approved by security holders(2)		328,676		10.21		609,611
Total		2,319,570				5,584,006

(1) Comprised of the Exterran Holdings, Inc. 2007 Stock Incentive Plan and the Exterran Holdings, Inc. Employee Stock Purchase Plan. In addition to the outstanding options, as of December 31, 2011 there were 366,143 restricted stock units, payable in common stock upon vesting, outstanding under the 2007 Stock Incentive Plan.

(2) Comprised of the Exterran Holdings, Inc. Directors’ Stock and Deferral Plan and the 2011 Employment Inducement Long-Term Incentive Plan.

The table above does not include information with respect to equity plans we assumed from Hanover or Universal (the “Legacy Plans”). No additional grants may be made under the Legacy Plans.

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The following equity grants are outstanding under Legacy Plans that were approved by security holders:

Plan or Agreement Name	Number of Shares Reserved  for Issuance Upon the Exercise of Outstanding Stock Options (#)		Weighted- Average Exercise Price ($)		Shares Available for  Future Grants (#)
Hanover Compressor Company 2001 Equity Incentive Plan		29,798		39.34		None
Hanover Compressor Company 2003 Stock Incentive Plan		63,616		36.13		None
Universal Compression Holdings, Inc. Incentive Stock Option Plan		849,228		34.38		None

The Legacy Plan for which security holder approval was not solicited or obtained and for which grants of stock options remain outstanding consists of the Hanover Compression Company 1998 Stock Option Plan as set forth in the table below. This plan has the following material features: (1) awards were limited to stock options and were made to officers, directors, employees, and consultants; (2) unless otherwise set forth in an applicable stock option agreement the stock options vest over a period of up to four years; (3) the term of the stock options granted under the Legacy Plan may not exceed 10 years; and (4) no additional grants may be made under this Legacy Plan.

Plan or Agreement Name	Number of Shares Reserved  for Issuance Upon the Exercise of Outstanding Stock Options (#)		Weighted- Average Exercise Price ($)		Shares Available for Future Grants (#)
Hanover Compressor Company 1998 Stock Option Plan		8,875		44.76		None

Item 13.  Certain Relationships and Related Transactions and Director Independence

The information required in Part III, Item 13 of this report is incorporated by reference to the sections entitled “Certain Relationships and Related Transactions” and “Information Regarding Corporate Governance, the Board of Directors and Committees of the Board — Director Independence” in our definitive proxy statement, to be filed with the SEC within 120 days of the end of our fiscal year.

Item 14.  Principal Accountant Fees and Services

The information required in Part III, Item 14 of this report is incorporated by reference to the section entitled “Ratification of Appointment of Independent Registered Public Accounting Firm” in our definitive proxy statement, to be filed with the SEC within 120 days of the end of our fiscal year.

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PART IV

Item 15.  Exhibits and Financial Statement Schedules

(a) Documents filed as a part of this report.

1. Financial Statements.  The following financial statements are filed as a part of this report.

Report of Independent Registered Public Accounting Firm	F-1
Consolidated Balance Sheets	F-2
Consolidated Statements of Operations	F-3
Consolidated Statements of Comprehensive Income (Loss)	F-4
Consolidated Statements of Stockholders’ Equity	F-5
Consolidated Statements of Cash Flows	F-6
Notes to Consolidated Financial Statements	F-7

2. Financial Statement Schedule

Schedule II — Valuation and Qualifying Accounts S-1

All other schedules have been omitted because they are not required under the relevant instructions.

3. Exhibits

Exhibit	Description
2.1	Contribution, Conveyance and Assumption Agreement, dated July 26, 2010, by and among Exterran Holdings, Inc., Exterran Energy Solutions, L.P., EES Leasing LLC, EXH GP LP LLC, Exterran GP LLC, EXH MLP LP LLC, Exterran General Partner, L.P., EXLP Operating LLC, EXLP Leasing LLC and Exterran Partners, L.P., incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed on July 28, 2010
2.2	Contribution, Conveyance and Assumption Agreement, dated May 23, 2011, by and among Exterran Holdings, Inc., Exterran Energy Corp., Exterran General Holdings LLC, Exterran Energy Solutions, L.P., EES Leasing LLC, EXH GP LP LLC, Exterran GP LLC, EXH MLP LP LLC, Exterran General Partner, L.P., EXLP Operating LLC, EXLP Leasing LLC and Exterran Partners, L.P., incorporated by reference to Exhibit 2.1 of the Registrant’s Current Report on Form 8-K filed on May 24, 2011
3.1	Restated Certificate of Incorporation of Exterran Holdings, Inc., incorporated by reference to Exhibit 3.1 of the Registrant’s Current Report on Form 8-K filed on August 20, 2007
3.2	Second Amended and Restated Bylaws of Exterran Holdings, Inc., incorporated by reference to Exhibit 3.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008
4.1	Eighth Supplemental Indenture, dated August 20, 2007, by and between Hanover Compressor Company, Exterran Holdings, Inc., and U.S. Bank National Association, as Trustee, for the 4.75% Convertible Senior Notes due 2014, incorporated by reference to Exhibit 10.15 of the Registrant’s Current Report on Form 8-K filed on August 23, 2007
4.2	Indenture, dated as of June 10, 2009, between Exterran Holdings, Inc. and Wells Fargo Bank, National Association, as trustee, incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K filed on June 16, 2009
4.3	Supplemental Indenture, dated as of June 10, 2009, between Exterran Holdings, Inc. and Wells Fargo Bank, National Association, as trustee, incorporated by reference to Exhibit 4.2 of the Registrant’s Current Report on Form 8-K filed on June 16, 2009

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4.4	Indenture, dated as of November 23, 2010, by and among Exterran Holdings, Inc., the Guarantors named therein and Wells Fargo Bank, National Association, incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on November 24, 2010
10.1	Senior Secured Credit Agreement, dated as of July 8, 2011, by and among Exterran Holdings, Inc., as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, BNP Paribas, Credit Agricole Corporate and Investment Bank, Royal Bank of Canada and The Royal Bank of Scotland plc, as Co-Syndication Agents, and the other lenders signatory thereto, incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on July 14, 2011 (portions of this exhibit have been omitted by redacting a portion of the text (indicated by asterisks in the text) and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment)
10.2	Guaranty Agreement, dated as of July 8, 2011, made by EES Leasing LLC, EXH GP LP LLC, EXH MLP LP LLC and Exterran Energy Solutions, L.P. in favor of Wells Fargo Bank, National Association, as Administrative Agent, incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on July 14, 2011
10.3	Collateral Agreement, dated as of July 8, 2011, made by Exterran Holdings, Inc., EES Leasing LLC, EXH GP LP LLC, EXH MLP LP LLC and Exterran Energy Solutions, L.P. in favor of Wells Fargo Bank, National Association, as Administrative Agent, incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on July 14, 2011
10.4	Pledge Agreement, dated as of July 8, 2011, made by Exterran Holdings, Inc., EES GP, L.P., Enterra Compression Investment Company, EXH GP LP LLC, EXH MLP LP LLC, Exterran Energy Corp., Exterran Energy Solutions, L.P., Exterran General Holdings LLC, Exterran HL LLC, Exterran Holdings HL LLC, Hanover Asia, Inc., Universal Compression International, Inc. and Universal Compression Services LLC in favor of Wells Fargo Bank, National Association, as Administrative Agent, incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on July 14, 2011
10.5	Call Option Transaction Confirmation, dated June 4, 2009, between Exterran Holdings, Inc. and J.P. Morgan Chase Bank, National Association, London Branch, as dealer, incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on June 10, 2009
10.6	Call Option Transaction Confirmation, dated June 4, 2009, between Exterran Holdings, Inc. and Bank of America, N.A., as dealer, incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K filed on June 10, 2009
10.7	Call Option Transaction Confirmation, dated June 4, 2009, between Exterran Holdings, Inc. and Wachovia Bank, National Association, as dealer, incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K filed on June 10, 2009
10.8	Call Option Transaction Confirmation, dated June 4, 2009, between Exterran Holdings, Inc. and Credit Suisse International, as dealer, incorporated by reference to Exhibit 10.4 of the Registrant’s Current Report on Form 8-K filed on June 10, 2009
10.9	Warrants Confirmation, dated June 4, 2009, between Exterran Holdings, Inc. and J.P. Morgan Chase Bank, National Association, London Branch, as dealer, incorporated by reference to Exhibit 10.5 of the Registrant’s Current Report on Form 8-K filed on June 10, 2009
10.10	Warrants Confirmation, dated June 4, 2009, between Exterran Holdings, Inc. and Bank of America, N.A., as dealer, incorporated by reference to Exhibit 10.6 of the Registrant’s Current Report on Form 8-K filed on June 10, 2009
10.11	Warrants Confirmation, dated June 4, 2009, between Exterran Holdings, Inc. and Wachovia Bank, National Association, as dealer, incorporated by reference to Exhibit 10.7 of the Registrant’s Current Report on Form 8-K filed on June 10, 2009

70

10.12	Warrants Confirmation, dated June 4, 2009, between Exterran Holdings, Inc. and Credit Suisse International, as dealer, incorporated by reference to Exhibit 10.8 of the Registrant’s Current Report on Form 8-K filed on June 10, 2009
10.13	Amended and Restated Senior Secured Credit Agreement, dated as of November 3, 2010, by and among EXLP Operating LLC, as Borrower, Exterran Partners, L.P., as Guarantor, Wells Fargo Bank, National Association, as Administrative Agent, Bank of America, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication Agents, Barclays Bank plc and The Royal Bank of Scotland plc, as Co-Documentation Agents, and the lenders signatory thereto, incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on November 9, 2010
10.14	Amended and Restated Guaranty Agreement, dated as of November 3, 2010, made by Exterran Partners, L.P. and EXLP Leasing LLC in favor of Wells Fargo Bank, National Association, as Administrative Agent, incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on November 9, 2010
10.15	Amended and Restated Collateral Agreement, dated as of November 3, 2010, made by EXLP Operating LLC, Exterran Partners, L.P. and EXLP Leasing LLC in favor of Wells Fargo Bank, National Association, as Administrative Agent, incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on November 9, 2010
10.16	Second Amended and Restated Omnibus Agreement, dated as of November 10, 2009, by and among Exterran Holdings, Inc., Exterran Energy Solutions, L.P., Exterran GP LLC, Exterran General Partner, L.P., EXLP Operating LLC and Exterran Partners, L.P., incorporated by reference to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2009 (portions of this exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment by redacting a portion of the text (indicated by asterisks in the text)
10.17	First Amendment to Second Amended and Restated Omnibus Agreement, dated August 11, 2010, by and among Exterran Partners, L.P., Exterran Holdings, Inc., Exterran Energy Solutions, L.P., Exterran GP LLC, Exterran General Partner, L.P. and EXLP Operating LLC, incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2010 (portions of this exhibit have been omitted by redacting a portion of the text (indicated by asterisks in the text) and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment)
10.18	Third Amended and Restated Omnibus Agreement, dated June 10, 2011, by and among Exterran Holdings, Inc., Exterran Energy Solutions, L.P., Exterran GP LLC, Exterran General Partner, L.P., EXLP Operating LLC and Exterran Partners, L.P., incorporated by reference to Exhibit 10.1 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011 (portions of this exhibit have been omitted by redacting a portion of the text (indicated by asterisks in the text) and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment)
10.19	Office Lease Agreement by and between RFP Lincoln Greenspoint, LLC and Exterran Energy Solutions, L.P., incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on August 30, 2007
10.20†	Exterran Holdings, Inc. Amended and Restated 2007 Stock Incentive Plan, incorporated by reference to Annex B to the Registrant’s Definitive Proxy Statement on Schedule 14A filed on March 26, 2009
10.21†	Amendment No. 1 to Exterran Holdings, Inc. Amended and Restated 2007 Stock Incentive Plan, incorporated by reference to Annex A to the Registrant’s Definitive Proxy Statement on Schedule 14A filed on March 26, 2009

71

10.22†	Amendment No. 2 to Exterran Holdings, Inc. Amended and Restated 2007 Stock Incentive Plan, incorporated by reference to Exhibit 10.10 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009
10.23†	Amendment No. 3 to the Exterran Holdings, Inc. Amended and Restated 2007 Stock Incentive Plan, incorporated by reference to Annex A to the Registrant’s Definitive Proxy Statement on Schedule 14A filed on March 29, 2010
10.24	Amendment No. 4 to the Exterran Holdings, Inc. Amended and Restated 2007 Stock Incentive Plan, incorporated by reference to Annex A to the Registrant’s Definitive Proxy Statement on Schedule 14A, filed March 29, 2011
10.25	Exterran Holdings, Inc. 2011 Employment Inducement Long-Term Equity Plan, incorporated by reference to Exhibit 4.1 to the Registrant’s Registration Statement on Form S-8, filed November 4, 2011
10.26†	Exterran Holdings, Inc. Directors’ Stock and Deferral Plan, incorporated by reference to Exhibit 10.16 of the Registrant’s Current Report on Form 8-K filed on August 23, 2007
10.27†	First Amendment to Exterran Holdings, Inc. Directors’ Stock and Deferral Plan, incorporated by reference to Exhibit 10.22 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008
10.28†	Exterran Holdings, Inc. Employee Stock Purchase Plan, incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K filed on August 23, 2007
10.29	Amendment No. 1 to the Exterran Holdings, Inc. Employee Stock Purchase Plan, incorporated by reference to Annex D to the Registrant’s Definitive Proxy Statement on Schedule 14A, filed March 29, 2011
10.30	Amendment No. 2 to the Exterran Holdings, Inc. Employee Stock Purchase Plan, incorporated by reference to Annex C to the Registrant’s Definitive Proxy Statement on Schedule 14A, filed March 29, 2011
10.31†	Exterran Holdings, Inc. Deferred Compensation Plan, incorporated by reference to Exhibit 10.29 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007
10.32†	Exterran Employees’ Supplemental Savings Plan, incorporated by reference to Exhibit 10.30 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007
10.33†	Exterran Annual Performance Pay Plan, incorporated by reference to Exhibit 10.29 of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007
10.34†	First Amendment to Universal Compression, Inc. 401(k) Retirement and Savings Plan, incorporated by reference to Exhibit 10.2 of Universal Compression Holdings, Inc.’s Current Report on Form 8-K filed on August 3, 2007
10.35†	Form of Exterran Holdings, Inc. Award Notice for Time-Vested Incentive Stock Option, incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009
10.36†	Form of Exterran Holdings, Inc. Award Notice for Time-Vested Non-Qualified Stock Option, incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009
10.37†	Form of Exterran Holdings, Inc. Award Notice for Time-Vested Restricted Stock, incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009
10.38†	Form of Exterran Holdings, Inc. Award Notice for Time-Vested Restricted Stock for Director, incorporated by reference to Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009

72

10.39†	Form of Exterran Holdings, Inc. Award Notice for Time-Vested Stock-Settled Restricted Stock Units, incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009
10.40†	Form of Exterran Holdings, Inc. Award Notice for Time-Vested Stock Option for Officers, incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010
10.41†	Form of Exterran Holdings, Inc. Award Notice for Time-Vested Non-Qualified Stock Option, incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010
10.42†	Form of Exterran Holdings, Inc. Award Notice for Time-Vested Restricted Stock, incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010
10.43†	Form of Exterran Holdings, Inc. Award Notice for Time-Vested Restricted Stock (Directors), incorporated by reference to Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010
10.44†	Form of Exterran Holdings, Inc. Award Notice for Time-Vested Stock-Settled Restricted Stock Units, incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010
10.45†	Form of Exterran Holdings, Inc. Award Notice for Time-Vested Cash-Settled Restricted Stock Units, incorporated by reference to Exhibit 10.6 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010
10.46†	Form of Exterran Holdings, Inc. Award Notice for Performance Shares, incorporated by reference to Exhibit 10.7 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2010
10.47†	Form of Exterran Holdings, Inc. Award Notice for Time-Vested Stock Option for Officers, incorporated by reference to Exhibit 10.63 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2010
10.48†	Form of Exterran Holdings, Inc. Award Notice for Time-Vested Non-Qualified Stock Option, incorporated by reference to Exhibit 10.64 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2010
10.49†	Form of Exterran Holdings, Inc. Award Notice for Performance Shares, incorporated by reference to Exhibit 10.65 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2010
10.50†	Form of Exterran Holdings, Inc. Award Notice for Time-Vested Restricted Stock, incorporated by reference to Exhibit 10.66 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2010
10.51†	Form of Exterran Holdings, Inc. Award Notice for Time-Vested Restricted Stock (Directors) , incorporated by reference to Exhibit 10.67 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2010
10.52†	Form of Exterran Holdings, Inc. Award Notice for Time-Vested Stock-Settled Restricted Stock Units, incorporated by reference to Exhibit 10.68 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2010
10.53†	Form of Exterran Holdings, Inc. Award Notice for Time-Vested Cash-Settled Restricted Stock Units, incorporated by reference to Exhibit 10.69 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2010
10.54†*	Form of Exterran Holdings, Inc. Award Notice for Time-Vested Restricted Stock under the 2011 Employment Inducement Long-Term Equity Plan

73

10.55†*	Form of Exterran Holdings, Inc. Award Notice for Time-Vested Non-qualified Stock Option under the 2011 Employment Inducement Long-Term Equity Plan
10.56†	Form of Indemnification Agreement, incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K filed on August 23, 2007
10.57†	Form of Exterran Holdings, Inc. Change of Control Agreement, incorporated by reference to Exhibit 10.19 of the Registrant’s Current Report on Form 8-K filed on August 23, 2007
10.58†	Form of First Amendment to Exterran Holdings, Inc. Change of Control Agreement, incorporated by reference to Exhibit 10.2 of the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008
10.59†*	Change of Control Agreement, effective December 12, 2011, between Exterran Holdings, Inc. and D. Bradley Childers
10.60†*	Change of Control Agreement, effective December 12, 2011, between Exterran Holdings, Inc. and William M. Austin
10.61†	Separation Agreement between Exterran Holdings, Inc. and Ernie L. Danner, dated August 3, 2011, incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on September 4, 2011
10.62†	Form of Exterran Holdings, Inc. Severance Benefit Agreement, incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on September 16, 2011
10.63†*	Severance Benefit Agreement, effective December 12, 2011, between Exterran Holdings, Inc. and William M. Austin
10.64†*	Offer Letter, dated December 6, 2011, to D. Bradley Childers
10.65†*	Offer Letter, dated December 6, 2011, to William M. Austin
21.1*	List of Subsidiaries
23.1*	Consent of Deloitte & Touche LLP
31.1*	Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1**	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
101.1***	Interactive data files pursuant to Rule 405 of Regulation S-T

† Management contract or compensatory plan or arrangement.

* Filed herewith.

** Furnished, not filed.

*** Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of sections 11 and 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to any liability under those sections.

74

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Exterran Holdings, Inc.
/s/  D. BRADLEY CHILDERS
Name:	D. Bradley Childers
Title:	President and Chief Executive Officer
Date: February 23, 2012

75

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints D. Bradley Childers, William M. Austin, Kenneth R. Bickett and Donald C. Wayne, and each of them, his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission granting unto said attorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done as fully to all said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue thereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 23, 2012.

Signature	Title
/s/    D. BRADLEY CHILDERS         D. Bradley Childers	President and Chief Executive Officer (Principal Executive Officer)
/s/    WILLIAM M. AUSTIN         William M. Austin	Executive Vice President and Chief Financial Officer (Principal Financial Officer)
/s/    KENNETH R. BICKETT         Kenneth R. Bickett	Vice President and Controller (Principal Accounting Officer)
/s/    MARK R. SOTIR         Mark R. Sotir	Executive Vice Chairman and Director
/s/    URIEL E. DUTTON         Uriel E. Dutton	Director
/s/    GORDON T. HALL         Gordon T. Hall	Director
/s/    J.W.G. HONEYBOURNE         J.W.G. Honeybourne	Director
/s/    MARK A. MCCOLLUM         Mark A. McCollum	Director
/s/    WILLIAM C. PATE         William C. Pate	Director
/s/    STEPHEN M. PAZUK         Stephen M. Pazuk	Director
/s/    CHRISTOPHER T. SEAVER         Christopher T. Seaver	Director

76

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Exterran Holdings, Inc.

Houston, Texas

We have audited the accompanying consolidated balance sheets of Exterran Holdings, Inc. and subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2011. Our audits also included the financial statement schedule for each of the three years in the period ended December 31, 2011 listed in the Index at Item 15. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2011, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23, 2012 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 23, 2012

F-1

EXTERRAN HOLDINGS, INC.

CONSOLIDATED BALANCE SHEETS

(In thousands, except par value and share amounts)

	December 31,
	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	22,039		$	44,616
Restricted cash		1,121			1,941
Accounts receivable, net of allowance of $11,357 and $13,108, respectively		462,971			429,047
Inventory, net		361,685			396,287
Costs and estimated earnings in excess of billings on uncompleted contracts		122,214			147,901
Current deferred income taxes		37,401			36,093
Other current assets		112,483			98,801
Current assets associated with discontinued operations		4,013			5,918
Total current assets		1,123,927			1,160,604
Property, plant and equipment, net		3,004,452			3,092,652
Goodwill, net		—			196,680
Intangible and other assets, net		232,283			282,428
Long-term assets associated with discontinued operations		—			9,172
Total assets	$	4,360,662		$	4,741,536
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable, trade	$	216,327		$	157,206
Accrued liabilities		279,054			330,551
Deferred revenue		84,156			124,282
Billings on uncompleted contracts in excess of costs and estimated earnings		83,961			130,610
Current liabilities associated with discontinued operations		6,383			15,554
Total current liabilities		669,881			758,203
Long-term debt		1,773,039			1,897,147
Other long-term liabilities		98,713			150,227
Deferred income taxes		124,847			120,424
Long-term liabilities associated with discontinued operations		14,140			13,111
Total liabilities		2,680,620			2,939,112
Commitments and contingencies (Note 20)
Equity:
Preferred stock, $0.01 par value per share; 50,000,000 shares authorized; zero issued		—			—
Common stock, $0.01 par value per share; 250,000,000 shares authorized; 70,407,010 and 69,071,027 shares issued, respectively		704			691
Additional paid-in capital		3,645,332			3,500,292
Accumulated other comprehensive income (loss)		6,059			(20,225	)
Accumulated deficit		(2,007,922	)		(1,667,314	)
Treasury stock — 6,143,589 and 5,841,087 common shares, at cost, respectively		(206,937	)		(203,996	)
Total Exterran stockholders’ equity		1,437,236			1,609,448
Noncontrolling interest		242,806			192,976
Total equity		1,680,042			1,802,424
Total liabilities and equity	$	4,360,662		$	4,741,536

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

F-2

EXTERRAN HOLDINGS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

	Years Ended December 31,
	2011			2010			2009
Revenues:
North America contract operations	$	603,529		$	608,065		$	695,315
International contract operations		445,059			465,144			391,995
Aftermarket services		409,423			322,097			308,873
Fabrication		1,225,459			1,066,227			1,319,418
		2,683,470			2,461,533			2,715,601
Costs and Expenses:
Cost of sales (excluding depreciation and amortization expense):
North America contract operations		310,069			300,686			298,714
International contract operations		184,405			175,357			149,253
Aftermarket services		348,662			276,307			245,886
Fabrication		1,102,237			904,722			1,106,166
Selling, general and administrative		359,382			358,255			337,620
Depreciation and amortization		365,870			401,478			352,785
Long-lived asset impairment		7,012			146,903			96,988
Restructuring charges		11,627			—			14,329
Goodwill impairment		196,807			—			150,778
Interest expense		149,473			136,149			122,845
Equity in loss of non-consolidated affiliates		471			609			91,154
Other (income) expense, net		(5,425	)		(13,763	)		(53,360	)
		3,030,590			2,686,703			2,913,158
Loss before income taxes		(347,120	)		(225,170	)		(197,557	)
Provision for (benefit from) income taxes		(13,465	)		(66,606	)		51,667
Loss from continuing operations		(333,655	)		(158,564	)		(249,224	)
Income (loss) from discontinued operations, net of tax		(5,963	)		45,323			(296,239	)
Net loss		(339,618	)		(113,241	)		(545,463	)
Less: Net (income) loss attributable to the noncontrolling interest		(990	)		11,416			(3,944	)
Net loss attributable to Exterran stockholders	$	(340,608	)	$	(101,825	)	$	(549,407	)
Basic loss per common share:
Loss from continuing operations attributable to Exterran stockholders	$	(5.34	)	$	(2.37	)	$	(4.12	)
Income (loss) from discontinued operations attributable to Exterran stockholders		(0.10	)		0.73			(4.83	)
Net loss attributable to Exterran stockholders	$	(5.44	)	$	(1.64	)	$	(8.95	)
Diluted loss per common share:
Loss from continuing operations attributable to Exterran stockholders	$	(5.34	)	$	(2.37	)	$	(4.12	)
Income (loss) from discontinued operations attributable to Exterran stockholders		(0.10	)		0.73			(4.83	)
Net loss attributable to Exterran stockholders	$	(5.44	)	$	(1.64	)	$	(8.95	)
Weighted average common and equivalent shares outstanding:
Basic		62,624			61,995			61,406
Diluted		62,624			61,995			61,406

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

F-3

EXTERRAN HOLDINGS, INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In thousands)

	Years Ended December 31,
	2011			2010			2009
Net loss		$ (339,618	)		$ (113,241	)		$ (545,463	)
Other comprehensive income (loss), net of tax:
Change in fair value of derivative financial instruments		(2,126	)		8,797			13,088
Adjustments from sale of Partnership units		1,184			—			—
Amortization of payments to terminate interest rate swaps		20,267			2,006			—
Foreign currency translation adjustment		3,343			(2,326	)		56,640
Total other comprehensive income		22,668			8,477			69,728
Comprehensive loss		(316,950	)		(104,764	)		(475,735	)
Less: Comprehensive (income) loss attributable to the noncontrolling interest		2,626			9,712			(6,784	)
Comprehensive loss attributable to Exterran stockholders	$	(314,324	)	$	(95,052	)	$	(482,519	)

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

F-4

EXTERRAN HOLDINGS, INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands, except share data)

	Exterran Holdings, Inc. Stockholders
	Common Stock				Additional Paid-in Capital			Accumulated Other Comprehensive Income (Loss)			Treasury Stock						Accumulated Deficit			Non- controlling Interest			Total
	Shares		Amount								Shares			Amount
Balance at December 31, 2008		67,202,109	$	672	$	3,354,922		$	(94,767	)		(5,535,671	)	$	(200,959	)	$	(1,016,082	)	$	184,291		$	2,228,077
Treasury stock purchased												(57,284	)		(976	)								(976	)
Shares issued in employee stock purchase plan		191,384		2		2,843																		2,845
Stock-based compensation, net of forfeitures		801,954		8		23,815						(74,942	)								926			24,749
Income tax benefit from stock-based compensation expense						(2,674	)																	(2,674	)
Cash distribution to noncontrolling unitholders of the Partnership																					(15,459	)		(15,459	)
Issuance of convertible senior notes and purchased call options and warrants sold						56,745																		56,745
Other						(1,033	)														320			(713	)
Comprehensive income (loss):
Net income (loss)																		(549,407	)		3,944			(545,463	)
Derivatives change in fair value, net of tax									10,248												2,840			13,088
Foreign currency translation adjustment									56,640															56,640
Balance at December 31, 2009		68,195,447	$	682	$	3,434,618		$	(27,879	)		(5,667,897	)	$	(201,935	)	$	(1,565,489	)	$	176,862		$	1,816,859
Treasury stock purchased												(84,922	)		(2,061	)								(2,061	)
Options exercised		50,494		1		839																		840
Shares issued in employee stock purchase plan		102,156		1		2,223																		2,224
Stock-based compensation, net of forfeitures		722,930		7		22,408						(88,268	)								585			23,000
Income tax benefit from stock-based compensation expense						(895	)																	(895	)
Net proceeds from sale of Partnership units, net of tax						41,111			881												43,273			85,265
Cash distribution to noncontrolling unitholders of the Partnership																					(18,030	)		(18,030	)
Other						(12	)														(2	)		(14	)
Comprehensive income (loss):
Net loss																		(101,825	)		(11,416	)		(113,241	)
Derivatives change in fair value, net of tax									7,093												1,704			8,797
Amortization of interest rate swap terminations, net of tax									2,006															2,006
Foreign currency translation adjustment									(2,326	)														(2,326	)
Balance at December 31, 2010		69,071,027	$	691	$	3,500,292		$	(20,225	)		(5,841,087	)	$	(203,996	)	$	(1,667,314	)	$	192,976		$	1,802,424
Treasury stock purchased												(157,756	)		(2,941	)								(2,941	)
Options exercised		32,545				526																		526
Shares issued in employee stock purchase plan		153,489		1		1,886																		1,887
Stock-based compensation, net of forfeitures		1,149,949		12		20,006						(144,746	)								135			20,153
Income tax benefit from stock-based compensation expense						(1,092	)																	(1,092	)
Net proceeds from sale of Partnership units, net of tax						123,904			1,184												92,190			217,278
Cash distribution to noncontrolling unitholders of the Partnership																					(39,870	)		(39,870	)
Other						(190	)														1			(189	)
Comprehensive income (loss):
Net loss																		(340,608	)		990			(339,618	)
Derivatives change in fair value, net of tax									1,490												(3,616	)		(2,126	)
Amortization of payments to terminate interest rate swaps, net of tax									20,267															20,267
Foreign currency translation adjustment									3,343															3,343
Balance at December 31, 2011		70,407,010	$	704	$	3,645,332		$	6,059			(6,143,589	)	$	(206,937	)	$	(2,007,922	)	$	242,806		$	1,680,042

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

F-5

EXTERRAN HOLDINGS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Years Ended December 31,
	2011			2010			2009
Cash flows from operating activities:
Net loss	$	(339,618	)	$	(113,241	)	$	(545,463	)
Adjustments:
Depreciation and amortization		365,870			401,478			352,785
Long-lived asset impairment		7,012			146,903			96,988
Goodwill impairment		196,807			—			150,778
Deferred financing cost amortization		8,977			5,303			3,913
(Income) loss from discontinued operations, net of tax		5,963			(45,323	)		296,239
Amortization of debt discount		18,323			16,364			8,329
Provision for doubtful accounts		1,610			4,750			5,929
Gain on sale of property, plant and equipment		(8,543	)		(7,322	)		(33,156	)
Gain on sale of business		—			—			(3,193	)
Equity in loss of non-consolidated affiliates, net of dividends received		471			609			91,154
Interest rate swaps		—			751			1,576
Amortization of payments to terminate interest rate swaps		20,267			2,006			—
(Gain) loss on currency exchange rate remeasurement of intercompany balances		14,594			(6,801	)		(15,097	)
Stock-based compensation expense		20,018			23,266			24,749
Deferred income tax provision		(52,389	)		(129,259	)		(6,684	)
Changes in assets and liabilities, net of acquisition:
Accounts receivable and notes		(58,303	)		36,421			111,464
Inventory		26,100			97,093			39,344
Costs and estimated earnings versus billings on uncompleted contracts		(21,601	)		2,910			35,587
Other current assets		(16,211	)		20,161			1,407
Accounts payable and other liabilities		(5,500	)		7,422			(68,515	)
Deferred revenue		(36,824	)		(85,693	)		(62,337	)
Other		(28,035	)		(9,543	)		(8,989	)
Net cash provided by continuing operations		118,988			368,255			476,808
Net cash provided by (used in) discontinued operations		1,336			(3,880	)		710
Net cash provided by operating activities		120,324			364,375			477,518
Cash flows from investing activities:
Capital expenditures		(282,791	)		(235,990	)		(368,901	)
Proceeds from sale of property, plant and equipment		46,258			31,195			69,097
Cash paid for business acquisition		(3,000	)		—			—
Proceeds from sale of business		—			—			5,642
Return of investments in non-consolidated affiliates		—			—			3,139
Net proceeds from the sale of Partnership units		289,908			109,365			—
(Increase) decrease in restricted cash		820			12,930			(7,308	)
Cash invested in non-consolidated affiliates		(471	)		(609	)		(1,959	)
Net cash provided by (used in) continuing operations		50,724			(83,109	)		(300,290	)
Net cash provided by (used in) discontinued operations		—			89,509			(710	)
Net cash provided by (used in) investing activities		50,724			6,400			(301,000	)
Cash flows from financing activities:
Proceeds from borrowings of long-term debt		1,893,740			2,098,244			1,180,815
Repayments of long-term debt		(2,036,171	)		(2,478,397	)		(1,342,785	)
Payments for debt issue costs		(8,823	)		(12,034	)		(12,293	)
Proceeds from warrants sold		—			—			53,138
Payment from call options		—			—			(89,408	)
Proceeds from stock options exercised		526			840			—
Proceeds from stock issued pursuant to our employee stock purchase plan		1,887			2,224			2,845
Purchases of treasury stock		(2,941	)		(2,061	)		(976	)
Stock-based compensation excess tax benefit		1,034			1,182			119
Distributions to noncontrolling partners in the Partnership		(39,870	)		(18,030	)		(15,459	)
Net cash used in financing activities		(190,618	)		(408,032	)		(224,004	)
Effect of exchange rate changes on cash and equivalents		(3,007	)		(1,872	)		7,325
Net decrease in cash and cash equivalents		(22,577	)		(39,129	)		(40,161	)
Cash and cash equivalents at beginning of period		44,616			83,745			123,906
Cash and cash equivalents at end of period	$	22,039		$	44,616		$	83,745
Supplemental disclosure of cash flow information:
Interest paid, net of capitalized amounts	$	100,735		$	109,952		$	112,521
Income taxes paid, net	$	59,735		$	47,325		$	69,507

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

F-6

EXTERRAN HOLDINGS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Background and Significant Accounting Policies

Exterran Holdings, Inc., together with its subsidiaries (“we” or “Exterran”), is 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.

We were incorporated in February 2007 as a wholly-owned subsidiary of Universal Compression Holdings, Inc. (“Universal”). On August 20, 2007, in accordance with their merger agreement, 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.

Principles of Consolidation

The accompanying consolidated financial statements include Exterran and its wholly-owned and majority-owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. Investments in affiliated entities in which we own more than a 20% interest and do not have a controlling interest are accounted for using the equity method.

For financial reporting purposes, we consolidate the financial statements of Exterran Partners, L.P. (together with its subsidiaries, the “Partnership”) with those of our own and reflect its operations in our North America contract operations business segment. We control the Partnership through our ownership of its general partner. Public ownership of the Partnership’s net assets and earnings are presented as a component of noncontrolling interest in our consolidated financial statements. The borrowings of the Partnership are presented as part of our consolidated debt. However, we do not have any obligation for the payment of interest or repayment of borrowings incurred by the Partnership.

Use of Estimates in the Financial Statements

The preparation of financial statements in conformity with accounting principles generally accepted in the U.S. (“GAAP”) requires management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses, as well as the disclosures of contingent assets and liabilities. Because of the inherent uncertainties in this process, actual future results could differ from those expected at the reporting date. Management believes that the estimates and assumptions used are reasonable.

F-7

Cash and Cash Equivalents

We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Restricted Cash

Restricted cash as of December 31, 2011 and 2010 consists of cash that contractually is not available for immediate use. Restricted cash is presented separately from cash and cash equivalents in the balance sheet and statement of cash flows.

Revenue Recognition

Revenue from contract operations is recorded when earned, which generally occurs monthly at the time the monthly service is provided to customers in accordance with the contracts. Aftermarket services revenue is recorded as products are delivered and title is transferred or services are performed for the customer.

Fabrication revenue is recognized using the percentage-of-completion method when the applicable criteria are met. We estimate percentage-of-completion for compressor and accessory fabrication on a direct labor hour to total labor hour basis. Production and processing equipment fabrication percentage-of-completion is estimated using the direct labor hour to total labor hour and the cost to total cost basis. The duration of these projects is typically between three and 36 months. Fabrication revenue is recognized using the completed contract method when the applicable criteria of the percentage-of-completion method are not met. Fabrication revenue from a claim is recognized to the extent that costs related to the claim have been incurred, when collection is probable and can be reliably estimated.

Concentrations of Credit Risk

Financial instruments that potentially subject us to concentrations of credit risk consist of cash and cash equivalents, accounts receivable and notes receivable. We believe that the credit risk in temporary cash investments is limited because our cash is held in accounts with multiple financial institutions. Trade accounts and notes receivable are due from companies of varying size engaged principally in oil and natural gas activities throughout the world. We review the financial condition of customers prior to extending credit and generally do not obtain collateral for trade receivables. Payment terms are on a short-term basis and in accordance with industry practice. We consider this credit risk to be limited due to these companies’ financial resources, the nature of products and the services we provide them and the terms of our contract operations service contracts.

We maintain allowances for doubtful accounts for estimated losses resulting from the inability of our customers to make required payments. The determination of the collectibility of amounts due from our customers requires us to use estimates and make judgments regarding future events and trends, including monitoring our customers’ payment history and current credit worthiness to determine that collectibility is reasonably assured, as well as consideration of the overall business climate in which our customers operate. Inherently, these uncertainties require us to make judgments and estimates regarding our customers’ ability to pay the amounts they owe in order to determine the appropriate amount of valuation allowances required for doubtful accounts. We review the adequacy of our allowance for doubtful accounts quarterly. We determine the allowance needed based on historical write-off experience and by evaluating significant balances aged greater than 90 days individually for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. During 2011, 2010 and 2009, our bad debt expense was $1.6 million, $4.8 million and $5.9 million, respectively.

Inventory

Inventory consists of parts used for fabrication or maintenance of natural gas compression equipment and facilities, processing and production equipment and also includes compression units and production equipment

F-8

that are held for sale. Inventory is stated at the lower of cost or market using the average-cost method. A reserve is recorded against inventory balances for estimated obsolescence based on specific identification and historical experience.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost and are depreciated using the straight-line method over their estimated useful lives as follows:

Compression equipment, facilities and other fleet assets	3 to 30 years
Buildings	20 to 35 years
Transportation, shop equipment and other	3 to 12 years

Major improvements that extend the useful life of an asset are capitalized. Repairs and maintenance are expensed as incurred. When property, plant and equipment is sold, retired or otherwise disposed of, the gain or loss is recorded in other (income) expense, net. Interest is capitalized during the construction period on equipment and facilities that are constructed for use in our operations. The capitalized interest is included as part of the cost of the asset to which it relates and is amortized over the asset’s estimated useful life.

Computer software

Certain costs related to the development or purchase of internal-use software are capitalized and amortized over the estimated useful life of the software, which ranges from three to five years. Costs related to the preliminary project stage, data conversion and the post-implementation/operation stage of an internal-use computer software development project are expensed as incurred.

Long-Lived Assets

We review for impairment of long-lived assets, including property, plant and equipment and identifiable intangibles that are being amortized whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss exists when estimated undiscounted cash flows expected to result from the use of the asset and its eventual disposition are less than its carrying amount. The impairment loss recognized represents the excess of the asset’s carrying value as compared to its estimated fair value. Identifiable intangibles are amortized over the assets’ estimated useful lives.

We hold investments in companies with operations in areas that relate to our business. We record an investment impairment charge when we believe an investment has experienced a decline in value that is other than temporary.

Deferred Revenue

Deferred revenue is primarily comprised of billings related to jobs where revenue is recognized on the percentage-of-completion method that have not begun, milestone billings related to jobs where revenue is recognized on the completed contract method and deferred revenue on contract operations jobs.

Other (Income) Expense, Net

Other (income) expense, net is primarily comprised of gains and losses from the remeasurement of our international subsidiaries’ net assets exposed to changes in foreign currency rates and on the sale of assets.

F-9

Income Taxes

We account for income taxes under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial statements and tax basis of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

We record net deferred tax assets to the extent we believe these assets will more likely than not be realized. In making such a determination, we consider all available positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, tax-planning strategies, and results of recent operations. In the event we were to determine that we would be able to realize our deferred income tax assets in the future in excess of their net recorded amount, we would make an adjustment to the deferred tax asset valuation allowance, which would reduce the provision for income taxes.

We record uncertain tax positions in accordance with the accounting standard on income taxes on the basis of a two-step process whereby (1) we determine whether it is more likely than not that the tax positions will be sustained based on the technical merits of the position and (2) those tax positions that meet the more-likely-than-not recognition threshold, we recognize the largest amount of tax benefit that is greater than 50 percent likely to be realized upon ultimate settlement with the related tax authority.

Foreign Currency Translation

The financial statements of subsidiaries outside the U.S., except those for which we have determined that the U.S. dollar is the functional currency, are measured using the local currency as the functional currency. Assets and liabilities of these subsidiaries are translated at the rates of exchange in effect at the balance sheet date. Income and expense items are translated at average monthly rates of exchange. The resulting gains and losses from the translation of accounts into U.S. dollars are included in accumulated other comprehensive income (loss) on our consolidated balance sheets. For all subsidiaries, gains and losses from remeasuring foreign currency accounts into the functional currency are included in other (income) expense, net on our consolidated statements of operations.

Hedging and Use of Derivative Instruments

We use derivative financial instruments to minimize the risks and/or costs associated with financial activities by managing our exposure to interest rate fluctuations on a portion of our debt obligations. We also use derivative financial instruments to minimize the risks caused by currency fluctuations in certain foreign currencies. We do not use derivative financial instruments for trading or other speculative purposes. We record interest rate swaps and foreign currency hedges on the balance sheet as either derivative assets or derivative liabilities measured at their fair value. The fair value of our derivatives was estimated using a combination of the market and income approach. Changes in the fair value of the derivatives designated as cash flow hedges are deferred in accumulated other comprehensive income (loss), net of tax, to the extent the contracts are effective as hedges until settlement of the underlying hedged transaction. To qualify for hedge accounting treatment, we must formally document, designate and assess the effectiveness of the transactions. If the necessary correlation ceases to exist or if the anticipated transaction becomes improbable, we would discontinue hedge accounting and apply mark-to-market accounting. Amounts paid or received from interest rate swap agreements are charged or credited to interest expense and matched with the cash flows and interest expense of the debt being hedged, resulting in an adjustment to the effective interest rate. Amounts paid or received from foreign currency derivatives designated as hedges are recorded against revenue and matched with the revenue recognized on the related contract being hedged.

F-10

Earnings (Loss) Attributable to Exterran Stockholders Per Common Share

Basic income (loss) attributable to Exterran stockholders per common share is computed by dividing income (loss) attributable to Exterran common stockholders by the weighted average number of shares outstanding for the period. Unvested share-based awards that contain nonforfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities and are included in the computation of earnings (loss) per share following the two-class method. Therefore, restricted share awards that contain the right to vote and receive dividends are included in the computation of basic and diluted earnings (loss) per share, unless their effect would be anti-dilutive.

Diluted income (loss) attributable to Exterran stockholders per common share is computed using the weighted average number of shares outstanding adjusted for the incremental common stock equivalents attributed to outstanding options and warrants to purchase common stock, restricted stock, restricted stock units, stock to be issued pursuant to our employee stock purchase plan and convertible senior notes, unless their effect would be anti-dilutive.

The table below summarizes loss attributable to Exterran stockholders (in thousands):

	Years Ended December 31,
	2011			2010			2009
Loss from continuing operations attributable to Exterran stockholders	$	(334,645	)	$	(147,148	)	$	(253,168	)
Income (loss) from discontinued operations, net of tax		(5,963	)		45,323			(296,239	)
Net loss attributable to Exterran stockholders	$	(340,608	)	$	(101,825	)	$	(549,407	)

There were no potential shares of common stock included in computing the dilutive potential shares of common stock used in diluted income (loss) per common share for the years ended December 31, 2011, 2010 and 2009, as the effect of their inclusion would have been anti-dilutive. The table below indicates the potential shares of common stock issuable that were excluded from net dilutive potential shares of common stock issuable as their effect would have been anti-dilutive (in thousands):

	Years Ended December 31,
	2011		2010		2009
Net dilutive potential common shares issuable:
On exercise of options where exercise price is greater than average market value for the period		2,533		1,359		1,140
On exercise of options and vesting of restricted stock and restricted stock units		675		735		539
On settlement of employee stock purchase plan shares		23		14		30
On exercise of warrants		2,808		2,808		1,604
On conversion of 4.25% convertible senior notes due 2014		15,334		15,334		8,762
On conversion of 4.75% convertible senior notes due 2014		3,114		3,114		3,114
Net dilutive potential common shares issuable		24,487		23,364		15,189

Comprehensive Income (Loss)

Components of comprehensive income (loss) are net income (loss) and all changes in equity during a period except those resulting from transactions with owners. Our accumulated other comprehensive income (loss) consists of foreign currency translation adjustments and changes in the fair value of derivative financial instruments, net of tax that are designated as cash flow hedges, and to the extent the hedge is effective. As a result of the changes in the fair values of derivatives designated as hedges and the amortization of interest rate swap terminations, we recorded an increase in accumulated other comprehensive income (loss) of $21.8 million

F-11

(net of tax of $12.1 million), $9.1 million (net of tax of $5.6 million) and $10.2 million (net of tax of $4.8 million) for the years ended December 31, 2011, 2010 and 2009, respectively.

Financial Instruments

Our financial instruments include cash, restricted cash, receivables, payables, interest rate swaps, debt and foreign currency hedges. At December 31, 2011 and 2010, the estimated fair value of these financial instruments approximated their carrying value as reflected in our consolidated balance sheets. The fair value of our fixed rate debt has been estimated primarily based on quoted market prices. The fair value of our floating rate debt has been estimated based on similar debt transactions that occurred near the valuation dates. A summary of the fair value and carrying value of our debt as of December 31, 2011 and 2010 is shown in the table below (in thousands):

	As of December 31, 2011				As of December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Fixed rate debt	$	794,039	$	792,000	$	775,810	$	808,000
Floating rate debt		979,000		989,000		1,121,337		1,101,000
Total debt	$	1,773,039	$	1,781,000	$	1,897,147	$	1,909,000

GAAP requires that all derivative instruments (including certain derivative instruments embedded in other contracts) be recognized in the balance sheet at fair value, and that changes in such fair values be recognized in earnings (loss) unless specific hedging criteria are met. Changes in the values of derivatives that meet these hedging criteria will ultimately offset related earnings effects of the hedged item pending recognition in earnings.

2. Discontinued Operations

In May 2009, the Venezuelan government enacted a law that reserves to the State of Venezuela certain assets and services related to hydrocarbon activities, which included substantially all of our assets and services in Venezuela. The law provides that the reserved activities are to be performed by the State, by the State-owned oil company, Petroleos de Venezuela S.A. (“PDVSA”), or its affiliates, or through mixed companies under the control of PDVSA or its affiliates. The law authorizes PDVSA or its affiliates to take possession of the assets and take over control of those operations related to the reserved activities as a step prior to the commencement of an expropriation process, and permits the national executive of Venezuela to decree the total or partial expropriation of shares or assets of companies performing those services.

In June 2009, PDVSA commenced taking possession of our assets and operations in a number of our locations in Venezuela and by the end of the second quarter of 2009, PDVSA had assumed control over substantially all of our assets and operations in Venezuela.

While the law provides that companies whose assets are expropriated in this manner may be compensated in cash or securities, we are unable to predict what, if any, compensation we ultimately will receive or when we may receive any such compensation. We reserve and will continue to reserve the right to seek full compensation for any and all expropriated assets and investments under all applicable legal regimes, including investment treaties and customary international law, as well as to seek resolution through direct discussions with Venezuela and/or PDVSA, which could result in us recording a gain on our investment in future periods. In this connection, on June 16, 2009, our Spanish subsidiary delivered to the Venezuelan government and PDVSA an official notice of dispute relating to the seized assets and investments under the Agreement between Spain and Venezuela for the Reciprocal Promotion and Protection of Investments and under Venezuelan law. On March 23, 2010, our Spanish subsidiary filed a request for the institution of an arbitration proceeding against Venezuela with the International Centre for Settlement of Investment Disputes (“ICSID”) related to the seized assets and investments, which was registered by ICSID on April 12, 2010. The arbitration hearing on jurisdiction and the merits is presently scheduled to take place in July 2012.

F-12

We maintained insurance for the risk of expropriation of our investments in Venezuela, subject to a policy limit of $50 million. During the year ended December 31, 2009, we recorded a receivable of $50 million related to this insurance policy because we determined that recovery under this policy of a portion of our loss was probable. We collected the $50 million under our policy in January 2010. Under the terms of the insurance policy, certain compensation we may receive from the Venezuelan government or PDVSA for our expropriated assets, receivables and operations will be applied first to the reimbursement of out-of-pocket expenses incurred by us and the insurance company, second to the insurance company until the $50 million payment has been repaid and third to us.

As a result of PDVSA taking possession of substantially all of our assets and operations in Venezuela, we recorded asset impairments during the year ended December 31, 2009, totaling $329.7 million ($379.7 million excluding the insurance proceeds of $50 million). These charges primarily related to receivables, inventory, fixed assets and goodwill, and are reflected in Income (loss) from discontinued operations. We believe the fair value of our seized Venezuelan operations substantially exceeds the historical cost-based carrying value of the assets, including the goodwill allocable to those operations; however, GAAP requires that our claim be accounted for as a gain contingency with no benefit being recorded until resolved. Accordingly, we did not include any compensation we may receive for our seized assets and operations from Venezuela in recording the loss on expropriation.

The expropriation of our business in Venezuela meets the criteria established for recognition as discontinued operations under accounting standards for presentation of financial statements. Therefore, our Venezuela contract operations and aftermarket services businesses are now reflected as discontinued operations in our consolidated statements of operations.

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 and is reflected in Other (income) loss, net in the table below for the year ended December 31, 2010. 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.

Our loss (recovery) attributable to expropriation for the year ended December 31, 2010 includes a benefit of $41.0 million from payments received from PDVSA and its affiliates as consideration 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.

The table below summarizes the operating results of the discontinued operations (in thousands):

	Years Ended December 31,
	2011			2010			2009
Revenues	$	—		$	2,940		$	69,050
Expenses and selling, general and administrative		1,302			5,892			61,761
Loss (recovery) attributable to expropriation		3,092			(38,925	)		329,685
Other (income) loss, net		(150	)		(12,145	)		(7,571	)
Provision for (benefit from) income taxes		1,719			2,795			(18,586	)
Income (loss) from discontinued operations, net of tax	$	(5,963	)	$	45,323		$	(296,239	)

F-13

The table below summarizes the balance sheet data for discontinued operations (in thousands):

	December 31,
	2011		2010
Cash	$	304	$	754
Accounts receivable		9		434
Inventory		1,017		1,077
Other current assets		2,683		3,653
Total current assets associated with discontinued operations		4,013		5,918
Property, plant and equipment, net		—		502
Other long-term assets		—		8,670
Total assets associated with discontinued operations	$	4,013	$	15,090
Accounts payable	$	589	$	801
Accrued liabilities		4,295		13,932
Deferred revenues		1,499		821
Total current liabilities associated with discontinued operations		6,383		15,554
Other long-term liabilities		14,140		13,111
Total liabilities associated with discontinued operations	$	20,523	$	28,665

3. Inventory

Inventory, net of reserves, consisted of the following amounts (in thousands):

	December 31,
	2011		2010
Parts and supplies	$	225,804	$	244,618
Work in progress		103,414		116,371
Finished goods		32,467		35,298
Inventory, net of reserves	$	361,685	$	396,287

During 2011, 2010 and 2009, we recorded $4.9 million, $2.2 million and $5.3 million, respectively, in inventory write-downs and reserves for inventory, which were either obsolete, excess or carried at a price above market value. As of December 31, 2011 and 2010, we had inventory reserves of $16.8 million and $18.3 million, respectively.

4. Fabrication Contracts

Costs, estimated earnings and billings on uncompleted contracts consisted of the following (in thousands):

	December 31,
	2011			2010
Costs incurred on uncompleted contracts	$	895,337		$	1,318,971
Estimated earnings		157,893			277,768
		1,053,230			1,596,739
Less — billings to date		(1,014,977	)		(1,579,448	)
	$	38,253		$	17,291

F-14

Costs, estimated earnings and billings on uncompleted contracts are presented in the accompanying financial statements as follows (in thousands):

	December 31,
	2011			2010
Costs and estimated earnings in excess of billings on uncompleted contracts	$	122,214		$	147,901
Billings on uncompleted contracts in excess of costs and estimated earnings		(83,961	)		(130,610	)
	$	38,253		$	17,291

5. Property, Plant and Equipment

Property, plant and equipment consisted of the following (in thousands):

	December 31,
	2011			2010
Compression equipment, facilities and other fleet assets	$	4,309,386		$	4,302,483
Land and buildings		176,782			166,273
Transportation and shop equipment		244,226			225,073
Other		151,939			142,770
		4,882,333			4,836,599
Accumulated depreciation		(1,877,881	)		(1,743,947	)
Property, plant and equipment, net	$	3,004,452		$	3,092,652

Depreciation expense was $341.3 million, $373.3 million and $322.3 million in 2011, 2010 and 2009, respectively. Assets under construction of $143.1 million and $134.6 million are primarily included in compression equipment, facilities and other fleet assets at December 31, 2011 and 2010, respectively. We capitalized $1.5 million, $1.7 million and $4.1 million of interest related to construction in process during 2011, 2010 and 2009, respectively.

6. Intangible and Other Assets

Intangible and other assets consisted of the following (in thousands):

	December 31,
	2011		2010
Deferred debt issuance costs, net	$	24,581	$	24,735
Intangible assets, net		137,984		161,618
Deferred taxes		27,789		59,585
Other		41,929		36,490
Intangibles and other assets, net	$	232,283	$	282,428

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Intangible assets and deferred debt issuance costs consisted of the following (in thousands):

	December 31, 2011					December 31, 2010
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Deferred debt issuance costs	$	44,141	$	(19,560	)	$	39,367	$	(14,632	)
Marketing related (5-20 year life)		3,043		(1,400	)		2,727		(1,211	)
Customer- related (10-20 year life)		175,676		(76,943	)		175,798		(60,511	)
Technology based (20 year life)		32,275		(6,747	)		32,361		(5,035	)
Contract based (2-11 year life)		65,222		(53,142	)		64,924		(47,435	)
Intangible assets and deferred debt issuance costs	$	320,357	$	(157,792	)	$	315,177	$	(128,824	)

Amortization of deferred debt issuance costs totaled $8.9 million, $5.3 million and $3.9 million in 2011, 2010 and 2009, respectively, and is recorded to interest expense in our consolidated statements of operations. Amortization of intangible costs totaled $24.6 million, $28.2 million and $30.5 million in 2011, 2010 and 2009, respectively.

Estimated future intangible amortization expense is as follows (in thousands):

2012	$	21,466
2013		17,876
2014		15,055
2015		13,196
2016		11,683
Thereafter		58,708
	$	137,984

7. Investments in Non-Consolidated Affiliates

Investments in affiliates that are not controlled by Exterran but where we have the ability to exercise significant influence over the operations are accounted for using the equity method. Our equity method investments are primarily comprised of entities that own, operate, service and maintain compression and other related facilities.

Our ownership interest and location of each equity method investee at December 31, 2011 are as follows:

	Ownership Interest			Location	Type of Business
PIGAP II		30.0	%	Venezuela	Gas Compression Plant
El Furrial		33.3	%	Venezuela	Gas Compression Plant

We also had a 35.5% ownership interest in each of the SIMCO Consortium and Harwat that we sold in November 2009. The SIMCO Consortium and Harwat operate a water injection plant in Venezuela. The summarized financial information in the table below includes the investees listed above as well as the SIMCO Consortium and Harwat through their disposition date in November 2009.

F-16

Summarized balance sheet information for investees accounted for by the equity method is as follows (on a 100% basis, in thousands):

	December 31,
	2011			2010
Current assets	$	928		$	1,200
Non-current assets		23,700			24,421
Current liabilities, including current debt		71,512			101,463
Long-term debt payable		873			1,203
Other non-current liabilities		29,055			29,665
Owners’ deficit		(76,812	)		(106,710	)

Summarized combined earnings information for these entities consisted of the following amounts (on a 100% basis, in thousands):

	Years Ended December 31,
	2011		2010		2009
Revenues	$	—	$	—	$	8,381
Operating income (loss)		31,651		41,582		(400,727	)
Net income (loss)		28,269		43,013		(343,680	)

Due to unresolved disputes with its only customer, PDVSA, SIMCO sent a notice to PDVSA in the fourth quarter of 2008 stating that SIMCO might not be able to continue to fund its operations if some of its outstanding disputes were not resolved and paid in the near future. On February 25, 2009, the Venezuelan National Guard occupied SIMCO’s facilities and during March 2009 transitioned the operation of SIMCO, including the hiring of SIMCO’s employees, to PDVSA.

During the first quarter of 2009, we determined that the expected proceeds from our investment in the SIMCO Consortium and Harwat would be less than the book value of our investment and, as a result, that the fair value of our investment had declined and the loss in value was not temporary. Therefore, we recorded an impairment charge in the first quarter of 2009 of $6.5 million, which is reflected as a charge in equity in loss of non-consolidated affiliates in our consolidated statements of operations.

Due to lack of payments from their only customer, PDVSA, PIGAP II and El Furrial each sent a notice of default to PDVSA in April 2009. PIGAP II’s and El Furrial’s debt was in technical default triggered by past due payments from their sole customer under their related services contracts. As a result of PDVSA’s nonpayment, in March 2009 these joint ventures recorded impairments on their assets. Accordingly, we reviewed our expected cash flows related to these two joint ventures and determined in March 2009 that the fair value of our investment in PIGAP II and El Furrial had declined and that we had a loss in our investment that was not temporary. Therefore, we recorded an impairment charge of $90.1 million ($81.7 million net of tax) to write-off our investments in PIGAP II and El Furrial. These impairment charges are reflected as a charge in equity in loss of non-consolidated affiliates in our consolidated statements of operations. In May 2009, PDVSA assumed control over the assets of PIGAP II and El Furrial and transitioned the operations of PIGAP II and El Furrial, including the hiring of their employees, to PDVSA. Our non-consolidated affiliates reserve and will continue to reserve the right to seek full compensation for any and all expropriated assets and investments under all applicable legal regimes, including investment treaties and customary international law, as well as to seek resolution through direct discussions with Venezuela and/or PDVSA, 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. In this connection, on March 25, 2011, Wilpro Energy Services (El Furrial) Limited and Wilpro Energy Services (PIGAP II) Limited, together with the Netherland’s parent company of our venture partners, filed a request for the institution of an arbitration proceeding against Venezuela with ICSID related to the seized assets and investments, which was registered by ICSID on April 20, 2011.

F-17

Because the assets and operations of our investments in our remaining non-consolidated affiliates have been expropriated, we currently do not expect to have any meaningful equity earnings in non-consolidated affiliates in the future from these investments, excluding any compensation we may receive related to the expropriation.

We did not receive dividends from our joint ventures in the years ended December 31, 2011, 2010 and 2009.

8. Goodwill

Goodwill acquired in connection with business combinations represents the excess of consideration over the fair value of tangible and identifiable intangible net assets acquired. Certain assumptions and estimates are employed in determining the fair value of assets acquired and liabilities assumed, as well as in determining the allocation of goodwill to the appropriate reporting units.

We perform our goodwill impairment test every year, or whenever events indicate impairment may have occurred, to determine if the estimated recoverable value of each of our reporting units exceeds the net carrying value of the reporting unit, including the applicable goodwill.

The first step in performing a goodwill impairment test is to compare the estimated fair value of each reporting unit with its recorded net book value (including the goodwill). If the estimated fair value of the reporting unit is higher than the recorded net book value, no impairment is deemed to exist and no further testing is required. If, however, the estimated fair value of the reporting unit is below the recorded net book value, then a second step must be performed to determine the goodwill impairment required, if any. In this second step, the estimated fair value from the first step is used as the purchase price in a hypothetical acquisition of the reporting unit. Business combination accounting rules are followed to determine a hypothetical purchase price allocation to the reporting unit’s assets and liabilities. The residual amount of goodwill that results from this hypothetical purchase price allocation is compared to the recorded amount of goodwill for the reporting unit, and the recorded amount is written down to the hypothetical amount, if lower.

Because quoted market prices for our reporting units are not available, management must apply judgment in determining the estimated fair value of these reporting units for purposes of performing the annual goodwill impairment test. Management uses all available information to make these fair value determinations, including the present values of expected future cash flows using discount rates commensurate with the risks involved in the assets.

We determine the fair value of our reporting units using both the expected present value of future cash flows and a market approach. The present value of future cash flows is estimated using our most recent forecast and the weighted average cost of capital of each reporting unit. The market approach uses a market multiple on the reporting units’ earnings before interest, tax, depreciation and amortization.

As discussed in Note 2, on June 2, 2009, PDVSA commenced taking possession of our assets and operations in Venezuela. As of 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 step one of 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. The $32.6 million of goodwill related to our Venezuela contract operations and aftermarket services businesses was also written off in the second quarter of 2009 as part of our loss from discontinued operations. The decrease in value of our international contract operations reporting unit was primarily caused by the loss of our operations in Venezuela.

F-18

As a result of the level of decline in our stock price and corresponding market capitalization in the third quarter of 2011, we performed a goodwill impairment test of our aftermarket services and fabrication reporting units’ goodwill as of September 30, 2011. We determined the fair value of these reporting units using the expected present value of future cash flows. This decline in our market capitalization led us to increase the estimate of the market’s implied weighted average cost of capital and reduce the present value of the forecasted cash flows. The test indicated that our aftermarket services and fabrication reporting units’ goodwill was impaired and therefore we recorded a full impairment of the goodwill associated with these reporting units in the third quarter of 2011.

The table below presents the change in the net carrying amount of goodwill for the years ended December 31, 2011 and 2010 (in thousands):

	North  America contract operations			International contract operations			Aftermarket services			Fabrication			Total
Balance as of December 31, 2009:
Goodwill	$	1,148,371		$	150,778		$	62,471		$	220,262		$	1,581,882
Accumulated impairment losses		(1,148,371	)		(150,778	)		—			(87,569	)		(1,386,718	)
		—			—			62,471			132,693			195,164
Impact of foreign currency Translation		—			—			624			892			1,516
Balance as of December 31, 2010:
Goodwill		1,148,371			150,778			63,095			221,154			1,583,398
Accumulated impairment losses		(1,148,371	)		(150,778	)		—			(87,569	)		(1,386,718	)
		—			—			63,095			133,585			196,680
Goodwill acquired during year		—			—			447			218			665
Impairment losses		—			—			(63,299	)		(133,508	)		(196,807	)
Impact of foreign currency translation		—			—			(243	)		(295	)		(538	)
Balance as of December 31, 2011:
Goodwill		1,148,371			150,778			63,299			221,077			1,583,525
Accumulated impairment losses		(1,148,371	)		(150,778	)		(63,299	)		(221,077	)		(1,583,525	)
	$	—		$	—		$	—		$	—		$	—

9. Accrued Liabilities

Accrued liabilities consisted of the following (in thousands):

	December 31,
	2011		2010
Accrued salaries and other benefits	$	70,065	$	63,706
Accrued income and other taxes		109,276		143,625
Accrued warranty expense		3,879		7,703
Accrued interest		8,366		9,163
Interest rate swaps fair value		14,250		24,432
Deferred income taxes		3,543		10,241
Accrued start-up and commissioning expenses		14,597		11,027
Accrued other liabilities		55,078		60,654
Accrued liabilities	$	279,054	$	330,551

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10. Long-Term Debt

Long-term debt consisted of the following (in thousands):

	December 31,
	2011		2010
Revolving credit facility due July 2016	$	433,500	$	—
Revolving credit facility due August 2012		—		50,395
Term loan		—		615,943
2007 asset-backed securitization facility notes due July 2012		—		6,000
Partnership’s revolving credit facility due November 2015		395,500		299,000
Partnership’s term loan facility due November 2015		150,000		150,000
4.25% convertible senior notes due June 2014 (presented net of the unamortized discount of $54.9 million and $73.2 million, respectively)		300,149		281,827
4.75% convertible senior notes due January 2014		143,750		143,750
7.25% senior notes due December 2018		350,000		350,000
Other, interest at various rates, collateralized by equipment and other assets		140		232
Long-term debt	$	1,773,039	$	1,897,147

Exterran Senior Secured Credit Facility

In July 2011, we entered into a credit agreement providing for a new five-year, $1.1 billion senior secured revolving credit facility (the “2011 Credit Facility”), which matures in July 2016 and replaced our former senior secured credit facility. We incurred approximately $7.8 million in transaction costs related to the 2011 Credit Facility. These costs are included in Intangible and other assets, net and amortized over the facility term. As a result of the termination of our former senior secured credit facility, we expensed approximately $1.6 million of unamortized deferred financing costs associated with our former senior secured credit facility in the third quarter of 2011, which is reflected in Interest expense in our consolidated statements of operations.

Concurrently with the execution of the new credit agreement, we borrowed $387.3 million under the 2011 Credit Facility and used the proceeds to (i) repay the entire amount outstanding under our former senior secured credit facility and terminate that facility and (ii) pay customary fees and other expenses relating to the 2011 Credit Facility. Borrowings under the 2011 Credit Facility bear interest at a base rate or LIBOR, at our option, plus an applicable margin. Depending on our Total Leverage Ratio (as defined in the credit agreement), the applicable margin for revolving loans varies (i) in the case of LIBOR loans, from 1.50% to 2.50% and (ii) in the case of base rate loans, from 0.50% to 1.50%. The base rate is the highest of the prime rate announced by Wells Fargo Bank, National Association, the Federal Funds Rate plus 0.5% and one-month LIBOR plus 1.0%. At December 31, 2011, all amounts outstanding under the 2011 Credit Facility were LIBOR loans and the applicable margin was 2.25%. The weighted average annual interest rate at December 31, 2011 on the outstanding balance under the 2011 Credit Facility, excluding the effect of interest rate swaps, was 2.6%.

As of December 31, 2011, we had $433.5 million in outstanding borrowings and $216.6 million in letters of credit outstanding under the 2011 Credit Facility. At December 31, 2011, taking into account guarantees through letters of credit, bid bonds and performance bonds, we had undrawn capacity of $449.9 million under the 2011 Credit Facility. Our senior secured credit agreement limits our Total Debt (as defined in the credit agreement) to Adjusted EBITDA ratio of not greater than 5.0 to 1.0. Due to this limitation, $190.3 million of the $449.9 million of undrawn capacity under the 2011 Credit Facility was available for additional borrowings as of December 31, 2011.

Our Significant Domestic Subsidiaries (as defined in the credit agreement) guarantee the debt under the 2011 Credit Facility. Borrowings under the 2011 Credit Facility are secured by substantially all of the personal

F-20

property assets and certain real property assets of us and our Significant Domestic Subsidiaries, including all of the equity interests of our U.S. subsidiaries (other than certain excluded subsidiaries) and 65% of the equity interests in certain of our first-tier foreign subsidiaries. The Partnership does not guarantee the debt under the 2011 Credit Facility, its assets are not collateral under the 2011 Credit Facility and the general partner units in the Partnership are not pledged under the 2011 Credit Facility. Subject to certain conditions, at our request, and with the approval of the lenders, the aggregate commitments under the 2011 Credit Facility may be increased by up to an additional $300 million.

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 are also subject to financial covenants, including a ratio of Adjusted EBITDA (as defined in the credit agreement) to Total Interest Expense (as defined in the credit agreement) of not less than 2.25 to 1.0, a ratio of consolidated Total Debt to Adjusted EBITDA of not greater than 5.0 to 1.0 and a ratio of Senior Secured Debt (as defined in the credit agreement) to Adjusted EBITDA of not greater than 4.0 to 1.0.

Exterran Asset-Backed Securitization Facility

In March 2011, we repaid the $6.0 million outstanding balance under our asset-backed securitization facility and terminated that facility. As a result of this termination, we expensed $1.4 million of unamortized deferred financing costs, which is reflected in Interest expense in our consolidated statements of operations for the year ended December 31, 2011.

The Partnership Revolving Credit Facility and Term Loan

In November 2010, the Partnership, as guarantor, and EXLP Operating LLC, a wholly-owned subsidiary of the Partnership, as borrower, entered into an amendment and restatement of their senior secured credit agreement (the “Partnership Credit Agreement”) to provide for a new five-year, $550.0 million senior secured credit facility consisting of a $400.0 million revolving credit facility and a $150.0 million term loan facility. In March 2011, the revolving borrowing capacity under this facility was increased by $150.0 million to $550.0 million. Concurrent with the execution of the Partnership Credit Agreement in November 2010, the Partnership borrowed $304.0 million under its revolving credit facility and $150.0 million under its term loan facility and used the proceeds to (i) repay the entire $406.1 million outstanding under the Partnership’s previous senior secured credit facility, (ii) repay the entire $30.0 million outstanding under the Partnership’s asset-backed securitization facility and terminate that facility, (iii) pay $14.8 million to terminate the interest rate swap agreements to which the Partnership was a party and (iv) pay customary fees and other expenses relating to the Partnership Credit Agreement. The Partnership incurred transaction costs of approximately $4.0 million related to the Partnership Credit Agreement. These costs were included in Intangible and other assets, net and are being amortized over the respective facility terms. As a result of the amendment and restatement of the Partnership Credit Agreement, we expensed $0.2 million of unamortized deferred financing costs associated with the refinanced debt, which is reflected in Interest expense in our consolidated statement of operations.

As of December 31, 2011, there was $395.5 million in outstanding borrowings under the Partnership’s revolving credit facility and $154.5 million was available for additional borrowings.

The Partnership’s revolving credit facility bears interest at a base rate or LIBOR, at the Partnership’s option, plus an applicable margin. Depending on the Partnership’s leverage ratio, the applicable margin for revolving loans varies (i) in the case of LIBOR loans, from 2.25% to 3.25% and (ii) in the case of base rate loans, from 1.25% to 2.25%. The base rate is the highest of the prime rate announced by Wells Fargo Bank, National Association, the Federal Funds Effective Rate plus 0.5% and one-month LIBOR plus 1.0%. At December 31, 2011, all amounts outstanding under this facility were LIBOR loans and the applicable margin was 2.5%. The weighted average annual interest rate on the outstanding balance of this facility at December 31, 2011, excluding the effect of interest rate swaps, was 2.8%.

F-21

The Partnership’s term loan facility bears interest at a base rate or LIBOR, at the Partnership’s option, plus an applicable margin. Depending on the Partnership’s leverage ratio, the applicable margin for term loans varies (i) in the case of LIBOR loans, from 2.5% to 3.5% and (ii) in the case of base rate loans, from 1.5% to 2.5%. At December 31, 2011, all amounts outstanding under the term loan were LIBOR loans and the applicable margin was 2.75%. The average annual interest rate on the outstanding balance of the term loan at December 31, 2011was 3.1%.

Borrowings under the Partnership Credit Agreement are secured by substantially all of the U.S. personal property assets of the Partnership and its Significant Domestic Subsidiaries (as defined in the Partnership Credit Agreement), including all of the membership interests of the Partnership’s Domestic Subsidiaries (as defined in the Partnership Credit Agreement).

The Partnership Credit Agreement 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. It also contains various covenants requiring mandatory prepayments of the term loans from the net cash proceeds of certain future asset transfers and debt issuances. 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 such an acquisition closes. The Partnership completed an acquisition from us meeting these thresholds in the second quarter of 2011; therefore, the Partnership’s Total Debt to EBITDA ratio was temporarily increased from 4.75 to 1.0 to 5.25 to 1.0 through December 31, 2011, reverting to 4.75 to 1.0 for the quarter ending March 31, 2012 and subsequent quarters. As of December 31, 2011, the Partnership maintained a 7.3 to 1.0 EBITDA to Total Interest Expense ratio and a 3.7 to 1.0 Total Debt to EBITDA ratio. A violation of the Partnership’s Total Debt to EBITDA covenant would be an event of default under the Partnership Credit Agreement, which would trigger cross-default provisions under certain of our debt agreements. As of December 31, 2011, the Partnership was in compliance with all financial covenants under the Partnership Credit Agreement.

7.25% Senior Notes

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 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

F-22

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.

4.25% Convertible Senior Notes

In June 2009, we issued $355.0 million aggregate principal amount of 4.25% convertible senior notes due June 2014 (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. The value of the shares the 4.25% Notes can be converted into did not exceed their principal amount as of December 31, 2011. We may not redeem the 4.25% Notes prior to their maturity date.

GAAP requires that the liability and equity components of certain convertible debt instruments that may be settled in cash upon conversion be separately accounted for in a manner that reflects an issuer’s nonconvertible debt borrowing rate. Upon issuance of our 4.25% Notes, $97.9 million was recorded as a debt discount and reflected in equity related to the convertible feature of these notes. The discount on the 4.25% Notes will be amortized using the effective interest method through June 30, 2014. During each of the years ended December 31, 2011, 2010 and 2009, we recognized $15.1 million, $15.1 million and $8.4 million, respectively, of interest expense related to the contractual interest coupon. During the years ended December 31, 2011, 2010 and 2009, we recognized $18.3 million, $16.4 million and $8.3 million, respectively, of interest expense related to the amortization of the debt discount. The effective interest rate on the debt component of these notes is 11.67%.

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

In connection with the offering of the 4.25% Notes, we purchased call options on our stock at approximately $23.15 per share of common stock and sold warrants on our stock at approximately $32.67 per share of common stock. These transactions economically adjust the effective conversion price to $32.67 for $325.0 million of the 4.25% Notes and therefore are expected to reduce the potential dilution to our common stock upon any such conversion.

4.75% Convertible Senior Notes

In December 2003, Hanover issued $143.75 million aggregate principal amount of 4.75% Convertible Senior Notes due January 15, 2014 (the “4.75% Notes”). In connection with the merger in August 2007, we executed supplemental indentures between Hanover and the trustees, pursuant to which we agreed to fully and unconditionally guarantee the obligations of Hanover relating to the 4.75% Notes. Hanover, renamed Exterran Energy Corp., the issuer of the 4.75% Notes, is our wholly-owned subsidiary. There are no significant restrictions on our ability to obtain funds from Exterran Energy Corp. by dividend or loan.

The 4.75% Notes are our general unsecured obligations and rank equally in right of payment with all of our other senior debt. The 4.75% Notes are effectively subordinated to all existing and future liabilities of our subsidiaries.

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The 4.75% Notes are convertible into a whole number of shares of our common stock and cash in lieu of fractional shares. The 4.75% Notes are convertible at the option of the holder into shares of our common stock at a conversion rate of 21.6667 shares of common stock per $1,000 principal amount of convertible senior notes, which is equivalent to a conversion price of approximately $46.15 per share.

At any time on or after January 15, 2011 but prior to January 15, 2013, we may redeem some or all of the 4.75% Notes at a redemption price equal to 100% of the principal amount of the 4.75% Notes plus accrued and unpaid interest, if any, if the price of our common stock exceeds 135% of the conversion price of the convertible senior notes then in effect for 20 trading days out of a period of 30 consecutive trading days. At any time on or after January 15, 2013, we may redeem some or all of the 4.75% Notes at a redemption price equal to 100% of the principal amount of the 4.75% Notes plus accrued and unpaid interest, if any. Holders have the right to require us to repurchase the 4.75% Notes upon a specified change in control, at a repurchase price equal to 100% of the principal amount of 4.75% Notes plus accrued and unpaid interest, if any.

Debt Compliance

We were in compliance with our debt covenants as of December 31, 2011. If we fail to remain in compliance with our financial covenants we would be in default under our credit agreements. In addition, if we experienced 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 credit agreements, this could lead to a default under our credit agreements. A default under one or more of our debt agreements, including a default by the Partnership under its credit facility, would trigger cross-default provisions under certain of our debt agreements, which would accelerate our obligation to repay our indebtedness under those agreements.

Long-term Debt Maturity Schedule

Contractual maturities of long-term debt (excluding interest to be accrued thereon) at December 31, 2011 are as follows (in thousands):

	December 31, 2011
2012	$	140	(1)
2013		—
2014		498,750	(2)
2015		545,500
2016		433,500
Thereafter		350,000
Total debt	$	1,827,890

(1) Maturities of $0.1 million due in 2012 are classified as long-term because we have the intent and ability to refinance these maturities with our existing long-term credit facilities.

(2) This amount includes the full face value of the 4.25% Notes and is not reduced by the unamortized discount of $54.9 million as of December 31, 2011.

11. Accounting for Derivatives

We are exposed to market risks primarily associated with changes in interest rates and foreign currency exchange rates. We use derivative financial instruments to minimize the risks and/or costs associated with financial activities by managing our exposure to interest rate fluctuations on a portion of our debt obligations. We also use derivative financial instruments to minimize the risks caused by currency fluctuations in certain foreign currencies. We do not use derivative financial instruments for trading or other speculative purposes.

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Interest Rate Risk

At December 31, 2011, we were a party to interest rate swaps pursuant to which we pay fixed payments and receive floating payments on a notional value of $715.0 million. We entered into these swaps to offset changes in expected cash flows due to fluctuations in the associated variable interest rates. Our interest rate swaps expire over varying dates, with interest rate swaps having a notional amount of $465.0 million expiring on or before August 2012 and the remaining interest rate swaps expiring through November 2015. As of December 31, 2011, the weighted average effective fixed interest rate on our interest rate swaps was 3.6%. We have designated these interest rate swaps as cash flow hedging instruments so that any change in their fair values is recognized as a component of comprehensive income (loss) and is included in accumulated other comprehensive income (loss) to the extent the hedge is effective. The swap terms substantially coincide with the hedged item and are expected to offset changes in expected cash flows due to fluctuations in the variable rate, and therefore we currently do not expect a significant amount of ineffectiveness on these hedges. We perform quarterly calculations to determine whether the swap agreements are still effective and to calculate any ineffectiveness. We recorded no ineffectiveness for the year ended December 31, 2011. We recorded approximately $0.2 million of interest expense for the year ended December 31, 2010, due to the ineffectiveness related to interest rate swaps. We estimate that approximately $14.3 million of deferred pre-tax losses attributable to existing interest rate swaps and included in our accumulated other comprehensive loss at December 31, 2011, will be reclassified into earnings as interest expense at then-current values during the next twelve months as the underlying hedged transactions occur. Cash flows from derivatives designated as hedges are classified in our consolidated statements of cash flows under the same category as the cash flows from the underlying assets, liabilities or anticipated transactions.

In the fourth quarter of 2010, we paid $43.0 million to terminate interest rate swap agreements with a total notional value of $585.0 million and a weighted average effective fixed interest rate of 4.6%. These swaps qualified for hedge accounting and were previously included on our balance sheet as a liability and in accumulated other comprehensive income (loss). The liability was paid in connection with the termination, and the associated amount in accumulated other comprehensive income (loss) will be amortized into interest expense over the original term of the swaps. We estimate that $10.7 million of deferred pre-tax losses from these terminated interest rate swaps will be amortized into interest expense during the next twelve months.

Foreign Currency Exchange Risk

We operate in approximately 30 countries throughout the world, and a fluctuation in the value of the currencies of these countries relative to the U.S. dollar could impact our profits from international operations and the value of the net assets of our international operations when reported in U.S. dollars in our financial statements. From time to time we may enter into foreign currency hedges to reduce our foreign exchange risk associated with cash flows we will receive in a currency other than the functional currency of the local Exterran affiliate that entered into the contract. The impact of foreign currency exchange on our consolidated statements of operations will depend on the amount of our net asset and liability positions exposed to currency fluctuations in future periods.

Foreign currency swaps or forward contracts that meet the hedging requirements or that qualify for hedge accounting treatment are accounted for as cash flow hedges and changes in the fair value are recognized as a component of comprehensive income (loss) to the extent the hedge is effective. The amounts recognized as a component of other comprehensive income (loss) will be reclassified into earnings (loss) in the periods in which the underlying foreign currency exchange transaction is recognized and are included under the same category as the income or loss from the underlying assets, liabilities, or anticipated transactions in our consolidated statements of operations. For foreign currency swaps and forward contracts that do not qualify for hedge accounting treatment, changes in fair value and gains and losses on settlement are included under the same category as the income or loss from the underlying assets, liabilities or anticipated transactions in our consolidated statements of operations.

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The following tables present the effect of derivative instruments on our consolidated financial position and results of operations (in thousands):

	December 31, 2011
	Balance Sheet Location	Fair Value Asset (Liability)
Derivatives designated as hedging instruments:
Interest rate hedges	Accrued liabilities	$	(14,250	)
Interest rate hedges	Other long-term liabilities		(5,196	)
Total derivatives		$	(19,446	)
	December 31, 2010
	Balance Sheet Location	Fair Value Asset (Liability)
Derivatives designated as hedging instruments:
Interest rate hedges	Intangibles and other assets	$	5,769
Interest rate hedges	Accrued liabilities		(24,432	)
Interest rate hedges	Other long-term liabilities		(10,362	)
Foreign currency hedge	Accrued liabilities		(462	)
Total derivatives		$	(29,487	)

	Year Ended December 31, 2011
	Gain (Loss) Recognized in  Other Comprehensive Income (Loss) on Derivatives			Location of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Income (Loss)	Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Income (Loss)
Derivatives designated as cash flow hedges:
Interest rate hedges	$	(29,178	)	Interest expense	$	(47,729	)
Foreign currency hedge		—		Fabrication revenue		410
Total	$	(29,178	)		$	(47,319	)
	Year Ended December 31, 2010
	Gain (Loss) Recognized in Other Comprehensive Income (Loss) on Derivatives			Location of Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Income (Loss)	Gain (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) into Income (Loss)
Derivatives designated as cash flow hedges:
Interest rate hedges	$	(44,558	)	Interest expense	$	(55,771	)
Foreign currency hedge		(3,880	)	Fabrication revenue		(3,470	)
Total	$	(48,438	)		$	(59,241	)

The counterparties to our derivative agreements are major international financial institutions. We monitor the credit quality of these financial institutions and do not expect non-performance by any counterparty, although such non-performance could have a material adverse effect on us. We have no specific collateral posted for our derivative instruments. The counterparties to our interest rate swaps are also lenders under our credit facilities and, in that capacity, share proportionally in the collateral pledged under the related facility.

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12. Fair Value Measurements

The accounting standard for fair value measurements and disclosures establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into the following three broad categories.

• Level 1 — Quoted unadjusted prices for identical instruments in active markets to which we have access at the date of measurement.

• Level 2 — Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets. Level 2 inputs are those in markets for which there are few transactions, the prices are not current, little public information exists or prices vary substantially over time or among brokered market makers.

• Level 3 — Model derived valuations in which one or more significant inputs or significant value drivers are unobservable. Unobservable inputs are those inputs that reflect our own assumptions regarding how market participants would price the asset or liability based on the best available information.

The following table summarizes the valuation of our interest rate swaps, foreign currency derivatives and impaired assets as of and for the year ended December 31, 2011 with pricing levels as of the date of valuation (in thousands):

	Total			Quoted Market Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Interest rate swaps asset (liability)	$	(19,446	)	$	—	$	(19,446	)	$	—
Impaired long-lived assets		1,642			—		—			1,642
Aftermarket services goodwill		—			—		—			—
Fabrication goodwill		—			—		—			—

The following table summarizes the valuation of our interest rate swaps, foreign currency derivatives and impaired assets as of and for the year ended December 31, 2010 with pricing levels as of the date of valuation (in thousands):

	Total			Quoted Market Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Interest rate swaps asset (liability)	$	(29,025	)	$	—	$	(29,025	)	$	—
Foreign currency derivatives asset (liability)		(462	)		—		(462	)		—
Impaired long-lived assets		70,637			—		—			70,637

On a quarterly basis, our interest rate swaps and foreign currency derivatives are recorded at fair value utilizing a combination of the market and income approach to estimate fair value. Our estimate of the fair value of the impaired long-lived assets was 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 or the estimated component value of the equipment that we plan to use. See Note 8 for a discussion of the valuation methodology we used in connection with the goodwill impairments.

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13. Long-Lived Asset Impairment

During 2011, we reviewed the idle compression assets used in our contract operations segments for units that were 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 these units to determine the fair value of the assets. The net book value of these assets exceeded the fair value by $6.6 million for the year ended December 31, 2011, and was recorded as a long-lived asset impairment. In addition, in the fourth quarter of 2011, we recorded a $0.4 million impairment of non-fleet long-lived assets.

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, 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 had recently sold, as well as our review of other units that were recently for sale by third parties.

This decision was 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 determined that 323 units representing 61,400 horsepower would be retired from the fleet in 2010 and 1,232 units representing 264,900 horsepower would be retired from the fleet in 2009. We performed a cash flow analysis of the expected proceeds from the salvage value of these units to determine the fair value of the assets. The net book value of these assets exceeded the fair value by $7.6 million and $91.0 million for the years ended December 31, 2010 and 2009, respectively, and 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.

In the first quarter of 2009, our management approved a plan to close certain fabrication facilities and consolidate our compression fabrication activities. As a result, we reviewed the facilities to be closed for impairment and the net book value of these facilities exceeded the fair value by $6.0 million and was recorded as a long-lived asset impairment.

Prior to 2010, we were involved in a project in the Cawthorne Channel in Nigeria (the “Cawthorne Channel Project”), to process natural gas from certain Nigerian oil and natural gas fields. The Cawthorne Channel Project only operated for limited periods of time beginning in June 2006. In 2008 as a result of operational difficulties and taking into consideration the project’s historical performance and declines in commodity prices, we undertook an assessment of our estimated future cash flows from the Cawthorne Channel Project. Based on the analysis we completed, we determined that we would not recover all of our remaining investment in the Cawthorne Channel Project. Accordingly, we recorded an impairment charge of $21.6 million in our 2008 results to reduce the carrying amount of our assets associated with the Cawthorne Channel Project to their estimated fair value. In November 2009, we sold our investment in the subsidiary that owns the barge mounted processing plant and other related assets used on the Cawthorne Channel Project for $37.0 million. This sale resulted in a pre-tax gain of approximately $20.8 million which is reflected in Other (income) expense, net in our consolidated statements of operations. The assets associated with our investment in the Cawthorne Channel Project were part of our international contract operations segment.

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14. Restructuring Charges

In November 2011, we announced a workforce cost reduction program across all of our business segments as a first step in a broader overall profit improvement initiative. These actions were the result of a review of our cost structure aimed at identifying ways to reduce our on-going operating costs and to adjust the size of our workforce to be consistent with current and expected activity levels. A significant portion of the workforce cost reduction program was completed in 2011, with the remainder expected to be completed in 2012.

During the year ended December 31, 2011, we incurred $11.6 million of restructuring charges that were related to consulting services and termination benefits. These charges are reflected as Restructuring charges in our consolidated statements of operations. We currently estimate that we will incur additional charges with respect to the profit improvement initiative of approximately $3.1 million. We expect all of the estimated additional charges will result in cash expenditures.

The following table summarizes the changes to our accrued liability balance related to restructuring charges for year ended December 31, 2011 (in thousands):

	Restructuring Charges  Accrual
Beginning balance at December 31, 2010	$	—
Additions for costs expensed		11,627
Less non-cash expenses		(1,575	)
Reductions for payments		(8,276	)
Ending balance at December 31, 2011	$	1,776

Restructuring charges by segment are as follows (in thousands):

	North  America Contract Operations		International Contract Operations		Aftermarket Services		Fabrication		Other(1)		Total
Costs incurred in 2011	$	53	$	502	$	422	$	1,574	$	9,076	$	11,627
Total expected costs		53		867		482		2,424		10,945		14,771

(1) Includes corporate related items

As a result of the reduced level of demand for our products and services, our management approved a plan in March 2009 to close certain facilities to consolidate our compression fabrication activities. These actions were the result of significant fabrication capacity stemming from the 2007 merger that created Exterran and the lack of consolidation of this capacity since that time, as well as the anticipated continuation of weaker global economic and energy industry conditions. The consolidation of those compression fabrication activities was completed in September 2009. The restructuring activities in 2009 included a $6.0 million facility impairment charge that was reflected in our consolidated statement of operations as a long-lived asset impairment (see Note 13). Additionally, we reduced the size of our workforce at our two manufacturing locations in Houston, Texas to support the forecasted level of new fabrication work.

We incurred charges in 2009 with respect to these restructuring charges discussed above of $14.3 million. These charges are reflected as Restructuring charges in our consolidated statements of operations. Approximately $13.4 million of the charges are severance and employee benefit costs and the remaining amount is for other facility closure and moving costs. All of the $14.3 million of charges resulted in cash expenditures.

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15. Income Taxes

The components of loss before income taxes were as follows (in thousands):

	Years Ended December 31,
	2011			2010			2009
United States	$	(268,492	)	$	(238,776	)	$	(4,385	)
Foreign		(78,628	)		13,606			(193,172	)
Loss before income taxes	$	(347,120	)	$	(225,170	)	$	(197,557	)

The provision for (benefit from) income taxes consisted of the following (in thousands):

	Years Ended December 31,
	2011			2010			2009
Current tax provision (benefit):
U.S. federal	$	4,029		$	1,691		$	(2,906	)
State		6,552			3,157			2,296
Foreign		27,309			56,623			58,842
Total current		37,890			61,471			58,232
Deferred tax provision (benefit):
U.S. federal		(71,857	)		(83,752	)		903
State		(7,874	)		(10,110	)		(4,193	)
Foreign		28,376			(34,215	)		(3,275	)
Total deferred		(51,355	)		(128,077	)		(6,565	)
Provision for (benefit from) income taxes	$	(13,465	)	$	(66,606	)	$	51,667

The provision for (benefit from) income taxes for 2011, 2010 and 2009 resulted in effective tax rates on continuing operations of 3.9%, 29.6% and (26.2)%, respectively. The reasons for the differences between these effective tax rates and the U.S. statutory rate of 35% are as follows (in thousands):

	Years Ended December 31,
	2011			2010			2009
Income taxes at U.S. federal statutory rate of 35%	$	(121,492	)	$	(78,809	)		$ (69,145	)
Net state income taxes		(538	)		(3,765	)		(1,249	)
Foreign taxes		4,676			21,096			34,879
Noncontrolling interest		(1,103	)		3,134			(3,264	)
Foreign tax credits		(11,431	)		(6,497	)		(3,129	)
Unrecognized tax benefits		(741	)		(817	)		7,784
Valuation allowances		62,318			(1,892	)		5,044
Goodwill impairment		53,988			—			52,772
Impairment of investments in non-consolidated affiliates		—			—			25,407
Other		858			944			2,568
Provision (benefit from) for income taxes	$	(13,465	)	$	(66,606	)		$ 51,667

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Deferred income tax balances are the direct effect of temporary differences between the financial statement carrying amounts and the tax basis of assets and liabilities at the enacted tax rates expected to be in effect when the taxes are actually paid or recovered. The tax effects of temporary differences that give rise to deferred tax assets and deferred tax liabilities are as follows (in thousands):

	December 31,
	2011			2010
Deferred tax assets:
Net operating loss carryforwards	$	246,163		$	323,354
Inventory		4,942			3,950
Alternative minimum tax credit carryforwards		13,020			8,269
Accrued liabilities		14,627			11,217
Foreign tax credit carryforwards		100,266			88,835
Other		39,874			52,407
Subtotal		418,892			488,032
Valuation allowances		(76,066	)		(18,140	)
Total deferred tax assets		342,826			469,892
Deferred tax liabilities:
Property, plant and equipment		(336,104	)		(377,049	)
Basis difference in the Partnership		(69,922	)		(81,013	)
Goodwill and intangibles		—			(17,987	)
Other		—			(28,830	)
Total deferred tax liabilities		(406,026	)		(504,879	)
Net deferred tax liabilities	$	(63,200	)	$	(34,987	)

Tax balances are presented in the accompanying consolidated balance sheets as follows (in thousands):

	December 31,
	2011			2010
Current deferred income tax assets	$	37,401		$	36,093
Intangibles and other assets		27,789			59,585
Accrued liabilities		(3,543	)		(10,241	)
Deferred income tax liabilities		(124,847	)		(120,424	)
Net deferred tax liabilities	$	(63,200	)	$	(34,987	)

At December 31, 2011, we had U.S. federal net operating loss carryforwards of approximately $457.5 million that are available to offset future taxable income. If not used, the carryforwards will begin to expire in 2022. We also had approximately $282.6 million of net operating loss carryforwards in certain foreign jurisdictions (excluding discontinued operations), approximately $145.7 million of which has no expiration date, $44.0 million of which is subject to expiration from 2012 to 2015, and the remainder of which expires in future years through 2031. Foreign tax credit carryforwards of $100.3 million and alternative minimum tax credit carryforwards of $13.0 million are available to offset future payments of U.S. federal income tax. The foreign tax credits will expire in varying amounts beginning in 2013, whereas the alternative minimum tax credits may be carried forward indefinitely under current U.S. tax law.

Pursuant to Sections 382 and 383 of the Internal Revenue Code of 1986, as amended, utilization of loss carryforwards and credit carryforwards, such as foreign tax credits, will be subject to annual limitations due to the ownership changes of both Hanover and Universal. In general, an ownership change, as defined by Section 382, results from transactions increasing the ownership of certain stockholders or public groups in the stock of a corporation by more than 50 percentage points over a three-year period. The merger resulted in such an

F-31

ownership change for both Hanover and Universal. Our ability to utilize loss carryforwards and credit carryforwards against future U.S. federal taxable income and future U.S. federal income tax may be limited. The limitations may cause us to pay U.S. federal income taxes earlier; however, we do not currently expect that any loss carryforwards or credit carryforwards will expire as a result of these limitations.

We record valuation allowances when it is more likely than not that some portion or all of our deferred tax assets will not be realized. The ultimate realization of the deferred tax assets depends on the ability to generate sufficient taxable income of the appropriate character and in the appropriate taxing jurisdictions in the future. If we do not meet our expectations with respect to taxable income, we may not realize the full benefit from our deferred tax assets which would require us to record a valuation allowance in our tax provision in future years.

In the third quarter of 2011, we recorded a valuation allowance of $1.3 million against our foreign tax credit deferred tax asset. While we expect to generate sufficient foreign source taxable income in the future, we no longer expect to generate sufficient overall taxable income in the future to fully use our net operating loss carryforwards and thus a portion of our foreign tax credit carryforwards before the year 2014. The foreign tax credits that expire in the year 2013 are no longer more likely than not to be realized within the 10-year carryforward period.

A $48.6 million valuation allowance was recorded against the deferred tax asset for Brazil net operating loss carryforwards for the year ended December 31, 2011. Although the net operating losses have an unlimited carryforward period, cumulative losses in recent years and losses expected in the near term result in it no longer being more likely than not that we will realize the deferred tax asset in the foreseeable future. Due to annual limitations on the utilization of Brazil net operating loss carryforwards, we would need to generate more than $400 million of taxable income in Brazil to fully realize the deferred tax asset.

We have not provided U.S. federal income taxes on indefinitely (or permanently) reinvested cumulative earnings of approximately $457.7 million generated by our non-U.S. subsidiaries. Such earnings are from ongoing operations which will be used to fund international growth. We have not recorded a deferred tax liability related to these unremitted foreign earnings as it is not practicable to estimate the amount of unrecognized deferred tax liabilities. In the event of a distribution of those earnings to the U.S. in the form of dividends, we may be subject to both foreign withholding taxes and U.S. federal income taxes net of allowable foreign tax credits.

A reconciliation of the beginning and ending amount of unrecognized tax benefits (including discontinued operations) is shown below (in thousands):

	Years Ended December 31,
	2011			2010			2009
Beginning balance	$	15,614		$	19,756		$	13,870
Additions based on tax positions related to prior years		—			—			5,886
Reductions based on lapse of statute of limitations		(167	)		—			—
Reductions based on tax positions related to prior years		(702	)		(4,142	)		—
Ending balance	$	14,745		$	15,614		$	19,756

We had $14.7 million, $15.6 million and $19.8 million of unrecognized tax benefits at December 31, 2011, 2010 and 2009, respectively, which if recognized would affect the effective tax rate (except for amounts that would be reflected in Income (loss) from discontinued operations, net of tax). We also have recorded $11.9 million, $10.6 million and $11.9 million of potential interest expense and penalties related to unrecognized tax benefits associated with uncertain tax positions (including discontinued operations) as of December 31, 2011, 2010 and 2009, respectively. To the extent interest and penalties are not assessed with respect to uncertain tax positions, amounts accrued will be reduced and reflected as reductions in income tax expense.

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We and our subsidiaries file consolidated and separate income tax returns in the U.S. federal jurisdiction and in numerous state and foreign jurisdictions. We are subject to U.S. federal income tax examinations for tax years beginning from 1997 onward and, early in the second quarter of 2011, the Internal Revenue Service commenced an examination of our U.S. federal income tax returns for the tax years 2006, 2008 and 2009. We do not expect any tax adjustments that would have a material impact on our financial position or results of operations.

State income tax returns are generally subject to examination for a period of three to five years after filing of the returns. However, the state impact of any U.S. federal audit adjustments and amendments remain subject to examination by various states for a period of up to one year after formal notification to the states. As of December 31, 2011, we did not have any state audits underway that would have a material impact on our financial position or results of operations.

We are subject to examination by taxing authorities throughout the world, including major foreign jurisdictions such as Argentina, Brazil, Canada, Italy, Mexico and Venezuela. With few exceptions, we and our subsidiaries are no longer subject to foreign income tax examinations for tax years before 2002. Several foreign audits are currently in progress and we do not expect any tax adjustments that would have a material impact on our financial position or results of operations.

We believe it is reasonably possible that a decrease of up to $2.0 million in unrecognized tax benefits may be necessary on or before December 31, 2012 due to the settlement of audits and the expiration of statutes of limitations. However, due to the uncertain and complex application of tax regulations, it is possible that the ultimate resolution of these matters may result in liabilities which could materially differ from these estimates. During 2011, unrecognized tax benefits decreased by $0.9 million as reflected in the above reconciliation.

16. Common Stockholders’ Equity

The Exterran Holdings, Inc. 2007 Amended and Restated Stock Incentive Plan (the “2007 Plan”) allows us to withhold shares to use upon vesting of restricted stock at the current market price to cover the minimum level of taxes required to be withheld on the vesting date. We purchased 157,756 of our shares from participants for approximately $2.9 million during 2011 to cover tax withholding. The 2007 Plan is administered by the compensation committee of our board of directors.

17. Stock-based Compensation and Awards

The following table presents the stock-based compensation expense included in our results of operations (in thousands):

	Years Ended December 31,
	2011		2010		2009
Stock options	$	3,916	$	5,273	$	5,673
Restricted stock, restricted stock units and phantom units		14,970		17,796		17,983
Employee stock purchase plan		278		282		935
Total stock-based compensation expense	$	19,164	$	23,351	$	24,591

Stock Incentive Plan

In August 2007, we adopted the Exterran Holdings, Inc. 2007 Stock Incentive Plan (as amended and restated, the “2007 Plan”) that provides for the granting of stock-based awards in the form of options, restricted stock, restricted stock units, stock appreciation rights and performance awards to our employees and directors. In May 2011, our stockholders approved an amendment to the 2007 Plan that increased the aggregate number of shares of common stock that may be issued under the 2007 Plan to 12,500,000 from 9,750,000. Each option and stock

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appreciation right granted counts as one share against the aggregate share limit, and each share of restricted stock and restricted stock unit granted counts as two shares against the aggregate share limit. Awards granted under the 2007 Plan that are subsequently cancelled, terminated or forfeited are available for future grant.

Stock Options

Under the 2007 Plan, stock options are granted at fair market value at the date of grant, are exercisable in accordance with the vesting schedule established by the compensation committee of our board of directors in its sole discretion and expire no later than seven years after the date of grant. Options generally vest 33 1/3% on each of the first three anniversaries of the grant date.

The weighted average fair value at date of grant for options granted during the years ended December 31, 2011, 2010 and 2009 was $5.81, $8.71 and $5.87, respectively, and was estimated using the Black-Scholes option valuation model with the following weighted average assumptions:

	Years Ended December 31,
	2011			2010			2009
Expected life in years		4.5			4.5			4.5
Risk-free interest rate		1.23	%		2.13	%		1.84	%
Volatility		45.17	%		42.94	%		40.51	%
Dividend yield		0.0	%		0.0	%		0.0	%

The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of the grant for a period commensurate with the estimated expected life of the stock options. Expected volatility is based on the historical volatility of our stock over the period commensurate with the expected life of the stock options and other factors. We have not historically paid a dividend and do not expect to pay a dividend during the expected life of the stock options.

The following table presents stock option activity for the year ended December 31, 2011 (in thousands, except per share data and remaining life in years):

	Stock Options			Weighted Average Exercise Price		Weighted Average Remaining Life		Aggregate Intrinsic Value
Options outstanding, December 31, 2010		3,124		$	31.20
Granted		924			15.33
Exercised		(33	)		16.16
Cancelled		(744	)		28.90
Options outstanding, December 31, 2011		3,271			27.39		4.1	$	—
Options exercisable, December 31, 2011		2,029			34.20		2.9		—

Intrinsic value is the difference between the market value of our stock and the exercise price of each option multiplied by the number of options outstanding for those options where the market value exceeds their exercise price. The total intrinsic value of stock options exercised during 2011 and 2010 was $0.2 million and $0.5 million, respectively. No stock options were exercised during the year ended December 31, 2009. As of December 31, 2011, $5.2 million of unrecognized compensation cost related to unvested stock options is expected to be recognized over the weighted-average period of 2.0 years.

Restricted Stock and Restricted Stock Units

For grants of restricted stock and restricted stock units, we recognize compensation expense over the vesting period equal to the fair value of our common stock at the date of grant. Our restricted stock and restricted stock unit grants generally vest 33 1/3% on each of the first three anniversaries of the grant date.

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The following table presents restricted stock and restricted stock unit activity for the year ended December 31, 2011 (in thousands, except per share data):

	Shares			Weighted Average Grant-Date Fair Value Per Share
Non-vested restricted stock and restricted stock units, December 31, 2010		1,421		$	23.20
Granted		1,212			19.22
Vested		(743	)		25.36
Cancelled		(220	)		22.11
Non-vested restricted stock and restricted stock units, December 31, 2011		1,670			19.49

As of December 31, 2011, $21.1 million of unrecognized compensation cost related to unvested restricted stock and restricted stock units is expected to be recognized over the weighted-average period of 2.0 years.

Our compensation committee’s general practice has been to grant equity-based awards once a year, in late February or early March after fourth quarter earnings information for the prior year has been released for at least two full trading days. The schedule for making equity-based awards is typically established several months in advance, and is not set based on knowledge of material nonpublic information or in response to our stock price. This practice results in awards being granted on a regular, predictable annual cycle, after annual earnings information has been disseminated to the marketplace. Equity-based awards are occasionally granted at other times during the year, such as upon the hiring of a new employee or following the promotion of an employee. In some instances, the compensation committee may be aware, at the time grants are made, of matters or potential developments that are not ripe for public disclosure at that time but that may result in public announcement of material information at a later date. In March 2011, the compensation committee of our board of directors authorized annual long-term incentive awards of stock options, restricted stock, restricted stock units and performance shares to our executive officers, other employees and non-employee directors.

Employee Stock Purchase Plan

In August 2007, we adopted the Exterran Holdings, Inc. Employee Stock Purchase Plan (“ESPP”), which is intended to provide employees with an opportunity to participate in our long-term performance and success through the purchase of shares of common stock at a price that may be less than fair market value. The ESPP is designed to comply with Section 423 of the Internal Revenue Code of 1986, as amended. Each quarter, an eligible employee may elect to withhold a portion of his or her salary up to the lesser of $25,000 per year or 10% of his or her eligible pay to purchase shares of our common stock at a price equal to 85% to 100% of the fair market value of the stock as of the first trading day of the quarter, the last trading day of the quarter or the lower of the first trading day of the quarter and the last trading day of the quarter, as the compensation committee of our board of directors may determine. The ESPP will terminate on the date that all shares of common stock authorized for sale under the ESPP have been purchased, unless it is extended. In May 2011, our stockholders approved an amendment to the ESPP that increased the aggregate number of shares of common stock available for purchase under the ESPP to 1,000,000. At December 31, 2011, 491,533 shares remained available for purchase under the ESPP. Our ESPP is compensatory and, as a result, we record an expense on our consolidated statements of operations related to the ESPP. Since July 2009, the purchase discount under the ESPP has been 5% of the fair market value of our common stock on the first trading day of the quarter or the last trading day of the quarter, whichever is lower.

Directors’ Stock and Deferral Plan

On August 20, 2007, we adopted the Exterran Holdings, Inc. Directors’ Stock and Deferral Plan. The purpose of the Directors’ Stock and Deferral Plan is to provide non-employee directors of the board of directors with an

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opportunity to elect to receive our common stock as payment for a portion or all of their retainer and meeting fees. The number of shares to be paid each quarter will be determined by dividing the dollar amount of fees elected to be paid in common stock by the closing sales price per share of the common stock on the last day of the quarter. In addition, directors who elect to receive a portion or all of their fees in the form of common stock may also elect to defer, until a later date, the receipt of a portion or all of their fees to be received in common stock. We have reserved 100,000 shares under the Directors’ Stock and Deferral Plan, and as of December 31, 2011, 69,629 shares remain available to be issued under the plan.

Employment Inducement Plan

In anticipation of certain key management changes discussed above, in November 2011, our board of directors adopted the Exterran Holdings, Inc. 2011 Employment Inducement Long-Term Equity Plan (the “Employment Inducement Plan”), which authorizes the issuance of up to 1,000,000 of non-qualified stock options, restricted stock, restricted stock units, stock appreciation rights and performance awards to certain newly-hired employees of us or our affiliates. The Employment Inducement Plan is only available to grant awards to an individual, as a material inducement to such individual to enter into employment with us, who (i) has not previously been an employee of us or our affiliates or (ii) is rehired following a bona fide period of non-employment with us and our affiliates. Awards granted under the Employment Inducement Plan that are subsequently cancelled, terminated or forfeited are available for future grant. As of December 31, 2011, 539,982 shares remain available to be issued under the Employment Inducement Plan. We do not intend to issue any additional equity under the Employment Inducement Plan, other than as necessary to materially induce a high-level executive to enter into employment with us.

Partnership Long-Term Incentive Plan

The Partnership has a long-term incentive plan that was adopted by Exterran GP LLC, the general partner of the Partnership’s general partner, in October 2006 for employees, directors and consultants of the Partnership, us or our respective affiliates. The long-term incentive plan currently permits the grant of awards covering an aggregate of 1,035,378 common units, common unit options, restricted units and phantom units. The long-term incentive plan is administered by the board of directors of Exterran GP LLC or a committee thereof (the “Plan Administrator”).

Unit options will have an exercise price that is not less than the fair market value of a common unit on the date of grant and will become exercisable over a period determined by the Plan Administrator. Phantom units are notional units that entitle the grantee to receive a common unit upon the vesting of the phantom unit or, at the discretion of the Plan Administrator, cash equal to the fair value of a common unit.

Partnership Phantom Units

During the year ended December 31, 2011, the Partnership granted 49,082 phantom units to officers and directors of Exterran GP LLC and certain of our employees, which vest 33 1/3% on each of the first three anniversaries of the grant date.

The following table presents phantom unit activity for the year ended December 31, 2011:

	Phantom Units			Weighted Average Grant-Date Fair Value per Unit
Phantom units outstanding, December 31, 2010		98,537		$	19.23
Granted		49,082			24.70
Vested		(67,026	)		20.47
Cancelled		(5,326	)		22.56
Phantom units outstanding, December 31, 2011		75,267			21.45

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As of December 31, 2011, $1.4 million of unrecognized compensation cost related to unvested phantom units is expected to be recognized over the weighted-average period of 1.8 years.

18. Retirement Benefit Plan

Our 401(k) retirement plan provides for optional employee contributions up to the Internal Revenue Service limit and discretionary employer matching contributions. We generally make discretionary matching contributions to each participant’s account at a rate of (i) 100% of each participant’s first 1% of contributions plus (ii) 50% of each participant’s contributions up to the next 5% of eligible compensation. We made no discretionary matching contributions from July 1, 2009 through June 30, 2010, but began making them again effective on July 1, 2010. We recorded matching contributions of $8.7 million, $3.9 million and $4.4 million during 2011, 2010 and 2009, respectively.

19. Transactions Related to the Partnership

In June 2011, we sold to the Partnership contract operations customer service agreements with 34 customers and a fleet of 407 compressor units used to provide compression services under those agreements, comprising approximately 289,000 horsepower, or 8% (by then available horsepower) of our combined U.S. contract operations business (the “June 2011 Contract Operations Acquisition”). In addition, the assets sold included 207 compressor units, comprising approximately 98,000 horsepower, that we previously leased to the Partnership, and a natural gas processing plant with a capacity of 8 million cubic feet per day used to provide processing services pursuant to a long-term services agreement. Total consideration for the transaction was approximately $223.0 million, excluding transaction costs. In connection with this acquisition, the Partnership assumed $159.4 million of our debt, paid us $62.2 million in cash and issued to Exterran General Partner, L.P. (“GP”), our wholly-owned subsidiary and the Partnership’s general partner, approximately 51,000 general partner units. In connection with this transaction, we entered into an amendment and restatement of our omnibus agreement with the Partnership that, among other things, extended the term of the caps on the Partnership’s obligation to reimburse us for SG&A costs and operating costs we allocate to the Partnership based on such costs we incur on the Partnership’s behalf for an additional year such that the caps will now terminate on December 31, 2012.

In May 2011, the Partnership sold, pursuant to a public underwritten offering, 5,134,175 common units representing limited partner interests in the Partnership, including 134,175 common units to cover over-allotments. The Partnership used the $127.7 million of net proceeds from this offering (i) to repay approximately $64.8 million of borrowings outstanding under its revolving credit facility and (ii) for general partnership purposes, including to fund a portion of the consideration for the June 2011 Contract Operations Acquisition. In connection with this sale and as permitted under the Partnership’s partnership agreement, the Partnership issued and sold to GP approximately 53,000 general partner units in consideration of the continuation of GP’s approximate 2.0% general partner interest in the Partnership.

In March 2011, we sold, pursuant to a public underwritten offering, 5,914,466 common units representing limited partner interests in the Partnership, including 664,466 common units to cover over-allotments. We used the $162.2 million of net proceeds received from the sale of the common units to repay borrowings under our revolving credit facility and term loan. The change in our ownership interest of the Partnership from the sale of the common units resulted in adjustments to noncontrolling interest, accumulated other comprehensive loss, deferred income taxes and additional paid-in capital to reflect our new ownership percentage in the Partnership.

In September 2010, we sold, pursuant to a public underwritten offering, 5,290,000 common units representing limited partner interests in the Partnership, including 690,000 common units to cover over-allotments. We used the $109.4 million of net proceeds received from the sale of the common units to repay borrowings under our revolving credit facility and term loan. The change in our ownership interest of the Partnership from the sale of the common units resulted in adjustments to noncontrolling interest, accumulated other comprehensive loss and additional paid-in capital to reflect our new ownership percentage in the Partnership.

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In August 2010, we sold to the Partnership contract operations customer service agreements with 43 customers and a fleet of approximately 580 compressor units used to provide compression services under those agreements, comprising approximately 255,000 horsepower, or approximately 6% (by then available horsepower) of our combined U.S. contract operations business. Total consideration for the transaction was approximately $214.0 million, excluding transaction costs. In connection with this acquisition, the Partnership issued to our wholly-owned subsidiaries approximately 8.2 million common units and approximately 167,000 general partner units.

Through our wholly-owned subsidiaries, we owned all of the subordinated units of the Partnership. As of each of June 30, 2011 and 2010, the Partnership met the requirements under its partnership agreement for early conversion of 1,581,250 of these subordinated units into common units. Accordingly, in each of August 2011 and 2010, 1,581,250 subordinated units converted into common units. As of September 30, 2011, the Partnership met the requirements under its partnership agreement for conversion of all remaining subordinated units into common units and therefore, the remaining 3,162,500 subordinated units converted into common units in November 2011.

The table below presents the effects of changes from net income (loss) attributable to Exterran stockholders and changes in our equity interest of the Partnership on our equity attributable to Exterran’s stockholders (in thousands):

	December 31,
	2011			2010
Net loss attributable to Exterran stockholders		$ (340,608	)	$	(101,825	)
Increase in Exterran stockholders’ additional paid in capital for sale of Partnership units		123,904			41,111
Change from net loss attributable to Exterran stockholders and transfers to the noncontrolling interest		$ (216,704	)	$	(60,714	)

20. Commitments and Contingencies

Rent expense for 2011, 2010 and 2009 was approximately $24.7 million, $23.5 million and $21.4 million, respectively. Commitments for future minimum rental payments with terms in excess of one year at December 31, 2011 are as follows (in thousands):

	December 31, 2011
2012	$	14,188
2013		8,151
2014		6,678
2015		5,806
2016		4,825
Thereafter		15,927
Total	$	55,575

We have issued the following guarantees that are not recorded on our accompanying balance sheet (dollars in thousands):

	Term		Maximum  Potential Undiscounted Payments as of December 31, 2011
Performance guarantees through letters of credit(1)		2012–2016	$	246,197
Standby letters of credit		2012		15,921
Bid bonds and performance bonds(1)		2012–2018		127,488
Maximum potential undiscounted payments			$	389,606

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(1) We have issued guarantees to third parties to ensure performance of our obligations, some of which may be fulfilled by third parties.

As part of an acquisition in 2001, we may be required to make contingent payments of up to $46 million to the seller, depending on our realization of certain U.S. federal tax benefits through the year 2015. To date, we have not realized any such benefits that would require a payment and we do not anticipate realizing any such benefits that would require a payment before the year 2013.

See Note 2 and Note 7 for a discussion of gain contingencies related to assets and investments that were expropriated in Venezuela.

Our business can be hazardous, involving unforeseen circumstances such as uncontrollable flows of natural gas or well fluids and fires or explosions. As is customary in our industry, we review our safety equipment and procedures and carry insurance against some, but not all, risks of our business. Our insurance coverage includes property damage, general liability and commercial automobile liability and other coverage we believe is appropriate. In addition, we have a minimal amount of insurance on our offshore assets. We believe that our insurance coverage is customary for the industry and adequate for our business; however, losses and liabilities not covered by insurance would increase our costs.

Additionally, we are substantially self-insured for worker’s compensation and employee group health claims in view of the relatively high per-incident deductibles we absorb under our insurance arrangements for these risks. Losses up to the deductible amounts are estimated and accrued based upon known facts, historical trends and industry averages.

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, we believe that any ultimate liability arising from these actions will not have a material effect on our consolidated financial position, results of operations or cash flows. Because of the inherent uncertainty of litigation, however, we cannot provide assurance that the resolution of any particular claim or proceeding to which we are a party will not have a material effect on our consolidated financial position, results of operations or cash flows for the period in which the resolution occurs.

21. Recent Accounting Developments

In October 2009, the Financial Accounting Standards Board (“FASB”) issued an update to existing guidance on revenue recognition for arrangements with multiple deliverables. This update addresses accounting for multiple-deliverable arrangements to enable vendors to account for deliverables separately. The guidance establishes a selling price hierarchy for determining the selling price of a deliverable. This update requires expanded disclosures for multiple deliverable revenue arrangements. The update is effective for us for revenue arrangements entered into or materially modified on or after January 1, 2011. Our adoption of this new guidance on January 1, 2011 did not have a material impact on our consolidated financial statements.

In December 2010, the FASB issued ASU No. 2010-29 Disclosure of Supplementary Pro Forma Information for Business Combinations. This standard update clarifies that, when presenting comparative financial statements, public companies should disclose revenue and earnings of the combined entity as though the current period business combinations had occurred as of the beginning of the comparable prior annual reporting period only. The update also expands the supplemental pro forma disclosures to include a description of the nature and amount of material, nonrecurring pro forma adjustments directly attributable to the business combination included in the reported pro forma revenue and earnings. The update is effective prospectively for business combinations entered into in fiscal years beginning on or after December 15, 2010. Our adoption of this new guidance did not have a material impact on our consolidated financial statements.

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In May 2011, the FASB issued an update to provide a consistent definition of fair value and ensure that the fair value measurement and disclosure requirements are similar between GAAP and International Financial Reporting Standards. This update changes certain fair value measurement principles and enhances the disclosure requirements particularly for Level 3 fair value measurements. This update is effective for interim and annual periods beginning on or after December 15, 2011. We do not believe the adoption of this update will have a material impact on our consolidated financial statements.

In June 2011, the FASB issued an update on the presentation of other comprehensive income. Under this update, entities will be required to present the total of comprehensive income, the components of net income, and the components of other comprehensive income either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The current option to report other comprehensive income and its components in the statement of changes in equity has been eliminated. This update is effective for interim and annual periods beginning on or after December 15, 2011. We do not believe the adoption of this update will have a material impact on our consolidated financial statements.

In September 2011, the FASB issued an update allowing entities to use a qualitative approach to test goodwill for impairment. Under this update, entities are permitted to first perform a qualitative assessment to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value. If it is concluded that this is the case, it is necessary to perform the currently prescribed two-step goodwill impairment test. Otherwise, the two-step goodwill impairment test is not required. This update is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011. We do not believe the adoption of this update will have a material impact on our consolidated financial statements.

22. Reportable Segments and Geographic Information

We manage our business segments primarily based upon the type of product or service provided. We have four principal segments: North America contract operations, international contract operations, aftermarket services and fabrication. The North America and international contract operations segments primarily provide natural gas compression services, production and processing equipment services and maintenance services to meet specific customer requirements on Exterran-owned assets. The aftermarket services segment provides a full range of services to support the surface production, compression and processing needs of customers, from parts sales and normal maintenance services to full operation of a customer’s owned assets. The fabrication segment provides (i) design, engineering, fabrication, installation and sale of natural gas compression units and accessories and equipment used in the production, treating and processing of crude oil and natural gas and (ii) 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.

We evaluate the performance of our segments based on gross margin for each segment. Revenues include only sales to external customers. We do not include intersegment sales when we evaluate the performance of our segments.

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No individual customer accounted for more than 10% of our consolidated revenues during any of the periods presented. The following table presents sales and other financial information by reportable segment for the years ended December 31, 2011, 2010 and 2009 (in thousands):

	North  America Contract Operations		International Contract Operations		Aftermarket Services		Fabrication		Reportable Segments Total		Other(1)		Total(2)
2011:
Revenue from external customers	$	603,529	$	445,059	$	409,423	$	1,225,459	$	2,683,470	$	—	$	2,683,470
Gross margin(3)		293,460		260,654		60,761		123,222		738,097		—		738,097
Total assets		2,052,170		887,046		111,890		384,099		3,435,205		921,444		4,356,649
Capital expenditures		192,470		58,767		2,082		22,077		275,396		7,395		282,791
2010:
Revenue from external customers	$	608,065	$	465,144	$	322,097	$	1,066,227	$	2,461,533	$	—	$	2,461,533
Gross margin(3)		307,379		289,787		45,790		161,505		804,461		—		804,461
Total assets		2,061,755		976,700		160,864		580,255		3,779,574		946,872		4,726,446
Capital expenditures		111,087		106,530		1,348		12,187		231,152		4,838		235,990
2009:
Revenue from external customers	$	695,315	$	391,995	$	308,873	$	1,319,418	$	2,715,601	$	—	$	2,715,601
Gross margin(3)		396,601		242,742		62,987		213,252		915,582		—		915,582
Total assets		2,357,751		988,257		148,548		720,482		4,215,038		1,019,372		5,234,410
Capital expenditures		108,985		236,450		2,629		10,592		358,656		10,245		368,901

The following table presents assets from reportable segments to total assets as of December 31, 2011 and 2010 (in thousands):

	2011		2010
Assets from reportable segments	$	3,435,205	$	3,779,574
Other assets(1)		921,444		946,872
Assets associated with discontinued operations		4,013		15,090
Consolidated assets	$	4,360,662	$	4,741,536

The following table presents geographic data as of and for the years ended December 31, 2011, 2010 and 2009 (in thousands):

	U.S.		International		Consolidated
2011:
Revenues from external customers	$	1,453,758	$	1,229,712	$	2,683,470
Property, plant and equipment, net	$	1,993,082	$	1,011,370	$	3,004,452
2010:
Revenues from external customers	$	1,090,096	$	1,371,437	$	2,461,533
Property, plant and equipment, net	$	1,985,180	$	1,107,472	$	3,092,652
2009:
Revenues from external customers	$	1,332,641	$	1,382,960	$	2,715,601
Property, plant and equipment, net	$	2,278,172	$	1,126,182	$	3,404,354

(1) Includes corporate related items.

(2) Totals exclude assets, capital expenditures and the operating results of discontinued operations.

(3) Gross margin, a non-GAAP financial measure, is reconciled to net loss below.

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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. 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 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.

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

	Years Ended December 31,
	2011			2010			2009
Net loss	$	(339,618	)	$	(113,241	)	$	(545,463	)
Selling, general and administrative		359,382			358,255			337,620
Depreciation and amortization		365,870			401,478			352,785
Long-lived asset impairment		7,012			146,903			96,988
Restructuring charges		11,627			—			14,329
Goodwill impairment		196,807			—			150,778
Interest expense		149,473			136,149			122,845
Equity in loss of non-consolidated affiliates		471			609			91,154
Other (income) expense, net		(5,425	)		(13,763	)		(53,360	)
Provision for (benefit from) income taxes		(13,465	)		(66,606	)		51,667
(Income) loss from discontinued operations, net of tax		5,963			(45,323	)		296,239
Gross margin	$	738,097		$	804,461		$	915,582

23. CONSOLIDATING FINANCIAL STATEMENTS

Exterran Energy Corp. (Subsidiary Issuer), our wholly-owned subsidiary, is the issuer of the 4.75% Notes. Exterran Holdings, Inc. (Parent) has agreed to fully and unconditionally guarantee the obligations of Exterran Energy Corp. relating to our 4.75% Notes. There are no other subsidiaries of the Parent that have provided guarantees to the 4.75% Notes. The Guarantor Subsidiaries and Other Subsidiaries columns represent non-guarantor subsidiaries for the 4.75% Notes.

We are the issuer of the 7.25% Notes. Exterran Energy Solutions, L.P., EES Leasing LLC, EXH GP LP LLC, and EXH MLP LP LLC (all our wholly-owned subsidiaries; together the Guarantor Subsidiaries), have agreed to fully and unconditionally guarantee our obligations relating to the 7.25% Notes. There is no subsidiary issuer for the 7.25% debt; that debt was issued solely by the Parent. The Subsidiary Issuer and Other Subsidiaries columns represent non-guarantor subsidiaries for the 7.25% Notes.

As a result of these guarantees, we are presenting the following condensed consolidating financial information pursuant to Rule 3-10 of Regulation S-X. These schedules are presented using the equity method of accounting for all periods presented. Under this method, investments in subsidiaries are recorded at cost and adjusted for our share in the subsidiaries’ cumulative results of operations, capital contributions and distributions and other changes in equity. Elimination entries relate primarily to the elimination of investments in subsidiaries and associated intercompany balances and transactions.

F-42

Condensed Consolidating Balance Sheet

December 31, 2011

(In thousands)

	Parent		Subsidiary Issuer		Guarantor Subsidiaries		Other Subsidiaries		Eliminations			Consolidation
ASSETS
Current assets	$	93	$	—	$	563,927	$	555,882	$	12		$	1,119,914
Current assets associated with discontinued operations		—		—		—		4,013		—			4,013
Total current assets		93		—		563,927		559,895		12			1,123,927
Property, plant and equipment, net		—		—		1,513,366		1,491,086		—			3,004,452
Investments in affiliates		1,813,197		1,774,029		1,687,806		—		(5,275,032	)		—
Intangible and other assets, net		18,389		39,168		78,836		134,678		(38,788	)		232,283
Intercompany receivables		945,401		1,068,746		99,075		637,165		(2,750,387	)		—
Long-term assets associated with discontinued operations		—		—		—		—		—			—
Total long-term assets		2,776,987		2,881,943		3,379,083		2,262,929		(8,064,207	)		3,236,735
Total assets	$	2,777,080	$	2,881,943	$	3,943,010	$	2,822,824	$	(8,064,195	)	$	4,360,662
LIABILITIES AND EQUITY
Current liabilities	$	11,122	$	3,147	$	353,827	$	308,320	$	(12,918	)	$	663,498
Current liabilities associated with discontinued operations		—		—		—		6,383		—			6,383
Total current liabilities		11,122		3,147		353,827		314,703		(12,918	)		669,881
Long-term debt		1,083,649		143,750		—		545,640		—			1,773,039
Intercompany payables		—		921,849		1,705,911		122,627		(2,750,387	)		—
Other long-term liabilities		2,267		—		109,243		137,908		(25,858	)		223,560
Long-term liabilities associated with discontinued operations		—		—		—		14,140		—			14,140
Total liabilities		1,097,038		1,068,746		2,168,981		1,135,018		(2,789,163	)		2,680,620
Total equity		1,680,042		1,813,197		1,774,029		1,687,806		(5,275,032	)		1,680,042
Total liabilities and equity	$	2,777,080	$	2,881,943	$	3,943,010	$	2,822,824	$	(8,064,195	)	$	4,360,662

F-43

Condensed Consolidating Balance Sheet

December 31, 2010

(In thousands)

	Parent		Subsidiary Issuer		Guarantor Subsidiaries		Other Subsidiaries		Eliminations			Consolidation
ASSETS
Current assets	$	160	$	—	$	559,367	$	595,151	$	8		$	1,154,686
Current assets associated with discontinued operations		—		—		—		5,918		—			5,918
Total current assets		160		—		559,367		601,069		8			1,160,604
Property, plant and equipment, net		—		—		1,680,256		1,412,396		—			3,092,652
Goodwill		—		—		146,876		49,804		—			196,680
Investments in affiliates		1,998,616		1,991,518		1,967,403		—		(5,957,537	)		—
Intangible and other assets, net		17,343		40,594		147,513		115,766		(38,788	)		282,428
Intercompany receivables		1,118,405		1,207,450		72,714		889,073		(3,287,642	)		—
Long-term assets associated with discontinued operations		—		—		—		9,172		—			9,172
Total long-term assets		3,134,364		3,239,562		4,014,762		2,476,211		(9,283,967	)		3,580,932
Total assets	$	3,134,524	$	3,239,562	$	4,574,129	$	3,077,280	$	(9,283,959	)	$	4,741,536
LIABILITIES AND EQUITY
Current liabilities	$	21,320	$	3,147	$	352,409	$	368,346	$	(2,573	)	$	742,649
Current liabilities associated with discontinued operations		—		—		—		15,554		—			15,554
Total current liabilities		21,320		3,147		352,409		383,900		(2,573	)		758,203
Long-term debt		1,298,165		143,750		—		455,232		—			1,897,147
Intercompany payables		—		1,094,049		2,096,523		97,070		(3,287,642	)		—
Other long-term liabilities		12,615		—		133,679		160,564		(36,207	)		270,651
Long-term liabilities associated with discontinued operations		—		—		—		13,111		—			13,111
Total liabilities		1,332,100		1,240,946		2,582,611		1,109,877		(3,326,422	)		2,939,112
Total equity		1,802,424		1,998,616		1,991,518		1,967,403		(5,957,537	)		1,802,424
Total liabilities and equity	$	3,134,524	$	3,239,562	$	4,574,129	$	3,077,280	$	(9,283,959	)	$	4,741,536

F-44

Condensed Consolidating Statement of Operations

Year Ended December 31, 2011

(In thousands)

	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Other Subsidiaries			Eliminations			Consolidation
Revenues	$	—		$	—		$	1,363,843		$	1,610,224		$	(290,597	)	$	2,683,470
Costs of sales (excluding depreciation and amortization expense)		—			—			1,091,719			1,144,251			(290,597	)		1,945,373
Selling, general and administrative		282			268			175,896			182,936			—			359,382
Depreciation and amortization		—			—			150,094			215,776			—			365,870
Long-lived asset impairment		—			—			4,724			2,288			—			7,012
Restructuring charges		—			—			—			11,627			—			11,627
Goodwill impairment		—			—			147,541			49,266			—			196,807
Interest expense		99,415			6,828			2,634			40,596			—			149,473
Other (income) expense:
Intercompany charges, net		(60,928	)		(6,565	)		67,493			—			—			—
Equity in loss of affiliates		315,368			315,023			99,567			471			(729,958	)		471
Other, net		40			—			(10,573	)		5,108			—			(5,425	)
Loss before income taxes		(354,177	)		(315,554	)		(365,252	)		(42,095	)		729,958			(347,120	)
Provision for (benefit from) income taxes		(13,569	)		(186	)		(50,229	)		50,519			—			(13,465	)
Loss from continuing operations		(340,608	)		(315,368	)		(315,023	)		(92,614	)		729,958			(333,655	)
Loss from discontinued operations, net of tax		—			—			—			(5,963	)		—			(5,963	)
Net loss		(340,608	)		(315,368	)		(315,023	)		(98,577	)		729,958			(339,618	)
Less: Net income attributable to the noncontrolling interest		—			—			—			(990	)		—			(990	)
Net loss attributable to Exterran stockholders	$	(340,608	)	$	(315,368	)	$	(315,023	)	$	(99,567	)	$	729,958		$	(340,608	)

F-45

Condensed Consolidating Statement of Operations

Year Ended December 31, 2010

(In thousands)

	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Other Subsidiaries			Eliminations			Consolidation
Revenues	$	—		$	—		$	1,046,965		$	1,659,674		$	(245,106	)	$	2,461,533
Costs of sales (excluding depreciation and amortization expense)		—			—			849,663			1,052,515			(245,106	)		1,657,072
Selling, general and administrative		401			401			150,046			207,407			—			358,255
Depreciation and amortization		—			—			135,598			265,880			—			401,478
Long-lived asset impairment		—			—			112,427			34,476			—			146,903
Interest (income) expense		25,964			6,828			(10,173	)		113,530			—			136,149
Other (income) expense:
Intercompany charges, net		(41,255	)		(442	)		41,697			—			—			—
Equity in (income) loss of affiliates		128,761			124,349			(24,693	)		609			(228,417	)		609
Other, net		40			—			(15,281	)		1,478			—			(13,763	)
Loss before income taxes		(113,911	)		(131,136	)		(192,319	)		(16,221	)		228,417			(225,170	)
Provision for (benefit from) income taxes		(12,086	)		(2,375	)		(67,970	)		15,825			—			(66,606	)
Loss from continuing operations		(101,825	)		(128,761	)		(124,349	)		(32,046	)		228,417			(158,564	)
Income from discontinued operations, net of tax		—			—			—			45,323			—			45,323
Net income (loss)		(101,825	)		(128,761	)		(124,349	)		13,277			228,417			(113,241	)
Less: Net loss attributable to the noncontrolling interest		—			—			—			11,416			—			11,416
Net income (loss) attributable to Exterran stockholders	$	(101,825	)	$	(128,761	)	$	(124,349	)	$	24,693		$	228,417		$	(101,825	)

F-46

Condensed Consolidating Statement of Operations

Year Ended December 31, 2009

(In thousands)

	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Other Subsidiaries			Eliminations			Consolidation
Revenues	$	—		$	—		$	1,044,058		$	1,990,611		$	(319,068	)	$	2,715,601
Costs of sales (excluding depreciation and amortization expense)		—			—			770,351			1,348,736			(319,068	)		1,800,019
Selling, general and administrative		341			164			127,554			209,561			—			337,620
Depreciation and amortization		—			—			105,573			247,212			—			352,785
Long-lived asset impairment		—			—			76,171			20,817			—			96,988
Restructuring charges		—			—			—			14,329			—			14,329
Goodwill impairment		—			—			—			150,778			—			150,778
Interest (income) expense		51,473			6,813			(27,137	)		91,696			—			122,845
Other (income) expense:
Intercompany charges, net		(16,847	)		(3,764	)		20,611			—			—			—
Equity in loss of affiliates		527,335			525,247			537,563			91,154			(1,590,145	)		91,154
Other, net		40			—			(48,784	)		(4,616	)		—			(53,360	)
Loss before income taxes		(562,342	)		(528,460	)		(517,844	)		(179,056	)		1,590,145			(197,557	)
Provision for (benefit from) income taxes		(12,935	)		(1,125	)		7,403			58,324			—			51,667
Loss from continuing operations		(549,407	)		(527,335	)		(525,247	)		(237,380	)		1,590,145			(249,224	)
Loss from discontinued operations, net of tax		—			—			—			(296,239	)		—			(296,239	)
Net loss		(549,407	)		(527,335	)		(525,247	)		(533,619	)		1,590,145			(545,463	)
Less: Net income attributable to the noncontrolling interest		—			—			—			(3,944	)		—			(3,944	)
Net loss attributable to Exterran stockholders	$	(549,407	)	$	(527,335	)	$	(525,247	)	$	(537,563	)	$	1,590,145		$	(549,407	)

F-47

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2011

(In thousands)

	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Other Subsidiaries			Eliminations			Consolidation
Cash flows from operating activities:
Net cash provided by (used in) continuing operations	$	282,416		$	2,127		$	(172,542	)	$	6,987		$	—		$	118,988
Net cash provided by discontinued operations		—			—			—			1,336			—			1,336
Net cash provided by (used in) operating activities		282,416			2,127			(172,542	)		8,323			—			120,324
Cash flows from investing activities:
Capital expenditures		—			—			(170,881	)		(111,910	)		—			(282,791	)
Proceeds from sale of property, plant and equipment		—			—			13,423			32,835			—			46,258
Cash paid for business acquisition		—			—			(3,000	)		—			—			(3,000	)
Decrease in restricted cash		—			—			—			820			—			820
Cash invested in non-consolidated affiliates		—			—			—			(471	)		—			(471	)
Net proceeds from the sale of Partnership units		—			—			289,908			—			—			289,908
Investment in consolidated subsidiaries		(214,356	)		(183,030	)		—			—			397,386			—
Net cash provided by (used in) investing activities		(214,356	)		(183,030	)		129,450			(78,726	)		397,386			50,724
Cash flows from financing activities:
Proceeds from borrowings of long-term debt		1,336,240			—			—			557,500			—			1,893,740
Repayments of long-term debt		(1,569,078	)		—			—			(467,093	)		—			(2,036,171	)
Payments for debt issue costs		(7,666	)		—			—			(1,157	)		—			(8,823	)
Proceeds from stock options exercised		526			—			—			—			—			526
Proceeds from stock issued pursuant to our employee stock purchase plan		1,887			—			—			—			—			1,887
Purchases of treasury stock		(2,941	)		—			—			—			—			(2,941	)
Stock-based compensation excess tax benefit		1,034			—			—			—			—			1,034
Distributions to noncontrolling partners in the Partnership		—			—			—			(39,870	)		—			(39,870	)
Capital contribution, net		—			214,356			183,030			—			(397,386	)		—
Borrowings (repayments) between subsidiaries, net		171,871			(33,453	)		(138,704	)		286			—			—
Net cash provided by (used in) financing activities		(68,127	)		180,903			44,326			49,666			(397,386	)		(190,618	)
Effect of exchange rate changes on cash and cash equivalents		—			—			—			(3,007	)		—			(3,007	)
Net increase (decrease) in cash and cash equivalents		(67	)		—			1,234			(23,744	)		—			(22,577	)
Cash and cash equivalents at beginning of year		160			—			1,586			42,870			—			44,616
Cash and cash equivalents at end of year	$	93		$	—		$	2,820		$	19,126		$	—		$	22,039

F-48

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2010

(In thousands)

	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Other Subsidiaries			Eliminations			Consolidation
Cash flows from operating activities:
Net cash provided by (used in) continuing operations	$	48,796		$	(4,039	)	$	(240,601	)	$	564,099		$	—		$	368,255
Net cash used in discontinued operations		—			—			—			(3,880	)		—			(3,880	)
Net cash provided by (used in) operating activities		48,796			(4,039	)		(240,601	)		560,219			—			364,375
Cash flows from investing activities:
Capital expenditures		—			—			(95,391	)		(140,599	)		—			(235,990	)
Proceeds from sale of property, plant and equipment		—			—			13,970			17,225			—			31,195
Decrease in restricted cash		—			—			—			12,930			—			12,930
Net proceeds from the sale of Partnership units		—			—			109,365			—			—			109,365
Cash invested in non-consolidated affiliates		—			—			—			(609	)		—			(609	)
Investment in consolidated subsidiaries		(50,089	)		112,497			—			—			(62,408	)		—
Net cash provided by (used in) continuing operations		(50,089	)		112,497			27,944			(111,053	)		(62,408	)		(83,109	)
Net cash provided by discontinued operations		—			—			—			89,509			—			89,509
Net cash provided by (used in) investing activities		(50,089	)		112,497			27,944			(21,544	)		(62,408	)		6,400
Cash flows from financing activities:
Proceeds from borrowings of long-term debt		1,627,244			—			—			471,000			—			2,098,244
Repayments of long-term debt		(1,459,836	)		—			—			(1,018,561	)		—			(2,478,397	)
Payments for debt issuance costs		(7,782	)		—			—			(4,252	)		—			(12,034	)
Proceeds from stock options exercised		840			—			—			—			—			840
Proceeds from stock issued pursuant to our employee stock purchase plan		2,224			—			—			—			—			2,224
Purchases of treasury stock		(2,061	)		—			—			—			—			(2,061	)
Stock-based compensation excess tax benefit		1,182			—			—			—			—			1,182
Distribution to noncontrolling partners in the Partnership		—			—			—			(18,030	)		—			(18,030	)
Capital contribution (distribution), net		—			50,089			(112,497	)		—			62,408			—
Borrowings (repayments) between subsidiaries, net		(160,407	)		(158,547	)		321,786			(2,832	)		—			—
Net cash provided by (used in) financing activities		1,404			(108,458	)		209,289			(572,675	)		62,408			(408,032	)
Effect of exchange rate changes on cash and cash equivalents		—			—			—			(1,872	)		—			(1,872	)
Net increase (decrease) in cash and cash equivalents		111			—			(3,368	)		(35,872	)		—			(39,129	)
Cash and cash equivalents at beginning of year		49			—			4,954			78,742			—			83,745
Cash and cash equivalents at end of year	$	160		$	—		$	1,586		$	42,870		$	—		$	44,616

F-49

Condensed Consolidating Statement of Cash Flows

Year Ended December 31, 2009

(In thousands)

	Parent			Subsidiary Issuer			Guarantor Subsidiaries			Other Subsidiaries			Eliminations			Consolidation
Cash flows from operating activities:
Net cash provided by (used in) continuing operations	$	(211,416	)	$	(1,002	)	$	180,901		$	508,325		$	—		$	476,808
Net cash provided by discontinued operations		—			—			—			710			—			710
Net cash provided by (used in) operating activities		(211,416	)		(1,002	)		180,901			509,035			—			477,518
Cash flows from investing activities:
Capital expenditures		—			—			(145,422	)		(223,479	)		—			(368,901	)
Proceeds from sale of property, plant and equipment		—			—			49,609			19,488			—			69,097
Proceeds from sale of business		—			—			5,642			—			—			5,642
Return of investments in non-consolidated affiliates		—			—			—			3,139			—			3,139
Increase in restricted cash		—			—			—			(7,308	)		—			(7,308	)
Cash invested in non-consolidated affiliates		—			—			—			(1,959	)		—			(1,959	)
Investment in consolidated subsidiaries		210,615			211,617			—			—			(422,232	)		—
Net cash provided by (used in) continuing operations		210,615			211,617			(90,171	)		(210,119	)		(422,232	)		(300,290	)
Net cash used in discontinued operations		—			—			—			(710	)		—			(710	)
Net cash provided by (used in) investing activities		210,615			211,617			(90,171	)		(210,829	)		(422,232	)		(301,000	)
Cash flows from financing activities:
Proceeds from issuance of long-term debt		1,104,065			—			—			76,750			—			1,180,815
Repayments of long-term debt		(969,726	)		—			—			(373,059	)		—			(1,342,785	)
Payments for debt issuance costs		(7,411	)		—			—			(4,882	)		—			(12,293	)
Stock-based compensation excess tax benefit		119			—			—			—			—			119
Proceeds from warrants sold		53,138			—			—			—			—			53,138
Payments for call options		(89,408	)		—			—			—			—			(89,408	)
Proceeds from stock issued pursuant to our employee stock purchase plan		2,845			—			—			—			—			2,845
Purchases of treasury stock		(976	)		—			—			—			—			(976	)
Distribution to noncontrolling partners in the Partnership		—			—			—			(15,459	)		—			(15,459	)
Capital distribution, net		—			(210,615	)		(211,617	)		—			422,232			—
Borrowings (repayments) between subsidiaries, net		(91,959	)		—			91,842			117			—			—
Net cash used in financing activities		687			(210,615	)		(119,775	)		(316,533	)		422,232			(224,004	)
Effect of exchange rate changes on cash and cash equivalents		—			—			—			7,325			—			7,325
Net decrease in cash and cash equivalents		(114	)		—			(29,045	)		(11,002	)		—			(40,161	)
Cash and cash equivalents at beginning of year		163			—			33,999			89,744			—			123,906
Cash and cash equivalents at end of year	$	49		$	—		$	4,954		$	78,742		$	—		$	83,745

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24. SUBSEQUENT EVENT

In February 2012, we entered into a Contribution, Conveyance and Assumption Agreement to sell to the Partnership contract operations customer service agreements with approximately 40 customers and a fleet of approximately 400 compressor units used to provide compression services under those agreements, comprising approximately 188,000 horsepower, or 5% (by then available horsepower) of our combined U.S. contract operations business. In addition, the assets to be sold include approximately 140 compressor units, comprising approximately 75,000 horsepower, that we currently lease to the Partnership, and a natural gas processing plant with a capacity of 10 million cubic feet per day used to provide processing services pursuant to a long-term services agreement. Total consideration for the transaction is expected to be approximately $184 million excluding transaction costs. In connection with this transaction, we expect to enter into an amendment to our omnibus agreement with the Partnership that would, among other things, increase the cap on SG&A costs we allocate to the Partnership based on such costs we incur on the Partnership’s behalf and extend the term of the caps on the Partnership’s obligation to reimburse us for SG&A costs and operating costs we allocate to the Partnership based on such costs we incur on the Partnership’s behalf for an additional year such that the caps would now terminate on December 31, 2013.

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EXTERRAN HOLDINGS, INC.

SELECTED QUARTERLY UNAUDITED FINANCIAL DATA

In the opinion of management, the summarized quarterly financial data below contains all appropriate adjustments, all of which are normally recurring adjustments, considered necessary to present fairly our financial position and the results of operations for the respective periods (in thousands, except per share amounts):

	March 31			June 30			September 30			December 31
2011(1):
Revenue from external customers	$	618,479		$	657,572		$	704,478		$	702,941
Gross profit(3)		105,058			91,594			105,714			102,483
Net loss attributable to Exterran stockholders		(30,030	)		(28,026	)		(215,974	)		(66,578	)
Loss per common share attributable to Exterran stockholders:
Basic	$	(0.48	)	$	(0.45	)	$	(3.44	)	$	(1.06	)
Diluted		(0.48	)		(0.45	)		(3.44	)		(1.06	)
2010(2):
Revenue from external customers	$	576,308		$	643,822		$	625,623		$	615,780
Gross profit(3)		128,000			113,251			104,688			46,925
Net income (loss) attributable to Exterran stockholders		16,662			17,526			(17,985	)		(118,028	)
Income (loss) per common share attributable to Exterran stockholders:
Basic	$	0.27		$	0.28		$	(0.29	)	$	(1.90	)
Diluted		0.27			0.28			(0.29	)		(1.90	)

(1) In the third quarter of 2011, we recorded a $196.1 million goodwill impairment charge (see Note 8) and $2.9 million of restructuring charges (see Note 14). In the fourth quarter of 2011, we recorded $8.7 million of restructuring charges.

(2) In the fourth quarter of 2010, we recorded a $142.2 million long-lived asset impairment charge, primarily for idle units we retired from our fleet and expect to sell (see Note 13).

(3) Gross profit is defined as revenue less cost of sales, direct depreciation and amortization expense and long-lived asset impairment charges.

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SCHEDULE II

EXTERRAN HOLDINGS, INC.

VALUATION AND QUALIFYING ACCOUNTS

(In thousands)

			Additions
Description	Balance  at Beginning of Period		Charged to Costs and Expenses		Charged  to Other Accounts		Deductions			Balance at End of Period
Allowance for doubtful accounts deducted from accounts receivable in the balance sheet
2011	$	13,108	$	1,610	$	—	$	3,361	(1)	$	11,357
2010		15,342		4,750		—		6,984	(1)		13,108
2009		13,738		5,929		—		4,325	(1)		15,342
Allowance for obsolete and slow moving inventory deducted from inventories in the balance sheet
2011	$	18,257	$	4,944	$	—	$	6,373	(2)	$	16,828
2010		18,368		2,246		—		2,357	(2)		18,257
2009		16,348		5,314		—		3,294	(2)		18,368
Allowance for deferred tax assets not expected to be realized
2011	$	18,140	$	70,514	$	—	$	12,588	(3)	$	76,066
2010		20,033		5,122		—		7,015	(3)		18,140
2009		15,196		6,952		—		2,115	(3)		20,033

(1) Uncollectible accounts written off, net of recoveries.

(2) Obsolete inventory written off at cost, net of value received.

(3) Reflects expected realization of deferred tax assets and amounts credited to other accounts for stock-based compensation excess tax benefits, expiring net operating losses, changes in tax rates and changes in currency exchange rates.

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