10-K 1 a13-25567_110k.htm ANNUAL REPORT PURSUANT TO SECTION 13 AND 15(D)

Table of Contents

 

 

 

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 the fiscal year ended December 31, 2013

 

or

 

o

 

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 x  No o

 

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

 

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

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) 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.

 

Large accelerated filer x

 

Accelerated filer o

 

 

 

Non-accelerated filer o

 

Smaller reporting company o

(Do not check if a 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 o  No x

 

The aggregate market value of the common stock of the registrant held by non-affiliates as of June 30, 2013 was $906,245,145. 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 18, 2014: 65,948,994 shares.

 


 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the registrant’s definitive proxy statement for the 2014 Meeting of Stockholders, which is expected to be filed with the Securities and Exchange Commission within 120 days after December 31, 2013, are incorporated by reference into Part III of this Form 10-K.

 

 

 



Table of Contents

 

TABLE OF CONTENTS

 

 

 

Page

PART I

Item 1.

Business

2

Item 1A.

Risk Factors

15

Item 1B.

Unresolved Staff Comments

26

Item 2.

Properties

27

Item 3.

Legal Proceedings

27

Item 4.

Mine Safety Disclosures

27

PART II

Item 5.

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

28

Item 6.

Selected Financial Data

30

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

35

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

54

Item 8.

Financial Statements and Supplementary Data

54

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

54

Item 9A.

Controls and Procedures

54

Item 9B.

Other Information

57

PART III

Item 10.

Directors, Executive Officers and Corporate Governance

57

Item 11.

Executive Compensation

57

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

57

Item 13.

Certain Relationships and Related Transactions and Director Independence

58

Item 14.

Principal Accountant Fees and Services

58

PART IV

Item 15.

Exhibits and Financial Statement Schedules

58

SIGNATURES

63

 



Table of Contents

 

PART I

 

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

 

This report contains “forward-looking statements” intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995. All statements other than statements of historical fact contained in this report are forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended (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, impairments, 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;

 

·                  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;

 

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·                           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 or 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. References to “Exterran,” “our,” “we” and “us” refer to Exterran Holdings, Inc. and its subsidiaries. References to “North America” when used in this report refer to the U.S. and Canada. References to “International” and variations thereof when used in this report refer to the world excluding North America.

 

General

 

We are a global market leader in the full-service natural gas compression business and a premier provider of operations, maintenance, service and equipment for oil and natural gas production, processing and transportation applications. Our global customer base consists of companies engaged in all aspects of the oil and natural gas industry, including large integrated oil and natural gas companies, national oil and natural gas companies, independent producers and natural gas processors, gatherers and pipelines. We operate in three primary business lines: contract operations, aftermarket services and fabrication. In our contract operations business line, we use our fleet of natural gas compression equipment and crude oil and natural gas production and processing equipment to provide operations services to our customers. 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. In our fabrication business line, we fabricate compression and oil and natural gas production and processing equipment for sale to our customers and for use 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. We offer our customers, on either a contract operations basis or a sale basis, the engineering, design, project management, procurement and construction services necessary to incorporate our products into production, processing and compression facilities, which we refer to as Integrated Projects.

 

Our products and services are essential to the production, processing, transportation and storage of natural gas and are provided primarily to producers and distributors of oil and natural gas. Our geographic business unit operating structure, technically experienced personnel and high-quality contract operations fleet and fabrication facilities allow us to provide reliable customer service and products in a timely manner.

 

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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, 2013, public unitholders held a 59% ownership interest in the Partnership and we owned the remaining equity interest, including all of the general partner interest and incentive distribution rights. The Partnership’s general partner 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 equity interests in the Partnership. As of December 31, 2013, the Partnership’s fleet included 5,521 compressor units comprising approximately 2,417,000 horsepower, or 70% of our and the Partnership’s combined total U.S. horsepower. The Partnership’s fleet included 274 compressor units, comprising approximately 109,000 horsepower, leased from our wholly-owned subsidiaries and excluded 24 compressor units, comprising approximately 8,000 horsepower, owned by the Partnership but leased to our wholly-owned subsidiaries as of December 31, 2013.

 

In March 2013, we sold to the Partnership contract operations customer service agreements with 50 customers and a fleet of 363 compressor units used to provide compression services under those agreements, comprising approximately 256,000 horsepower, or 8% (by then available horsepower) of our and the Partnership’s combined U.S. contract operations business (the “March 2013 Contract Operations Acquisition”). The assets sold also included 204 compressor units, comprising approximately 99,000 horsepower, previously leased to the Partnership and contracts relating to approximately 6,000 horsepower of compressor units the Partnership already owned and previously leased to us. Total consideration for the transaction was approximately $174.0 million, excluding transaction costs, and consisted of the Partnership’s issuance to us of approximately 7.1 million common units and approximately 145,000 general partner units.

 

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. It 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 (i) at the wellhead, (ii) throughout gathering and distribution systems, (iii) into and out of processing and storage facilities and (iv) along intrastate and interstate pipelines.

 

·                  Wellhead and Gathering Systems — Natural gas compression is used to transport natural gas from the wellhead through the gathering system. 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 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 is used during the transportation of natural gas from the gathering systems to storage or the end user. 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.

 

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Many natural gas 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 owned 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.

 

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 for purchased equipment 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 growing global consumption of natural gas and its byproducts is the predominant force driving the demand for natural gas compression and production and processing equipment. 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, 2013 remained relatively flat compared to the twelve months ended November 30, 2012. The U.S. Energy Information Administration (“EIA”) forecasts that total U.S. natural gas consumption will decrease by 1.3% in 2014 compared to 2013 and increase by an average of 0.7% per year thereafter until 2040. The EIA estimates that the U.S. natural gas consumption level will be approximately 30 trillion cubic feet in 2040, or 16% of the projected worldwide total of approximately 185 trillion cubic feet.

 

Natural gas marketed production in the U.S. for the twelve months ended November 30, 2013 increased by approximately 1.1% over the twelve months ended November 30, 2012. The EIA forecasts that total U.S. natural gas marketed production will increase by 2.2% in 2014 compared to 2013 and U.S. natural gas production will increase by an average of 1.5% per year thereafter until 2040. The EIA estimates that the U.S. natural gas production level will be approximately 33 trillion cubic feet in 2040, or 18% of the projected worldwide total of approximately 187 trillion cubic feet.

 

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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 services to producers of natural gas liquids. In early 2012, natural gas prices in North America fell to their lowest levels in more than a decade, but prices recovered somewhat during 2013. Historically, natural gas prices in North America have been volatile. During periods of lower natural gas prices, natural gas production growth could be limited or decline in North America, 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.

 

The EIA reports that natural gas consumption outside of the U.S. grew 48% from 2000 through 2011. 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 natural gas. Total natural gas consumption worldwide is projected to increase by 1.7% per year until 2040, 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 that continued through 2011. However, we began to see an improvement in market activities in North America in the latter part of 2010 and in 2011. During 2012, our fabrication backlog increased by approximately 45% from December 31, 2011. During 2013, our fabrication backlog decreased by approximately 36% from December 31, 2012. Over 30% of that reduction was related to an installation project for one customer that was completed in 2013. We believe our fabrication backlog has stabilized as of year-end 2013. We have seen a shift in the regional mix of our fabrication backlog since the beginning of 2009, when North America and the Eastern Hemisphere represented approximately 20% and 80%, respectively, of our fabrication backlog. As of December 31, 2013, North America and the Eastern Hemisphere accounted for approximately 43% and 55%, respectively, of 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 products, and therefore increased demand for the equipment, in the regions we serve over the next few years. The reductions in global economic activity led to a substantial reduction in our fabrication backlog levels related to these products during 2011 and 2012. During 2013, we experienced an increase in backlog for these products, resulting in year-end backlog levels similar to those at year-end 2010.

 

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 services to meet specific customer requirements utilizing Exterran-owned assets within the U.S.

 

·                  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. 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.

 

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·                  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 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 worldwide natural gas compressor fleet on December 31, 2013 is summarized in the following table:

 

 

 

 

 

Aggregate

 

 

 

 

 

Number

 

Horsepower

 

% of

 

Range of Horsepower Per Unit

 

of Units

 

(in thousands)

 

Horsepower

 

0 – 200

 

3,601

 

400

 

9

%

201 – 500

 

2,172

 

605

 

13

%

501 – 800

 

681

 

419

 

9

%

801 – 1,100

 

476

 

456

 

10

%

1,101 – 1,500

 

1,360

 

1,849

 

39

%

1,501 and over

 

467

 

955

 

20

%

Total

 

8,757

 

4,684

 

100

%

 

As of December 31, 2013, the Partnership’s fleet included 5,521 of these compressor units comprising approximately 2,417,000 horsepower, or 70% of our and the Partnership’s combined total U.S. horsepower. As of December 31, 2013, the Partnership’s fleet included 274 compressor units, comprising approximately 109,000 horsepower, leased from our wholly-owned subsidiaries and excluded 24 compressor units, comprising approximately 8,000 horsepower, owned by the Partnership but leased to our wholly-owned subsidiaries.

 

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 lower operating costs.

 

Contract Operations — North America and International

 

We provide comprehensive contract operations services, including the personnel, equipment, tools, materials and supplies to meet our customers’ natural gas compression, production or processing service needs. 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.

 

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 natural gas 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 primarily driven by internal natural gas fired combustion engines. We also utilize rotary screw compressors for specialized applications.

 

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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 Integrated 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 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. Following the initial minimum 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 typically do not take title to the natural gas we compress, process or treat and because the natural gas we use as fuel for our compressors and other equipment is supplied by our customers, we have limited direct exposure to commodity price fluctuations.

 

We maintain field service locations from which we can service and overhaul our own compressor fleet to provide contract operations services to our customers. We also use many of these locations to provide aftermarket services to our customers, as described in more detail below. As of December 31, 2013, our North America contract operations segment provided contract operations services primarily using a fleet of 7,765 natural gas compression units with an aggregate capacity of approximately 3,429,000 horsepower. During the year ended December 31, 2013, 20% of our total revenue and 36% 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, 2013, our international contract operations segment provided contract operations services using a fleet of 992 natural gas compression units with an aggregate capacity of approximately 1,255,000 horsepower and a fleet of production and processing equipment. During the year ended December 31, 2013, 15% of our total revenue and 29% 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. During the year ended December 31, 2013, 13% of our total revenue and 9% 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 where we operate.

 

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Generally, we assemble compressors sold to third parties 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. During the year ended December 31, 2013, 15% of our total revenue and 6% of our total gross margin was generated from our compressor and accessory fabrication business line.

 

As of December 31, 2013, our compressor and accessory fabrication backlog was $157.9 million, compared to $256.3 million at December 31, 2012. At December 31, 2013, all future revenue related to our compressor and accessory fabrication backlog is expected to be recognized before December 31, 2014.

 

Production and Processing Equipment Fabrication and Installation

 

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 them 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 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. During the year ended December 31, 2013, 37% of our total revenue and 20% of our total gross margin was generated from our production and processing equipment fabrication and installation business lines.

 

As of December 31, 2013, our production and processing equipment fabrication backlog was $475.6 million, compared to $563.8 million at December 31, 2012. Typically, we expect our production and processing equipment backlog to be produced within a three to 36 month period. At December 31, 2013, $92.1 million of future revenue related to our production and processing equipment backlog is expected to be recognized after December 31, 2014. As of December 31, 2013, our installation backlog was $46.4 million, compared to $245.6 million at December 31, 2012. At December 31, 2013, all future revenue related to our installation backlog is expected to be recognized before December 31, 2014.

 

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 36% of our gross margin during 2013. 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 services to producers of natural gas from shale and liquids rich plays. We intend to utilize the Partnership as our primary vehicle for the long-term growth of our U.S. contract operations business. In addition, increased drilling activity in the shale plays and areas focused on the production of oil and natural gas liquids in North America has led to opportunities in our North America fabrication business.

 

·                  Focus on key international markets.  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 natural gas production in international markets 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 project requirements. We expect to allocate additional resources toward key areas of our international business.

 

·                  Lower costs and improve profitability.  To enhance our competitive position, we embarked on a multi-year plan to improve the profitability of our operations in the second half of 2011. We implemented certain key profitability initiatives associated with this plan in 2012, and implemented additional process initiatives intended to improve operating efficiency and reduce our cost structure throughout 2013. These initiatives have positively impacted all of our business segments, and we expect additional positive impact in 2014. 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.

 

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Competitive Strengths

 

We believe we have the following key competitive strengths:

 

·                  Breadth and quality of product and service offerings.  We provide our customers 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. We believe our contract operations services generally allow our customers that outsource their compression or production and processing needs 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 leverage our core strengths, we believe that we can provide comprehensive integrated solutions to meet our customers’ needs. In our Integrated 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 products and 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 respond to our customers’ needs 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. Since 2006, we have completed eight sales to the Partnership of compressor units aggregating approximately 2.4 million horsepower. The proceeds from these transactions have provided us significant capital to reduce our debt and fund our capital expenditures. As of December 31, 2013, we held a 40% ownership interest in the Partnership’s limited partner units and we owned all of the general partner interest and incentive distribution rights. We believe our ownership interest in the Partnership will allow us to participate in its future growth.

 

Oil and Natural Gas Industry Cyclicality and Volatility

 

Changes in oil and natural gas exploration and production spending normally results in changes in demand for our products and services; however, we believe our contract operations business is typically 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.

 

Because we typically do not take title to the natural gas we compress, process or treat and because the natural gas we use as fuel for our compressors and other equipment is supplied by our customers, our direct exposure to commodity price risk is further reduced.

 

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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.

 

We conduct our contract operations and sales activities 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 and the United Arab Emirates.

 

Sales and Marketing

 

Our salespeople pursue the market for our products in their respective territories. Each salesperson is assigned a customer list or territory based on the individual’s experience and personal relationships and the customers’ service requirements. 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 that 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 to provide contract operations services and to sell 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, we obtain some of the components used in our products 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 we are competitive with respect to price, equipment availability, customer service, flexibility in meeting customer needs, technical expertise, quality and reliability of our compressors and related services. We face vigorous competition in both compression services and compressor fabrication, with some firms competing in both segments. In our production and processing equipment business, we have different competitors in the standard and custom-engineered equipment markets. Competitors in the standard equipment market include several large companies and a large number of small, regional fabricators. Competition in the standard equipment market is generally based upon price and availability. Our competition in the custom-engineered market usually consists of larger companies 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. For the year ended December 31, 2013, approximately 23% of our revenue was generated in the Eastern Hemisphere and approximately 17% of our revenue was generated in Latin America (primarily in Argentina, Bolivia, Brazil and Mexico). Changes in local economic or political conditions could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

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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 primarily in Argentina, Brazil, Italy and Mexico.

 

Additional risks inherent in our international business activities are described in Part I, Item 1A (“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 safety and health. 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 safety and health 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 hazardous and non-hazardous solid wastes; and the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and regulations thereunder, known more commonly as “Superfund,” which imposes liability for the remediation of releases of hazardous substances in the environment. We are also subject to regulation under the federal Occupational Safety and Health Act (“OSHA”) and regulations thereunder, which regulate the protection of the safety and health 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 U.S. 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 would have required us to undertake certain expenditures and activities, 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 certain 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. Following legal challenges to the 2010 rule, the EPA reconsidered the rule and published revisions to the rule on January 30, 2013. The revised rule requires management practices for all covered engines but requires catalyst installation only on larger equipment at sites that are not deemed to be “remote.” Based on feedback from our customers regarding the sites at which we provide contract operations services to them using such equipment, we estimate that the vast majority of those sites are “remote,” and, as such, we do not anticipate these rules, as currently drafted, will have a material adverse impact on our business, financial condition, results of operations or cash flows. Compliance with the final rule was required by October 2013.

 

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On May 21, 2012, the EPA issued new ozone nonattainment designations for all areas except Chicago, in relation to the 2008 national ambient air quality standard (“NAAQS”) for ozone. Among other things, these new designations add Wise County to the Dallas-Fort Worth (“DFW”) nonattainment area. This new designation will require Texas to modify its State Implementation Plan (“SIP”) to include a plan for Wise County, Texas to come into compliance with the ozone NAAQS. This modification process started in January 2014, and the State of Texas anticipates having new regulations in place by mid-2015. If Texas implements the same control requirements in Wise County that are already in place in the other counties in the DFW nonattainment area, we could be required to modify or remove and replace a significant amount of equipment we currently utilize in Wise County. However, at this point we cannot predict what Texas’ new SIP will require or what equipment will still be operating in Wise County when it comes into effect and, as a result, we cannot currently accurately predict the impact or cost to comply.

 

On August 16, 2012, the EPA published final rules that establish new air emission controls for natural gas and natural gas liquids production, processing and transportation activities, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with production and processing activities. Among other things, the rules establish specific requirements regarding emissions from compressors and controllers at natural gas gathering and boosting stations and processing plants together with dehydrators and storage tanks at natural gas processing plants, compressor stations and gathering and boosting stations. In addition, the rules establish new requirements for leak detection and repair of leaks at natural gas processing plants that exceed 500 parts per million in concentration.

 

In addition, in January 2011, the Texas Commission on Environmental Quality (“TCEQ”) finalized revisions to certain air permit programs that significantly increase air emissions-related requirements for new and certain existing oil and gas production and gathering sites in the Barnett Shale production area. The final rule established 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 2020 and 2030 depending on the type of engine and the permitting requirements. A number of other states where our engines are operated have adopted or are considering adopting additional regulations that could impose new air permitting or pollution control requirements for engines, some of which could entail material costs to comply. At this point, however, we cannot predict whether any such rules would require us to incur material costs.

 

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 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. 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 has been pursuing 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. These rules triggered reporting obligations for some sites we operated in 2013.

 

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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. On July 1, 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. On June 29, 2012, the EPA issued final regulations for “Phase III” of its program, retaining the permitting thresholds established in Phases I and II. These rules will 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 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 clean up 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 cleanup 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.

 

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International Operations

 

Our operations outside the U.S. are subject to similar international governmental controls and restrictions pertaining to the environment and other regulated activities in the countries in which we operate. We believe our operations are in substantial compliance with existing international governmental controls and restrictions and that compliance with these international controls and restrictions has not had a material adverse effect on our operations. We cannot provide any assurance, however, that we will not incur significant costs to comply with international controls and restrictions in the future.

 

Employees

 

As of December 31, 2013, we had approximately 10,000 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 Securities and Exchange Commission (“SEC”). Information on our website is not incorporated by reference in this report or any of our other securities filings. Paper copies of our filings are also available, without charge, from Exterran Holdings, Inc., 16666 Northchase Drive, Houston, Texas 77060, Attention: Investor Relations. Alternatively, the public may read and copy any materials we file with the SEC at its 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, results of operations and cash flows could be negatively impacted.

 

Low natural gas prices in North America could decrease demand for our natural gas compression and oil and natural gas production and processing equipment and services and, as a result, 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. In April 2012, natural gas prices in North America fell to their lowest levels in more than a decade at around $2.00 per MMBtu. As a result, certain companies reduced their natural gas drilling and production activities, particularly in more mature and predominantly dry gas areas in North America, where we provide a significant amount of contract operations services, which led to a decline in our contract operation business in these areas during 2012. Since then, natural gas prices in North America have improved somewhat to approximately $4.30 per MMBtu as of December 31, 2013, but natural gas prices in 2013 continued to cause certain companies to reduce their natural gas drilling and production activities in more mature and predominantly dry gas areas in North America, which led to a continued decline in our contract operations business in these areas in 2013. During periods of lower natural gas prices, natural gas production growth could be limited or decline in North America, particularly in dry gas areas, and 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 effect 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 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.

 

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 impairments of long-lived assets. For example, during the year ended December 31, 2011, we recorded a goodwill impairment of $196.8 million; and during the years ended December 31, 2013, 2012 and 2011, we recorded long-lived asset impairments of $28.6 million, $136.6 million and $6.1 million, respectively. Included in the impairments recorded in recent years are idle units we retired from our fleet, and we expect to either sell these units or to re-utilize their key components. Selling these compressor units is expected to take several years, and if we are not able to sell these units or re-utilize their key components 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.

 

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

 

Some of our projects have a relatively larger size and scope than the majority of our projects, which 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.

 

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

 

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

 

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

 

We operate in many countries outside the U.S., and these activities accounted for a substantial amount of our revenue during the year ended December 31, 2013. We are exposed to risks inherent in doing business in each of the countries where 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.

 

In April 2012, Argentina assumed control over its largest oil and gas producer, Yacimientos Petroliferos Fiscales (“YPF”). We had approximately 539,000 horsepower of compression in Argentina as of December 31, 2013, and we generated $186.7 million of revenue in Argentina, including $81.5 million of revenue from YPF, during the year ended December 31, 2013. We are unable to predict what effect, if any, the nationalization of YPF will have on our business in Argentina, or whether Argentina will nationalize additional businesses in the oil and gas industry; however, the nationalization of YPF, the nationalization of additional businesses or the taking of other actions listed below by Argentina could have a material adverse effect on our business, financial condition, results of operations and cash flows.

 

More generally in Argentina, the ongoing social, political, economic and legal climate has given rise to significant uncertainties about the country’s economic and political future. Since the presidential election in late 2011, the Argentine government has increasingly used foreign-exchange, price, trade and capital controls to attempt to address the country’s economic challenges. Because Argentina’s current regulations restrict foreign exchange, including exchanging Argentine pesos for U.S. dollars in certain cases, we are unable to repatriate earnings from Argentina and therefore the cash flow from our operations in Argentina may not be a reliable source of funding for our operations outside of Argentina, which could limit our ability to grow. In addition, our inability to exchange Argentine pesos for U.S. dollars subjects us to risk of currency devaluation on future earnings in Argentina.

 

In addition, the Argentine government may adopt additional regulations or policies in the future that may materially impact, among other things, (i) the timing of and our ability to repatriate cash from Argentina to the U.S. and other jurisdictions, (ii) the value of our assets and business in Argentina and (iii) our ability to import into Argentina the materials necessary for our operations. Any such changes could have a material adverse effect on the profitability of our operations or on our ability to continue operations in certain areas.

 

With respect to any particular country in which we operate, the risks inherent in our activities may 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;

 

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·                  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;

 

·                  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 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 are due to receive a substantial amount in installment payments from the purchaser of our previously nationalized Venezuelan assets, the nonpayment of which would reduce the anticipated amount of funds available to us to repay indebtedness and for general corporate purposes.

 

As discussed in Notes 2 and 7 to the Financial Statements, in March 2012 and August 2012, we sold our previously-nationalized Venezuelan joint venture assets and Venezuelan subsidiary assets, respectively, to PDVSA Gas, S.A. (“PDVSA Gas”), a subsidiary of PDVSA, for aggregate consideration of approximately $550 million. As of December 31, 2013, we have received payments, including annual charges, of approximately $334 million ($50 million of which we used to repay insurance proceeds previously collected under the policy we maintained for the risk of expropriation) and are due to receive the remaining principal amount of approximately $221 million in installments through the third quarter of 2016. We intend to use these remaining proceeds, as they are received, for the repayment of indebtedness and for general corporate purposes. Any failure by PDVSA Gas to pay these installments when due would reduce the amount of funds available to us in the future for these purposes. PDVSA’s payments to many of its suppliers and partners are currently significantly in arrears. Additionally, in recent weeks protests against the Venezuelan government have intensified, and the ongoing social, political, economic and legal climate has given rise to significant uncertainties about the country’s economic and political stability. Since the presidential election in the first half of 2013, the Venezuelan government has increasingly used foreign-exchange, price and capital controls to attempt to address the country’s economic challenges. If the recent political unrest were to develop into a prolonged period of governmental or economic instability, or if PDVSA becomes increasingly unable to pay its suppliers and partners, our ability to recover in full the remaining proceeds from PDVSA Gas could be adversely impacted.

 

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We could be adversely affected by violations of the U.S. Foreign Corrupt Practices Act, similar worldwide anti-bribery laws and trade control 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 compliance policies and programs may not be completely effective in ensuring our compliance with anti-bribery laws. 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 reputation, business, financial condition, results of operations and cash flows.

 

We also are subject to other laws and regulations governing our operations, including regulations administered by the U.S. Department of Treasury’s Office of Foreign Asset Control and various non-U.S. government entities, including applicable export control regulations, economic sanctions on countries and persons and customs requirements. Trade control laws are complex and constantly changing, and compliance with them increases our cost of doing business. Our compliance policies and programs may not be completely effective in ensuring our compliance with trade control laws. If we are not in compliance with these laws, we may be subject to criminal and civil penalties and other sanctions and remedial measures, and we may incur legal expenses, which could have a material adverse impact on our reputation, business, financial condition, results of operations and cash flows. Any investigation of any potential violations of trade control laws by U.S. or foreign authorities could have a material adverse impact on our reputation, business, financial condition, results of operations and cash flows.

 

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

 

We operate in many international countries. We anticipate that there will be instances in which costs and revenues will not be exactly matched with respect to currency denomination. We generally do not hedge exchange rate exposures, which exposes us to the risk of exchange rate losses. Gains and losses from the remeasurement of assets and liabilities that are receivable or payable in currency other than our subsidiaries’ functional currency are included in our consolidated statements of operations. In addition, currency fluctuations cause the U.S. dollar value of our international results of operations and net assets to vary with exchange rate fluctuations. This could have a negative impact on our business, financial condition or results of operations. In addition, fluctuations in currencies relative to currencies in which the earnings are generated may make it more difficult to perform period-to-period comparisons of our reported results of operations. For example, other (income) expense, net, during the year ended December 31, 2013 includes a foreign currency loss of $3.0 million compared to a loss of $8.2 million during the year ended December 31, 2012.

 

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.

 

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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, financial condition and results of operations.

 

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, 2013, we had approximately $1.5 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 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, 2013, we maintained a 10.7 to 1.0 Adjusted EBITDA to Total Interest Expense ratio, a 1.6 to 1.0 consolidated Total Debt to Adjusted EBITDA ratio and a 0.1 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 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 would trigger cross-default provisions under certain of our other debt agreements, which would accelerate our obligation to repay our indebtedness under those agreements. As of December 31, 2013, we were in compliance with all financial covenants under our debt agreements.

 

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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 the Partnership’s ability to incur additional indebtedness, engage in transactions with affiliates, merge or consolidate, sell assets, make certain investments and acquisitions, make loans, grant liens, repurchase equity and pay dividends and distributions. The Partnership Credit Agreement also contains various covenants requiring mandatory prepayments from the net cash proceeds of certain asset transfers. The Partnership must maintain various consolidated financial ratios, including a ratio of EBITDA (as defined in the Partnership Credit Agreement) to Total Interest Expense (as defined in the Partnership Credit Agreement) of not less than 2.75 to 1.0, a ratio of Total Debt (as defined in the Partnership Credit Agreement) to EBITDA of not greater than 5.25 to 1.0 (subject to a temporary increase to 5.5 to 1.0 for any quarter during which an acquisition meeting certain thresholds is completed and for the following two quarters after the acquisition closes) and a ratio of Senior Secured Debt (as defined in the Partnership Credit Agreement) to EBITDA of not greater than 4.0 to 1.0. As of December 31, 2013, the Partnership maintained a 7.5 to 1.0 EBITDA to Total Interest Expense ratio, a 3.1 to 1.0 Total Debt to EBITDA ratio and a 1.7 to 1.0 Senior Secured Debt to EBITDA ratio. A material adverse effect with respect to the Partnership’s assets, liabilities, financial condition, business or operations that, taken as a whole, impacts the Partnership’s ability to perform its obligations under the Partnership Credit Agreement, could lead to a default under that agreement. A default under one of the Partnership’s debt agreements would trigger cross-default provisions under the Partnership’s other debt agreement, which would accelerate the Partnership’s obligation to repay its indebtedness under those agreements. As of December 31, 2013, the Partnership was in compliance with all financial covenants under the Partnership Credit Agreement.

 

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. If the repayment obligations on any of our indebtedness were to be 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.

 

While we recently declared a dividend of $0.15 per share of common stock, there can be no assurance that we will pay dividends in the future.

 

On February 25, 2014, our Board of Directors declared a cash dividend of $0.15 per share of common stock to shareholders of record on March 14, 2014. We cannot provide assurance that we would, at any time in the future, again generate sufficient surplus cash that would be available for distribution to the holders of our common stock as a dividend or that our board of directors would determine to use any such surplus or our net profits to pay a dividend.

 

Future dividends may be affected by, among other factors:

 

·                  the availability of surplus or net profits, which in turn depend on the performance of our business;

 

·                  our future capital requirements; and

 

·                  changes in federal and state income tax laws or corporate laws.

 

We cannot provide assurance that we will declare or pay dividends in any particular amounts or at all in the future. A decision not to pay dividends or a reduction in our dividend payments in the future could have a negative effect on our stock price.

 

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

 

As of December 31, 2013, after taking into consideration interest rate swaps, we had $212.0 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 at December 31, 2013 would result in an annual increase in our interest expense of approximately $2.1 million.

 

Many of our North America contract operations services contracts have short initial terms and after the initial term are cancelable on short notice, and we cannot be sure that such contracts will be extended or renewed after the end of the initial contractual term. Any such nonrenewals, or renewals at reduced rates, or the loss of contracts with any significant customer, could adversely impact our results of operations.

 

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 recoup the cost of the equipment we utilize to provide contract operations services and these contracts are typically cancelable on short notice after the initial term. We cannot be sure that a substantial number of these contracts will be extended or renewed by our customers or that any of our customers will continue to contract with us. The inability to negotiate extensions or renew a substantial portion of our North America contract operations services contracts, the renewal of such contracts at reduced rates, the inability to contract for additional services with our customers or the loss of all or a significant portion of our services contracts with any significant customer could lead to a reduction in revenues and net income and could require us to record additional asset impairments. This could have a material adverse effect upon our business, financial condition, results of operations and cash flows.

 

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.

 

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From time to time, we are subject to various claims, litigation and other proceedings that could ultimately be resolved against us, requiring material future cash payments or charges, which could impair our financial condition or results of operations.

 

The size, nature and complexity of our business make us susceptible to various claims, both in litigation and binding arbitration proceedings. We are currently, and may in the future become, subject to various claims, which, if not resolved within amounts we have accrued, could have a material adverse effect on our financial position, results of operations or cash flows. Similarly, any claims, even if fully indemnified or insured, could negatively impact our reputation among our customers and the public, and make it more difficult for us to compete effectively or obtain adequate insurance in the future. See Note 20 to the Financial Statements for additional information regarding certain legal proceedings to which we are a party, including ongoing litigation regarding our qualification as a heavy equipment dealer, the qualification of our natural gas compressors as heavy equipment and the resulting appraisal of our natural gas compressors for ad valorem tax purposes under revised Texas statutes.

 

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. We do not have long-term contracts with some of these sources, and 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 businesses are highly competitive and there are low barriers to entry, especially our natural gas compression services and fabrication business. Our competitors may be able to adapt more quickly to technological changes within our industry and changes in economic and market conditions, 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. 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. If our competitors substantially increase the resources they devote to the development and marketing of competitive products, equipment or services or substantially decrease the price at which they offer their products, equipment or services, we may not be able to compete effectively.

 

In addition, we could face significant competition from new entrants into the compression services and fabrication business. Some of our existing competitors or new entrants may expand or fabricate new compression units that would create additional competition for the products, equipment or services we provide to our customers.

 

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

 

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 workers’ 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 are not able to obtain liability insurance, our business, financial condition and results of operations could be negatively impacted.

 

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, financial condition and results of operations.

 

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 results of operations. In addition, these types of events could require significant management attention and resources, and could adversely affect our reputation among customers and the public.

 

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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, including the Partnership common units we own, and the amount of distributions that we receive from the Partnership.

 

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

 

The tax treatment of publicly traded partnerships or our investment in the Partnership’s common units 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 from time to time, members of Congress may propose and consider substantive changes to the existing U.S. federal income tax laws that could affect publicly traded partnerships. One such legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations, upon which the Partnership relies for its treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes, or other proposals, will be reconsidered or will ultimately be enacted. 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 the Partnership to be treated as a partnership for U.S. federal income tax purposes. 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.

 

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, including the Partnership common units we own, and the amount of distributions that we receive from the Partnership.

 

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Federal, state and local 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 EPA has asserted federal regulatory authority under the federal Safe Drinking Water Act over hydraulic fracturing involving the use of diesel. In addition, a number of agencies including EPA, the U.S. Department of Energy, and the U.S. Department of the Interior, along with Congressional committees, have been pursuing studies and other inquiries into the potential environmental effects of hydraulic fracturing, the outcome of which could reach conclusions that could give rise to new legislation or regulations. 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. The U.S. Bureau of Land Management on May 24, 2013 proposed regulations that, when finalized, will govern hydraulic fracturing on public lands. 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. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. 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.

 

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 would have required us to undertake certain expenditures and activities, 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 certain 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. Following legal challenges to the 2010 rule, the EPA reconsidered the rule and published revisions to the rule on January 30, 2013. The revised rule requires management practices for all covered engines but requires catalyst installation only on larger equipment at sites that are not deemed to be “remote.” Based on feedback from our customers regarding the sites at which we provide contract operations services to them using such equipment, we estimate that the vast majority of those sites are “remote,” and, as such, we do not anticipate these rules, as currently drafted, will have a material adverse impact on our business, financial condition, results of operations or cash flows.

 

On May 21, 2012, the EPA issued new ozone nonattainment designations for all areas except Chicago, in relation to the 2008 NAAQS for ozone. Among other things, these new designations add Wise County, Texas to the DFW nonattainment area. This new designation will require Texas to modify its SIP to include a plan for Wise County to come into compliance with the ozone NAAQS. This modification process started in January 2014, and the State of Texas anticipates having new regulations in place by mid-2015. If Texas implements the same control requirements in Wise County that are already in place in the other counties in the DFW nonattainment area, we could be required to modify or remove and replace a significant amount of equipment we currently utilize in Wise County. However, at this point we cannot predict what Texas’ new SIP will require or what equipment will still be operating in Wise County when it comes into effect and, as a result, we cannot currently accurately predict the impact or cost to comply.

 

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On August 16, 2012, the EPA published final rules that establish new air emission controls for natural gas and natural gas liquids production, processing and transportation activities, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with production and processing activities. Among other things, the rules establish specific requirements regarding emissions from compressors and controllers at natural gas gathering and boosting stations and processing plants together with dehydrators and storage tanks at natural gas processing plants, compressor stations and gathering and boosting stations. In addition, the rules establish new requirements for leak detection and repair of leaks at natural gas processing plants that exceed 500 parts per million in concentration.

 

In addition, in January 2011, the TCEQ finalized revisions to certain air permit programs that significantly increase air emissions-related requirements for new and certain existing oil and gas production and gathering sites in the Barnett Shale production area. The final rule established 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 2020 and 2030 depending on the type of engine and the permitting requirements. A number of other states where our engines are operated have adopted or are considering adopting additional regulations that could impose new air permitting or pollution control requirements for engines, some of which could entail material costs to comply. At this point, however, we cannot predict whether any such rules would require us to incur material costs.

 

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.

 

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.

 

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

 

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

 

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

 

The U.S. Congress has considered legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane. 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 has been pursuing 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. These rules triggered reporting obligations for some sites we operated in 2013.

 

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. On July 1, 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. On June 29, 2012, the EPA issued final regulations for “Phase III” of its program, retaining the permitting thresholds established in Phases I and II. These rules will 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 and/or distributions from 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 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 independent directors;

 

·                  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, 2013:

 

Location

 

Status

 

Square Feet

 

Uses

Houston, Texas

 

Leased

 

243,746

 

Corporate office

Oklahoma City, Oklahoma

 

Leased

 

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

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

 

86,112

 

International contract operations and aftermarket services

Neuquen, Argentina

 

Leased

 

47,500

 

International contract operations and aftermarket services

Reynosa, Mexico

 

Owned

 

24,347

 

International contract operations and aftermarket services

Comodoro Rivadavia, Argentina

 

Owned

 

26,000

 

International contract operations and aftermarket services

Neuquen, Argentina

 

Owned

 

38,798

 

International contract operations and aftermarket services

Santa Cruz, Bolivia

 

Leased

 

22,017

 

International contract operations and aftermarket services

Bangkok, Thailand

 

Leased

 

36,611

 

Aftermarket services

Port Harcourt, Nigeria

 

Leased

 

19,031

 

Aftermarket services

Broussard, Louisiana

 

Owned

 

74,402

 

Fabrication, North America contract operations and aftermarket services

Houston, Texas

 

Owned

 

343,750

 

Fabrication

Houston, Texas

 

Owned

 

261,600

 

Fabrication

Schulenburg, Texas

 

Owned

 

22,675

 

Fabrication

Broken Arrow, Oklahoma

 

Owned

 

141,549

 

Fabrication

Columbus, Texas

 

Owned

 

219,552

 

Fabrication

Youngstown, Ohio

 

Leased

 

65,000

 

Fabrication

Jebel Ali Industrial Area, 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.

 

Item 3.  Legal Proceedings

 

A description of certain legal proceedings can be found in Litigation and Claims in Note 20 (“Commitments and Contingencies”) to the Financial Statements included in this report and is incorporated by reference into this Item 3.

 

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 Range

 

 

 

High

 

Low

 

Year Ended December 31, 2012

 

 

 

 

 

First Quarter

 

$

15.23

 

$

8.79

 

Second Quarter

 

$

14.31

 

$

10.58

 

Third Quarter

 

$

20.47

 

$

12.57

 

Fourth Quarter

 

$

22.23

 

$

19.09

 

Year Ended December 31, 2013

 

 

 

 

 

First Quarter

 

$

27.40

 

$

22.01

 

Second Quarter

 

$

30.26

 

$

23.25

 

Third Quarter

 

$

32.55

 

$

27.07

 

Fourth Quarter

 

$

34.48

 

$

26.50

 

 

On February 18, 2014, the closing price of our common stock was $36.20 per share. As of February 11, 2014, there were approximately 1,450 holders of record of our common stock.

 

The performance graph below shows the cumulative total stockholder return on our 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, 2008. The results are based on an investment of $100 in each of our 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.

 

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

 

We have not paid any cash dividends on our common stock since our formation through the year ended December 31, 2013. On February 25, 2014, we announced that our board of directors declared an initial quarterly dividend of $0.15 per share of common stock, a rate of $0.60 per share on an annualized basis, to be paid on March 28, 2014 to stockholders of record at the close of business on March 14, 2014. Any future determinations to pay cash dividends to our stockholders will be at the discretion of our board of directors and will be dependent upon our financial condition and results of operations, credit and loan agreements in effect at that time and other factors deemed relevant by our board of directors.

 

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

 

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Item 6.  Selected Financial Data

 

The table below shows certain selected financial data for Exterran for each of the five years in the period ended December 31, 2013, which has been derived from our audited Financial Statements. As discussed in Note 2 to the Financial Statements, the results from continuing operations for all periods presented exclude the results of our Venezuelan contract operations business, Canadian contract operations and aftermarket services businesses (“Canadian Operations”) and contract water treatment business. Those results are reflected in discontinued operations for all periods presented. 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,

 

 

 

2013

 

2012

 

2011

 

2010

 

2009

 

Statement of Operations Data:

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

3,160,404

 

$

2,794,246

 

$

2,612,625

 

$

2,394,037

 

$

2,637,552

 

Gross margin(1)

 

963,006

 

829,408

 

720,414

 

784,707

 

885,783

 

Selling, general and administrative

 

358,173

 

375,647

 

352,096

 

350,709

 

331,801

 

Depreciation and amortization

 

327,505

 

346,177

 

352,793

 

387,571

 

338,812

 

Long-lived asset impairment(2)

 

28,637

 

136,614

 

6,068

 

143,874

 

96,988

 

Restructuring charges(3)

 

 

6,471

 

11,594

 

 

13,864

 

Goodwill impairment(4)

 

 

 

196,807

 

 

150,778

 

Interest expense

 

115,745

 

134,376

 

149,473

 

136,149

 

122,845

 

Equity in (income) loss of non-consolidated affiliates(5)

 

(19,000

)

(51,483

)

471

 

609

 

91,154

 

Other (income) expense, net(6)

 

(24,501

)

506

 

(5,597

)

(11,481

)

(51,856

)

Provision for (benefit from) income taxes

 

84,719

 

(45,755

)

(11,717

)

(64,559

)

47,853

 

Income (loss) from continuing operations

 

91,728

 

(73,145

)

(331,574

)

(158,165

)

(256,456

)

Income (loss) from discontinued operations, net of tax(7)

 

64,014

 

35,976

 

(8,044

)

44,924

 

(289,007

)

Net income (loss) attributable to noncontrolling interest

 

32,578

 

2,317

 

990

 

(11,416

)

3,944

 

Net income (loss) attributable to Exterran stockholders

 

123,164

 

(39,486

)

(340,608

)

(101,825

)

(549,407

)

Income (loss) from continuing operations attributable to Exterran stockholders per common share:

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

0.90

 

$

(1.19

)

$

(5.31

)

$

(2.37

)

$

(4.24

)

Diluted

 

$

0.89

 

$

(1.19

)

$

(5.31

)

$

(2.37

)

$

(4.24

)

Weighted average common and equivalent shares outstanding:

 

 

 

 

 

 

 

 

 

 

 

Basic

 

65,655

 

63,436

 

62,624

 

61,995

 

61,406

 

Diluted

 

66,204

 

63,436

 

62,624

 

61,995

 

61,406

 

Other Financial Data:

 

 

 

 

 

 

 

 

 

 

 

EBITDA, as adjusted(8)

 

$

633,647

 

$

460,661

 

$

388,089

 

$

434,361

 

$

576,817

 

Capital expenditures:

 

 

 

 

 

 

 

 

 

 

 

Contract Operations Equipment:

 

 

 

 

 

 

 

 

 

 

 

Growth

 

$

231,195

 

$

261,548

 

$

132,986

 

$

126,546

 

$

244,289

 

Maintenance

 

95,197

 

100,208

 

90,477

 

69,257

 

80,148

 

Other

 

65,333

 

66,975

 

48,687

 

35,610

 

36,308

 

Cash flows provided by (used in):

 

 

 

 

 

 

 

 

 

 

 

Operating activities

 

$

355,704

 

$

389,925

 

$

120,443

 

$

366,313

 

$

479,870

 

Investing activities

 

(196,451

)

(205,451

)

(239,184

)

(102,965

)

(301,000

)

Financing activities

 

(156,702

)

(171,290

)

99,290

 

(298,667

)

(224,004

)

Balance Sheet Data:

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

35,665

 

$

34,601

 

$

21,903

 

$

44,361

 

$

81,552

 

Working capital(9)

 

580,425

 

463,429

 

454,046

 

402,401

 

582,128

 

Property, plant and equipment, net

 

2,820,272

 

2,838,719

 

2,911,711

 

2,990,284

 

3,299,996

 

Total assets

 

4,227,157

 

4,254,847

 

4,360,662

 

4,741,536

 

5,292,948

 

Long-term debt

 

1,502,155

 

1,564,923

 

1,773,039

 

1,897,147

 

2,260,936

 

Total Exterran stockholder’s equity

 

1,662,090

 

1,478,613

 

1,437,236

 

1,609,448

 

1,639,997

 

 


(1)                  Gross margin, a non-GAAP financial measure, is defined, reconciled to net income (loss) and discussed further below under “Non-GAAP Financial Measures.”

 

(2)                  Year ended December 31, 2013: During 2013, we evaluated the future deployment of our idle fleet and determined to retire and either sell or re-utilize the key components of approximately 280 idle compressor units, representing approximately 76,000 horsepower, previously used to provide services in our North America contract operations segment. As a result, we performed an impairment review and recorded a $14.9 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 either the expected net sale proceeds compared to other fleet units we recently sold and/or a review of other units recently offered for sale by third parties, or the estimated component value of the equipment we plan to use.

 

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In July 2013, as part of our continued emphasis on simplification and focus on our core business, we sold the entity that owned our fabrication facility in the United Kingdom. As a result, we recorded impairment charges of $11.9 million during the year ended December 31, 2013.

 

During 2013, we evaluated other long-lived assets for impairment and recorded long-lived asset impairments of $1.8 million on these assets.

 

Year ended December 31, 2012: During 2012, we evaluated the future deployment of our idle fleet and determined to retire and either sell or re-utilize the key components of approximately 930 idle compressor units, representing approximately 318,000 horsepower, previously used to provide services in our North America contract operations segment. As a result, we performed an impairment review and recorded a $97.1 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 either the expected net sale proceeds compared to other fleet units we recently sold and/or a review of other units recently offered for sale by third parties, or the estimated component value of the equipment we plan to use.

 

In connection with our 2012 fleet review, we evaluated for impairment idle units that had been culled from our fleet in prior years and were available for sale. Based upon that review, we reduced the expected proceeds from disposition for most of the remaining units and increased the weighted average disposal period for the units from the assumptions used in prior periods. This resulted in an additional impairment of $34.8 million to reduce the book value of each unit to its estimated fair value.

 

During 2012, we evaluated other long-lived assets for impairment and recorded long-lived asset impairments of $4.7 million on these assets.

 

Year ended December 31, 2011: During 2011, we reviewed our idle compression assets used in our contract operations segments for units that were not of the type, configuration, make or model that are cost effective to maintain and operate. As a result, we performed an impairment review and recorded a $5.7 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 either the expected net sale proceeds compared to other fleet units we recently sold and/or a review of other units recently offered for sale by third parties, or the estimated component value of the equipment we plan to use.

 

During 2011, we evaluated other long-lived assets for impairment and recorded long-lived asset impairments of $0.4 million on these assets.

 

Year ended December 31, 2010: During 2010, we completed an evaluation of our longer-term strategies and determined to retire and sell approximately 1,800 idle compressor units, representing approximately 600,000 horsepower, previously used to provide services in our North America and international contract operations businesses. As a result, we performed an impairment review and recorded a $133.0 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 either the expected net sale proceeds compared to other fleet units we recently sold and/or a review of other units recently offered for sale by third parties. During 2010, we also 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 effective to maintain and operate and determined to retire 323 units representing 61,400 horsepower 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 assets. As a result, we recorded a $7.6 million asset impairment to reduce the book value of each unit to its estimated fair value. In addition, in the fourth quarter of 2010, 105 fleet units previously used in our international contract operations segment were damaged in a flood, resulting in a long-lived asset impairment of $3.3 million.

 

Year ended December 31, 2009: As a result of a decline in market conditions and operating horsepower in North America during 2009, we reviewed our idle compression assets used in our contract operations segments for units that were not of the type, configuration, make or model that were cost effective to maintain and operate and determined to retire from the fleet 1,232 units, representing 264,900 horsepower. 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 we would no longer utilize in our operations. As a result, we recorded a $91.0 million asset impairment to reduce the book value of each unit to its estimated fair value. In addition, during the year ended December 31, 2009, we recorded $6.0 million of facility impairments.

 

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(3)                  Years ended December 31, 2012 and 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 resulted from a review of our cost structure aimed at identifying ways to reduce our on-going operating costs and adjust the size of our workforce to be consistent with then current and expected activity levels.

 

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 resulted from significant fabrication capacity following 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.

 

(4)                  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 our remaining goodwill during 2011 of $196.8 million.

 

Year ended December 31, 2009: As discussed in Note 2 to the Financial Statements, in June 2009 PDVSA assumed control over substantially all of our assets and operations in Venezuela. As a result, 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 income (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.

 

(5)                  Years ended December 31, 2013 and 2012: As discussed in Note 7 to the Financial Statements, in March 2012, our Venezuelan joint ventures sold their assets to PDVSA Gas. We received an initial payment of $37.6 million in March 2012, and received installment payments, including an annual charge, totaling $19.0 million and $14.1 million during the years ended December 31, 2013 and 2012, respectively. The remaining principal amount due to us of approximately $39 million as of December 31, 2013, is payable in quarterly cash installments through the first quarter of 2016. We have not recognized amounts payable to us by PDVSA Gas as a receivable and will therefore recognize quarterly payments received in the future as equity in (income) loss of non-consolidated affiliates in our consolidated statements of operations in the periods such payments are received. In connection with the sale of our Venezuelan joint ventures’ assets, the joint ventures and our joint venture partners have agreed to suspend their previously filed arbitration proceeding against Venezuela pending payment in full by PDVSA Gas of the purchase price for the assets.

 

Year ended December 31, 2009: In the first quarter of 2009, we reviewed our investment in our Venezuelan joint ventures, and based on the expected cash flows to be received from our investment, we recorded an impairment of $96.6 million.

 

(6)                  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 our subsidiary that owned a barge mounted processing plant and certain other related assets used on the Cawthorne Channel Project in Nigeria 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.

 

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(7)                  Years ended December 31, 2013 and 2012: As discussed in Note 2 to the Financial Statements, in August 2012, our Venezuelan subsidiary sold its previously nationalized assets to PDVSA Gas for a purchase price of approximately $441.7 million. We received an initial payment of $176.7 million in cash at closing, of which we remitted $50.0 million to repay the amount we collected in January 2010 under the terms of an insurance policy we maintained for the risk of expropriation. We received installment payments, including an annual charge, totaling $69.3 million and $16.8 million during the years ended December 31, 2013 and 2012, respectively. The remaining principal amount due to us of approximately $182 million as of December 31, 2013, is payable in quarterly cash installments through the third quarter of 2016. We have not recognized amounts payable to us by PDVSA Gas as a receivable and will therefore recognize quarterly payments received in the future as income from discontinued operations in the periods such payments are received. The proceeds from the sale of the assets are not subject to Venezuelan national taxes due to an exemption allowed under the Venezuelan Reserve Law applicable to expropriation settlements. In addition, and in connection with the sale, we and the Venezuelan government agreed to waive rights to assert certain claims against each other. We therefore recorded a reduction in previously unrecognized tax benefits, resulting in a $15.5 million benefit reflected in income (loss) from discontinued operations, net of tax, in our consolidated statements of operations during the year ended December 31, 2012.

 

In June 2012, we committed to a plan to sell our Canadian Operations as part of our continued emphasis on simplification and focus on our core businesses. Our Canadian Operations are reflected as discontinued operations in our Financial Statements. These operations were previously included in our North American contract operations and aftermarket services business segments. In connection with the planned disposition, we recorded impairment charges totaling $6.4 million and $80.2 million during the years ended December 31, 2013 and 2012, respectively. The impairment charges are reflected in income (loss) from discontinued operations, net of tax, in our consolidated statements of operations.

 

In July 2013, we completed the sale of our Canadian Operations. We received the following consideration for the sale of the Canadian Operations (specified in either U.S. dollars (“$”) or Canadian dollars (“CDN$”)): (i) cash proceeds of $12.3 million, net of transaction expenses, (ii) a note receivable of CDN$8.1 million, (iii) contingent consideration of CDN$5.0 million based upon the Canadian Operations reaching a specified performance threshold prior to December 31, 2016 and (iv) a potential tax refund related to the Canadian Operations of CDN$1.6 million if such amounts are received by the Canadian Operations.

 

In December 2013, we abandoned our contract water treatment business as part of our continued emphasis on simplification and focus on our core businesses. The abandonment of this business meets the criteria established for recognition as discontinued operations under GAAP. Therefore, our contract water treatment business is reflected as discontinued operations in our Financial Statements. This business was previously included in our North American contract operations business segment. During the years ended December 31, 2013 and 2012, we evaluated our contract water treatment business and recorded impairment charges of $2.4 million and $46.8 million, respectively. The impairment charges are reflected in income (loss) from discontinued operations, net of tax, in our consolidated statements of operations.

 

Year ended December 31, 2009: As discussed in Note 2 to the Financial Statements, in June 2009, PDVSA assumed control over substantially all of our assets and operations in Venezuela. As a result, 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.

 

(8)                  EBITDA, as adjusted, a non-GAAP financial measure, is defined, reconciled to net income (loss) and discussed further below under “Non-GAAP Financial Measures.”

 

(9)                  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 to evaluate 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 our SG&A activities, the impact of our financing methods and income taxes. Depreciation and amortization 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.

 

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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 statements 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 to support our operations and required corporate activities. To compensate for these limitations, management uses this non-GAAP measure as a supplemental measure to other GAAP results to provide a more complete understanding of our performance.

 

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

 

 

 

Years Ended December 31,

 

 

 

2013

 

2012

 

2011

 

2010

 

2009

 

Net income (loss)

 

$

155,742

 

$

(37,169

)

$

(339,618

)

$

(113,241

)

$

(545,463

)

Selling, general and administrative

 

358,173

 

375,647

 

352,096

 

350,709

 

331,801

 

Depreciation and amortization

 

327,505

 

346,177

 

352,793

 

387,571

 

338,812

 

Long-lived asset impairment

 

28,637

 

136,614

 

6,068

 

143,874

 

96,988

 

Restructuring charges

 

 

6,471

 

11,594

 

 

13,864

 

Goodwill impairment

 

 

 

196,807

 

 

150,778

 

Interest expense

 

115,745

 

134,376

 

149,473

 

136,149

 

122,845

 

Equity in (income) loss of non-consolidated affiliates

 

(19,000

)

(51,483

)

471

 

609

 

91,154

 

Other (income) expense, net

 

(24,501

)

506

 

(5,597

)

(11,481

)

(51,856

)

Provision for (benefit from) income taxes

 

84,719

 

(45,755

)

(11,717

)

(64,559

)

47,853

 

(Income) loss from discontinued operations, net of tax

 

(64,014

)

(35,976

)

8,044

 

(44,924

)

289,007

 

Gross margin

 

$

963,006

 

$

829,408

 

$

720,414

 

$

784,707

 

$

885,783

 

 

We define EBITDA, as adjusted, as net income (loss) excluding 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, restructuring charges, non-cash gains or losses from foreign currency exchange rate changes recorded on intercompany obligations 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, restructuring charges and other charges. Management uses EBITDA, as adjusted, as a supplemental measure to review current period operating performance, comparability measures and performance measures for period to period comparisons. Our EBITDA, as adjusted, may not be comparable to a similarly titled measure of another company because other entities may not calculate EBITDA in the same manner.

 

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

 

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

 

 

 

Years Ended December 31,

 

 

 

2013

 

2012

 

2011

 

2010

 

2009

 

Net income (loss)

 

$

155,742

 

$

(37,169

)

$

(339,618

)

$

(113,241

)

$

(545,463

)

(Income) loss from discontinued operations, net of tax

 

(64,014

)

(35,976

)

8,044

 

(44,924

)

289,007

 

Depreciation and amortization

 

327,505

 

346,177

 

352,793

 

387,571

 

338,812

 

Long-lived asset impairment

 

28,637

 

136,614

 

6,068

 

143,874

 

96,988

 

Restructuring charges

 

 

6,471

 

11,594

 

 

13,864

 

Goodwill impairment

 

 

 

196,807

 

 

150,778

 

Investment in non-consolidated affiliates impairment

 

 

224

 

471

 

609

 

96,593

 

Proceeds from sale of joint venture assets

 

(19,000

)

(51,707

)

 

 

 

Interest expense

 

115,745

 

134,376

 

149,473

 

136,149

 

122,845

 

(Gain) loss on currency exchange rate remeasurement of intercompany balances

 

4,313

 

7,406

 

14,174

 

(6,255

)

(13,654

)

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

 

84,719

 

(45,755

)

(11,717

)

(64,559

)

47,853

 

EBITDA, as adjusted

 

$

633,647

 

$

460,661

 

$

388,089

 

$

434,361

 

$

576,817

 

 

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 Financial Statements, 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 Part I (“Disclosure Regarding Forward-Looking Statements”) and Part I, Item 1A (“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, aftermarket services and fabrication. In our contract operations business line, we use our fleet of natural gas compression equipment and crude oil and natural gas production and processing equipment to provide operations services to our customers. 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. In our fabrication business line, we fabricate compression and oil and natural gas production and processing equipment for sale to our customers and for use 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. We offer our customers, on either a contract operations basis or a sale basis, the engineering, design, project management, procurement and construction services necessary to incorporate our products into production, processing and compression facilities, which we refer to as Integrated Projects.

 

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 is typically less impacted by commodity prices than certain other energy service products and services, changes in oil and natural gas exploration and production spending normally result in changes in demand for our products and services.

 

Natural gas consumption in the U.S. for the twelve months ended November 30, 2013 remained relatively flat compared to the twelve months ended November 30, 2012. The EIA forecasts that total U.S. natural gas consumption will decrease by 1.3% in 2014 compared to 2013 and increase by an average of 0.7% per year thereafter until 2040. The EIA estimates that the U.S. natural gas consumption level will be approximately 30 trillion cubic feet in 2040, or 16% of the projected worldwide total of approximately 185 trillion cubic feet.

 

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Natural gas marketed production in the U.S. for the twelve months ended November 30, 2013 increased by approximately 1.1% over the twelve months ended November 30, 2012. The EIA forecasts that total U.S. natural gas marketed production will increase by 2.2% in 2014 compared to 2013 and U.S. natural gas production will increase by an average of 1.5% per year thereafter until 2040. The EIA estimates that the U.S. natural gas production level will be approximately 33 trillion cubic feet in 2040, or 18% of the projected worldwide total of approximately 187 trillion cubic feet.

 

Our Performance Trends and Outlook

 

Our revenue, earnings and financial position are affected by, among other things, market conditions that impact demand and pricing for natural gas compression and oil and natural gas production and processing and our customers’ decisions among using our products and services, using our competitors’ products and services or owning and operating the equipment themselves.

 

In the second half of 2011, we embarked on a multi-year plan to improve the profitability of our operations. We implemented certain key profitability initiatives associated with this plan in 2012, and implemented additional process initiatives intended to improve operating efficiency and reduce our cost structure throughout 2013. These initiatives have positively impacted all of our business segments, and we expect additional positive impact in 2014.

 

During 2013, we saw steady activity in North American shale plays and areas focused on the production of oil and natural gas liquids. This activity has increased the overall amount of compression horsepower in the industry; however, these increases continue to be offset by horsepower declines in more mature and predominantly dry gas markets, where we provide a significant amount of contract operations services. In early 2012, natural gas prices in North America fell to their lowest levels in more than a decade, but prices recovered somewhat during 2013. Historically, natural gas prices in North America have been volatile. During periods of lower natural gas prices, natural gas production growth could be limited or decline in North America, particularly in dry gas areas. Booking activity levels for our North America fabricated products during the year ended December 31, 2013 have decreased from relatively high levels in the prior year. Approximately 38% of the reduction in the North America backlog during 2013 compared to year-end 2012 was related to an installation project for one customer that was completed in 2013. Despite lower booking levels for our fabricated products, our North America fabrication revenue during 2013 was higher than the results achieved during 2012. We believe our fabrication backlog has stabilized as of year-end 2013.

 

In international markets, we believe demand for our contract operations and fabricated projects will continue 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.

 

Our level of capital spending depends on our forecast for the demand for our products and services and the equipment required to provide services to our customers. We anticipate investing more capital in our contract operations business in 2014 than we did in 2013.

 

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, 2014; however, to the extent it is not, we may seek additional debt or equity financing. We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity or other debt securities, in open market purchases, privately negotiated transactions or otherwise and from time to time seek to purchase our equity. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.

 

We intend to continue to contribute over time additional U.S. contract operations customer contracts and equipment to the Partnership in exchange for cash, the Partnership’s assumption of our debt and/or our receipt of additional interests in the Partnership. Such transactions depend on, among other things, market and economic conditions, our ability to agree with the Partnership regarding the terms of any purchase and the availability to the Partnership of debt and equity capital on reasonable terms.

 

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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 2013, we saw steady activity in North American shale plays and areas focused on the production of oil and natural gas liquids. This activity has increased the overall amount of compression horsepower in the industry; however, these increases continue to be offset by horsepower declines in more mature and predominantly dry gas markets, where we provide a significant amount of contract operations services. In early 2012, natural gas prices in North America fell to their lowest levels in more than a decade, but prices recovered somewhat during 2013. Historically, natural gas prices in North America have been volatile. During periods of lower natural gas prices, natural gas production growth could be limited or decline in North America, 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. The recent investment of capital in new equipment by our competitors and other third parties could also create uncertainty in our business outlook. Many of our North America contract operations agreements with customers have short initial terms and are typically cancelable on short notice after the initial term, and we cannot be certain that these contracts will be extended or renewed after the end of the initial contractual term. Any such nonrenewals, or renewals at reduced rates, could adversely impact our results of operations.

 

Execution on Larger Contract Operations and Fabrication Projects.  Some of our projects have a relatively larger size and scope than the majority of our projects, which 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.

 

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 in our industry 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.

 

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. In international projects, some business activity is related to infrastructure development or regulatory requirements such as regulations to prevent the flaring of natural gas. The timing and financial impact of these projects is difficult to predict as they typically have longer lead times and larger scope, which can lead to variations in our results of operations internationally on a year over year basis.

 

Summary of Results

 

As discussed in Note 2 to the Financial Statements, the results from continuing operations for all periods presented exclude the results of our Venezuelan contract operations business, Canadian Operations and contract water treatment business. Those results are reflected in discontinued operations for all periods presented.

 

Net Income (loss) attributable to Exterran stockholders and EBITDA, as adjusted.  We recorded net income attributable to Exterran stockholders of $123.2 million during the year ended December 31, 2013 and net loss attributable to Exterran stockholders of $39.5 million and $340.6 million during the years ended December 31, 2012 and 2011, respectively. The increase in net income attributable to Exterran stockholders during the year ended December 31, 2013 compared to the year ended December 31, 2012 was primarily due to an increase in gross margins in our fabrication and North America contract operations segments, a decrease in long-lived asset impairments of $108.0 million, an increase in income from discontinued operations and an increase in gain on sale of property, plant and equipment, partially offset by a decrease of $32.7 million in cash payments received from the sale of our Venezuelan joint ventures’ assets and an increase in income tax expense. The decrease in net loss attributable to Exterran stockholders during the year ended December 31, 2012 compared to the year ended December 31, 2011 was primarily due to goodwill impairments of $196.8 million recorded during the year ended December 31, 2011, an increase in gross margin in all of our business segments, equity in income of non-consolidated affiliates of $51.7 million from the sale of our Venezuelan joint ventures’ assets during the year ended December 31, 2012 and an increase in income from discontinued operations. These decreases in net loss were partially offset by an increase in long-lived asset impairments of $130.5 million during the year ended December 31, 2012 compared to the year ended December 31, 2011. Our EBITDA, as adjusted, was $633.6 million, $460.7 million and $388.1 million during the years ended December 31, 2013, 2012 and 2011, respectively. EBITDA, as adjusted, during the year ended December 31, 2013 compared to the year ended December 31, 2012 and during the year ended December 31, 2012 compared to the year ended December 31, 2011, was favorably impacted by higher gross margins as discussed above. 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.

 

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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,

 

 

 

2013

 

2012

 

2011

 

Revenue:

 

 

 

 

 

 

 

North America Contracts Operations

 

$

627,844

 

$

596,011

 

$

570,780

 

International Contract Operations

 

476,016

 

463,957

 

445,059

 

Aftermarket Services

 

395,600

 

385,861

 

371,327

 

Fabrication

 

1,660,944

 

1,348,417

 

1,225,459

 

 

 

$

3,160,404

 

$

2,794,246

 

$

2,612,625

 

Gross Margin(1):

 

 

 

 

 

 

 

North America Contracts Operations

 

$

345,355

 

$

311,308

 

$

276,971

 

International Contract Operations

 

279,072

 

279,349

 

260,654

 

Aftermarket Services

 

86,182

 

82,271

 

59,567

 

Fabrication

 

252,397

 

156,480

 

123,222

 

 

 

$

963,006

 

$

829,408

 

$

720,414

 

Gross Margin percentage(2):

 

 

 

 

 

 

 

North America Contracts Operations

 

55

%

52

%

49

%

International Contract Operations

 

59

%

60

%

59

%

Aftermarket Services

 

22

%

21

%

16

%

Fabrication

 

15

%

12

%

10

%

 


(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 Part II, Item 6 (“Selected Financial Data — Non-GAAP Financial Measures”) of this report.

 

(2)                  Defined as gross margin divided by revenue.

 

Operating Highlights

 

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

 

 

 

Years Ended December 31,

 

 

 

2013

 

2012

 

2011

 

Total Available Horsepower (at period end):

 

 

 

 

 

 

 

North America

 

3,429

 

3,376

 

3,545

 

International

 

1,255

 

1,265

 

1,260

 

Total

 

4,684

 

4,641

 

4,805

 

Total Operating Horsepower (at period end):

 

 

 

 

 

 

 

North America

 

2,884

 

2,900

 

2,830

 

International

 

986

 

1,007

 

960

 

Total

 

3,870

 

3,907

 

3,790

 

Average Operating Horsepower:

 

 

 

 

 

 

 

North America

 

2,871

 

2,839

 

2,784

 

International

 

995

 

991

 

978

 

Total

 

3,866

 

3,830

 

3,762

 

Horsepower Utilization (at period end):

 

 

 

 

 

 

 

North America

 

84

%

86

%

80

%

International

 

79

%

80

%

76

%

Total

 

83

%

84

%

79

%

 

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December 31,

 

 

 

2013

 

2012

 

2011

 

Compressor and Accessory Fabrication Backlog

 

$

157,893

 

$

256,315

 

$

249,724

 

Production and Processing Equipment Fabrication Backlog

 

475,565

 

563,826

 

415,968

 

Installation Backlog

 

46,429

 

245,573

 

69,576

 

Fabrication Backlog

 

$

679,887

 

$

1,065,714

 

$

735,268

 

 

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

 

North America Contract Operations

(dollars in thousands)

 

 

 

Years Ended December 31,

 

Increase

 

 

 

2013

 

2012

 

(Decrease)

 

Revenue

 

$

627,844

 

$

596,011

 

5

%

Cost of sales (excluding depreciation and amortization expense)

 

282,489

 

284,703

 

(1

)%

Gross margin

 

$

345,355

 

$

311,308

 

11

%

Gross margin percentage

 

55

%

52

%

3

%

 

The increase in revenue during the year ended December 31, 2013 compared to the year ended December 31, 2012 was primarily attributable to an increase in rates, a 1% increase in average operating horsepower and a $6.5 million increase in revenue with no incremental cost due to the termination of contracts resulting from the exercise of purchase options by our customer on two natural gas processing plants, partially offset by a $7.4 million decrease in revenue due to the termination of three natural gas processing plant contracts during the second quarter of 2013. The increases in gross margin (defined as revenue less cost of sales, excluding depreciation and amortization expense) and gross margin percentage during the year ended December 31, 2013 compared to the year ended December 31, 2012 were primarily caused by the revenue increase explained above and improved management of field operating expenses from the implementation of profitability improvement initiatives. 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.

 

International Contract Operations

(dollars in thousands)

 

 

 

Years Ended December 31,

 

Increase

 

 

 

2013

 

2012

 

(Decrease)

 

Revenue

 

$

476,016

 

$

463,957

 

3

%

Cost of sales (excluding depreciation and amortization expense)

 

196,944

 

184,608

 

7

%

Gross margin

 

$

279,072

 

$

279,349

 

0

%

Gross margin percentage

 

59

%

60

%

(1

)%

 

The increase in revenue during the year ended December 31, 2013 compared to the year ended December 31, 2012 was primarily due to rate increases in Argentina and Indonesia that provided $32.7 million of additional revenue in 2013 and increases in revenue in Mexico and Bahrain of $17.7 million primarily due to contracts that commenced or were expanded in scope in 2012 and 2013. These increases were partially offset by a $37.1 million decrease in revenue in Brazil primarily as a result of the recognition of revenue with little incremental cost on terminated contracts during the prior year period. Gross margin percentage during the year ended December 31, 2013 compared to the year ended December 31, 2012 decreased due to the recognition of revenue on terminated contracts in Brazil during the year ended December 31, 2012 mentioned above, partially offset by the rate increases mentioned above.

 

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Aftermarket Services

(dollars in thousands)

 

 

 

Years Ended December 31,

 

Increase

 

 

 

2013

 

2012

 

(Decrease)

 

Revenue

 

$

395,600

 

$

385,861

 

3

%

Cost of sales (excluding depreciation and amortization expense)

 

309,418

 

303,590

 

2

%

Gross margin

 

$

86,182

 

$

82,271

 

5

%

Gross margin percentage

 

22

%

21

%

1

%

 

The increase in revenue during the year ended December 31, 2013 compared to the year ended December 31, 2012 was primarily due to an increase in revenue in the Eastern Hemisphere of $8.9 million and an increase in revenue in Latin America of $6.7 million, partially offset by a decrease in revenue in North America of $5.9 million. Gross margin increased during the year ended December 31, 2013 compared to the year ended December 31, 2012 primarily due to increases in gross margin in Latin America and North America, partially offset by lower current period gross margins on work performed in the Eastern Hemisphere.

 

Fabrication

(dollars in thousands)

 

 

 

Years Ended December 31,

 

Increase

 

 

 

2013

 

2012

 

(Decrease)

 

Revenue

 

$

1,660,944

 

$

1,348,417

 

23

%

Cost of sales (excluding depreciation and amortization expense)

 

1,408,547

 

1,191,937

 

18

%

Gross margin

 

$

252,397

 

$

156,480

 

61

%

Gross margin percentage

 

15

%

12

%

3

%

 

The increase in revenue during the year ended December 31, 2013 compared to the year ended December 31, 2012 was primarily due to $188.9 million of higher revenue in the Eastern Hemisphere, $74.6 million of higher revenue in North America and $49.0 million of higher revenue in Latin America. The increase in revenue in the Eastern Hemisphere was due to increases of $114.3 million, $38.9 million and $35.7 million in compressor revenue, production and processing equipment revenue and installation revenue, respectively. The increase in North America revenue was due to increases of $80.7 million and $88.4 million in installation revenue and production and processing equipment revenue, respectively, partially offset by a $94.5 million decrease in compressor revenue. The increase in Latin America revenue was primarily due to an increase in installation revenue of $54.4 million. The increases in gross margin and gross margin percentage were primarily caused by the revenue increase explained above, a reduction in operating expenses from the implementation of profitability improvement initiatives and improved pricing associated with projects in North America and the Eastern Hemisphere. These improvements in results were partially offset by cost overruns on three large turnkey projects during the year ended December 31, 2013.

 

Costs and Expenses

(dollars in thousands)

 

 

 

Years Ended December 31,

 

Increase

 

 

 

2013

 

2012

 

(Decrease)

 

Selling, general and administrative

 

$

358,173

 

$

375,647

 

(5

)%

Depreciation and amortization

 

327,505

 

346,177

 

(5

)%

Long-lived asset impairment

 

28,637

 

136,614

 

(79

)%

Restructuring charges

 

 

6,471

 

(100

)%

Interest expense

 

115,745

 

134,376

 

(14

)%

Equity in income of non-consolidated affiliates

 

(19,000

)

(51,483

)

(63

)%

Other (income) expense, net

 

(24,501

)

506

 

(4,942

)%

 

The decrease in SG&A expense during the year ended December 31, 2013 compared to the year ended December 31, 2012 was primarily due to a $15.1 million decrease in state and local taxes primarily related to the impact of sales tax audits in North America recorded during the year ended December 31, 2012 and a $6.6 million decrease in bad debt expense, partially offset by a $5.2 million increase in professional, consulting and legal expenses. SG&A as a percentage of revenue was 11% and 13% during the years ended December 31, 2013 and 2012, respectively.

 

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Depreciation and amortization expense during the year ended December 31, 2013 compared to the year ended December 31, 2012 decreased primarily due to reduced depreciation expense on terminated contract operations projects in Brazil and the impact of impairments recorded in 2012, which decreased depreciation expense during the year ended December 31, 2013. These decreases were partially offset by increased depreciation expense due to property, plant and equipment additions.

 

During the year ended December 31, 2013, we evaluated the future deployment of our idle fleet and determined to retire and either sell or re-utilize the key components of approximately 280 idle compressor units, representing approximately 76,000 horsepower, previously used to provide services in our North America contract operations segment. As a result, we performed an impairment review and recorded a $14.9 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 either the expected net sale proceeds compared to other fleet units we recently sold and/or a review of other units recently offered for sale by third parties, or the estimated component value of the equipment we plan to use.

 

In July 2013, as part of our continued emphasis on simplification and focus on our core business, we sold the entity that owned our fabrication facility in the United Kingdom. As a result, we recorded impairment charges of $11.9 million during the year ended December 31, 2013.

 

During the year ended December 31, 2013, we evaluated other long-lived assets for impairment and recorded long-lived asset impairments of $1.8 million on these assets.

 

During the year ended December 31, 2012, we evaluated the future deployment of our idle fleet and determined to retire and either sell or re-utilize the key components of approximately 930 idle compressor units, representing approximately 318,000 horsepower, previously used to provide services in our North America contract operations segment. As a result, we performed an impairment review and recorded a $97.1 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 either the expected net sale proceeds compared to other fleet units we recently sold and/or a review of other units recently offered for sale by third parties, or the estimated component value of the equipment we plan to use. The average age of the impaired idle units we impaired during the second quarter of 2012 was 24 years.

 

In connection with our 2012 fleet review, we evaluated for impairment idle units that had been culled from our fleet in prior years and were available for sale. Based upon that review, we reduced the expected proceeds from disposition for most of the remaining units and increased the weighted average disposal period for the units from the assumptions used in prior periods. This resulted in an additional impairment of $34.8 million to reduce the book value of each unit to its estimated fair value.

 

During the year ended December 31, 2012, we evaluated other long-lived assets for impairment and recorded long-lived asset impairments of $4.7 million on these assets.

 

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 ongoing operating costs and to adjust the size of our workforce to be consistent with then current and expected activity levels. A significant portion of the workforce cost reduction program was completed in 2011, with the remainder completed in 2012. During the year ended December 31, 2012, we incurred $6.5 million of restructuring charges primarily related to termination benefits and consulting services. See Note 14 to the Financial Statements for further discussion of these charges.

 

The decrease in interest expense during the year ended December 31, 2013 compared to the year ended December 31, 2012 was primarily due to a lower average balance of long-term debt and a decrease in the weighted average effective rate on our debt. The decrease in the weighted average effective rate on our debt was primarily due to the expiration of certain interest rate swaps in the third quarter of 2012 and a decrease of $6.5 million in the amortization of terminated interest rate swaps. Additionally, during the year ended December 31, 2013, we expensed $1.6 million of unamortized deferred financing costs resulting from an amendment to the Partnership Credit Agreement and our redemption of the 4.75% convertible senior notes (the “4.75% Notes”). During the year ended December 31, 2012, we expensed $1.3 million of unamortized deferred financing costs resulting from the decrease in capacity of our revolving credit facility. The terminated interest rate swaps are being amortized into interest expense over the original terms of the swaps.

 

In March 2012, our Venezuelan joint ventures sold their assets to PDVSA Gas. We received payments, including an annual charge, of $19.0 million and $51.7 million during the years ended December 31, 2013 and December 31, 2012, respectively. The remaining principal amount due to us of approximately $39 million as of December 31, 2013, is payable in quarterly cash installments through the first quarter of 2016. Payments we receive from the sale will be recognized as equity in (income) loss of non-consolidated affiliates in our consolidated statements of operations in the periods such payments are received.

 

The change in other (income) expense, net, during the year ended December 31, 2013 compared to the year ended December 31, 2012 was primarily due to a $22.8 million increase in gain on sale of property, plant and equipment.

 

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Income Taxes

(dollars in thousands)

 

 

 

Years Ended December 31,

 

Increase

 

 

 

2013

 

2012

 

(Decrease)

 

Provision for (benefit from) income taxes

 

$

84,719

 

$

(45,755

)

285

%

Effective tax rate

 

48.0

%

38.5

%

9.5

%

 

The increase in our income tax expense during the year ended December 31, 2013 compared to the year ended December 31, 2012 was primarily attributable to a $295.3 million increase in pre-tax income which included a $119.9 million decrease in impairments of idle fleet assets, predominantly tax effected at the U.S. statutory rate. Additionally, a $9.0 million valuation allowance was recorded during the fourth quarter of 2013 against the deferred tax asset for Italy net operating loss carryforwards, which increased income tax expense.

 

Discontinued Operations

(dollars in thousands)

 

 

 

Years Ended December 31,

 

Increase

 

 

 

2013

 

2012

 

(Decrease)

 

Income from discontinued operations, net of tax

 

$

64,014

 

$

35,976

 

78

%

 

Income from discontinued operations, net of tax, during the years ended December 31, 2013 and 2012 includes our operations in Venezuela that were expropriated in June 2009, including compensation for expropriation and costs associated with our arbitration proceeding, results from our Canadian Operations and results from our contract water treatment business.

 

As discussed in Note 2 to the Financial Statements, in June 2009, PDVSA assumed control over substantially all of our assets and operations in Venezuela. In August 2012, our Venezuelan subsidiary sold its previously nationalized assets to PDVSA Gas for a purchase price of approximately $441.7 million. We received an initial payment of $176.7 million in cash at closing, of which we remitted $50.0 million to repay the amount we collected in January 2010 under the terms of an insurance policy we maintained for the risk of expropriation. We received installment payments, including an annual charge, totaling $69.3 million and $16.8 million during the years ended December 31, 2013 and 2012, respectively. The remaining principal amount due to us of approximately $182 million as of December 31, 2013, is payable in quarterly cash installments through the third quarter of 2016. We have not recognized amounts payable to us by PDVSA Gas as a receivable and will therefore recognize quarterly payments received in the future as income from discontinued operations in the periods such payments are received. The proceeds from the sale of the assets are not subject to Venezuelan national taxes due to an exemption allowed under the Venezuelan Reserve Law applicable to expropriation settlements. In addition, and in connection with the sale, we and the Venezuelan government agreed to waive rights to assert certain claims against each other. We therefore recorded a reduction in previously unrecognized tax benefits, resulting in a $15.5 million benefit reflected in income (loss) from discontinued operations, net of tax, in our consolidated statements of operations during the year ended December 31, 2012.

 

In June 2012, we committed to a plan to sell our Canadian Operations. In connection with the planned disposition, we recorded impairment charges totaling $6.4 million and $80.2 million during the years ended December 31, 2013 and 2012, respectively. As discussed in Note 2 to the Financial Statements, in July 2013, we completed the sale of our Canadian Operations.

 

In December 2013, we abandoned our contract water treatment business as part of our continued emphasis on simplification and focus on our core businesses. The abandonment of this business meets the criteria established for recognition as discontinued operations under GAAP. During the years ended December 31, 2013 and 2012, we evaluated our contract water treatment business and recorded impairment charges of $2.4 million and $46.8 million, respectively. The impairment charges are reflected in income (loss) from discontinued operations, net of tax, in our consolidated statements of operations.

 

Noncontrolling Interest

 

As of December 31, 2013, noncontrolling interest was comprised of the portion of the Partnership’s earnings that is applicable to the Partnership’s publicly-held limited partner interest. As of December 31, 2013, public unitholders held a 59% ownership interest in the Partnership.

 

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Year Ended December 31, 2012 Compared to Year Ended December 31, 2011

 

North America Contract Operations

(dollars in thousands)

 

 

 

Years Ended December 31,

 

Increase

 

 

 

2012

 

2011

 

(Decrease)

 

Revenue

 

$

596,011

 

$

570,780

 

4

%

Cost of sales (excluding depreciation and amortization expense)

 

284,703

 

293,809

 

(3

)%

Gross margin

 

$

311,308

 

$

276,971

 

12

%

Gross margin percentage

 

52

%

49

%

3

%

 

The increase in revenue during the year ended December 31, 2012 compared to the year ended December 31, 2011 was primarily attributable to a 2% increase in average operating horsepower, an increase in rates, a $4.0 million increase in revenue from a gas processing plant that began operations during the fourth quarter of 2011 and a $3.9 million increase in freight revenue. The increases in gross margin (defined as revenue less cost of sales, excluding depreciation and amortization expense) and gross margin percentage during the year ended December 31, 2012 compared to the year ended December 31, 2011 were primarily caused by the revenue increase explained above, improved management of field operating expenses from the implementation of profitability improvement initiatives, a $7.1 million benefit from ad valorem taxes due to a change in tax law (see Note 20 to the Financial Statements) and a $4.4 million decrease in costs to deploy idle fleet assets on customer contracts, partially offset by an increase in lube oil prices. 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.

 

International Contract Operations

(dollars in thousands)

 

 

 

Years Ended December 31,

 

Increase

 

 

 

2012

 

2011

 

(Decrease)

 

Revenue

 

$

463,957

 

$

445,059

 

4

%

Cost of sales (excluding depreciation and amortization expense)

 

184,608

 

184,405

 

0

%

Gross margin

 

$

279,349

 

$

260,654

 

7

%

Gross margin percentage

 

60

%

59

%

1

%

 

The increases in revenue and gross margin during the year ended December 31, 2012 compared to the year ended December 31, 2011 were primarily due to a $15.9 million increase in revenue in Mexico primarily due to new contracts commencing in 2012, a $10.9 million increase in revenue in Argentina as a result of inflation rate adjustments, a $5.1 million increase in revenue due to the recognition of revenue with little incremental cost on the early termination of a project in Nigeria resulting from the exercise of a purchase option by our customer in 2012 and a $9.1 million increase in revenue from a new contract in the Eastern Hemisphere. These increases were partially offset by a $20.5 million decrease in revenue in Brazil primarily as a result of lower 2012 revenue from four contracts that were terminated in 2011 and settled in 2012 and contract renewals at lower rates in 2012. Gross margin percentage during the year ended December 31, 2012 increased due to the recognition of $17.1 million of revenue with little incremental cost from the settlement in 2012 of the early termination of projects in Brazil and Nigeria and inflation rate adjustments in Argentina. These increases were partially offset by the impact of contract renewals at lower rates in 2012 in Brazil.

 

Aftermarket Services

(dollars in thousands)

 

 

 

Years Ended December 31,

 

Increase

 

 

 

2012

 

2011

 

(Decrease)

 

Revenue

 

$

385,861

 

$

371,327

 

4

%

Cost of sales (excluding depreciation and amortization expense)

 

303,590

 

311,760

 

(3

)%

Gross margin

 

$

82,271

 

$

59,567

 

38

%

Gross margin percentage

 

21

%

16

%

5

%

 

The increase in revenue during the year ended December 31, 2012 compared to the year ended December 31, 2011 was primarily due to an increase in revenue in North America of $31.7 million. This was partially offset by a decrease in revenue in the Eastern Hemisphere and Latin America of $9.3 million and $7.9 million, respectively. Gross margin and gross margin percentage were favorably impacted by improved market conditions and the implementation of profitability improvement initiatives that began in the second half of 2011.

 

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Fabrication

(dollars in thousands)

 

 

 

Years Ended December 31,

 

Increase

 

 

 

2012

 

2011

 

(Decrease)

 

Revenue

 

$

1,348,417

 

$

1,225,459

 

10

%

Cost of sales (excluding depreciation and amortization expense)

 

1,191,937

 

1,102,237

 

8

%

Gross margin

 

$

156,480

 

$

123,222

 

27

%

Gross margin percentage

 

12

%

10

%

2

%

 

The increase in revenue during the year ended December 31, 2012 compared to the year ended December 31, 2011 was primarily due to $315.8 million of higher revenue in North America caused by improved market conditions, partially offset by a $207.4 million reduction of revenue in the Eastern Hemisphere. The increases in gross margin and gross margin percentage were primarily caused by customer price increases in North America as a result of improved market conditions and a reduction in operating expenses from the implementation of profitability improvement initiatives and lower margins in 2011 on two projects in the Eastern Hemisphere. This was partially offset by the continuation of weaker market conditions and increased competition that impacted the results of our Belleli Energy 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, and a $15.0 million recovery on a loss contract recorded in the first quarter of 2011. The decreases in gross margin and gross margin percentage at our Belleli Energy subsidiary were primarily the result of lower activity levels and an increase in under-absorption caused by such reduced activity.

 

Costs and Expenses

(dollars in thousands)

 

 

 

Years Ended December 31,

 

Increase

 

 

 

2012

 

2011

 

(Decrease)

 

Selling, general and administrative

 

$

375,647

 

$

352,096

 

7

%

Depreciation and amortization

 

346,177

 

352,793

 

(2

)%

Long-lived asset impairment

 

136,614

 

6,068

 

2,151

%

Restructuring charges

 

6,471

 

11,594

 

(44

)%

Goodwill impairment

 

 

196,807

 

(100

)%

Interest expense

 

134,376

 

149,473

 

(10

)%

Equity in (income) loss of non-consolidated affiliates

 

(51,483

)

471

 

(11,031

)%

Other (income) expense, net

 

506

 

(5,597

)

(109

)%

 

The increase in SG&A expense during the year ended December 31, 2012 was primarily due to a $15.3 million increase in state and local taxes primarily related to sales tax audits in North America and a $10.3 million increase in compensation and benefit costs. These increases were partially offset by a decrease in other SG&A expenses primarily driven by cost reduction efforts. SG&A as a percentage of revenue was 13% during the years ended December 31, 2012 and 2011.

 

Depreciation and amortization during the year ended December 31, 2012 compared to the year ended December 31, 2011 decreased primarily due to reduced depreciation and amortization on contract operations projects in Brazil as a result of contracts that terminated in 2011 and the impact of the $128.5 million impairment recorded in the second quarter of 2012, which decreased depreciation and amortization expense by $5.9 million in the year ended December 31, 2012. These reductions were partially offset by increased depreciation and amortization on contract operations projects in Mexico that commenced in 2012.

 

During 2012, we evaluated the future deployment of our idle fleet and determined to retire and either sell or re-utilize the key components of approximately 930 idle compressor units, representing approximately 318,000 horsepower, previously used to provide services in our North America contract operations segment. As a result, we performed an impairment review and recorded a $97.1 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 either the expected net sale proceeds compared to other fleet units we recently sold and/or a review of other units recently offered for sale by third parties, or the estimated component value of the equipment we plan to use. The average age of the impaired idle units we impaired during the second quarter of 2012 was 24 years.

 

In connection with our 2012 fleet review, we evaluated for impairment idle units that had been culled from our fleet in prior years and were available for sale. Based upon that review, we reduced the expected proceeds from disposition for most of the remaining units and increased the weighted average disposal period for the units from the assumptions used in prior periods. This resulted in an additional impairment of $34.8 million to reduce the book value of each unit to its estimated fair value.

 

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During 2012, we evaluated other long-lived assets for impairment and recorded long-lived asset impairments of $4.7 million on these assets.

 

During 2011, we reviewed our idle compression assets used in our contract operations segments for units that were not of the type, configuration, make or model that are cost effective to maintain and operate. As a result, we performed an impairment review and recorded a $5.7 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 either the expected net sale proceeds compared to other fleet units we recently sold and/or a review of other units recently offered for sale by third parties, or the estimated component value of the equipment we plan to use.

 

During 2011, we evaluated other long-lived assets for impairment and recorded long-lived asset impairments of $0.4 million on these assets.

 

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 then current and expected activity levels. A significant portion of the workforce cost reduction program was completed in 2011, with the remainder completed in 2012. During the years ended December 31, 2012 and 2011, we incurred $6.5 and $11.6 million, respectively, of restructuring charges primarily related to termination benefits and consulting services. 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 our remaining goodwill during 2011 of $196.8 million. See Note 8 to the Financial Statements for further discussion of the goodwill impairments.

 

The decrease in interest expense during the year ended December 31, 2012 compared to the year ended December 31, 2011 was primarily due to a decrease of $9.6 million in the amortization of terminated interest rate swaps and a decrease as a result of the expiration of certain interest rate swaps in the third quarter of 2012. This was partially offset by refinancing a portion of our outstanding debt at a higher interest rate. The terminated interest rate swaps are being amortized into interest expense over the original terms of the swaps.

 

The change in equity in (income) loss of non-consolidated affiliates during the year ended December 31, 2012 compared to the year ended December 31, 2011 relates to payments, including an annual charge, of $51.7 million received during the year ended December 31, 2012 from the sale of our Venezuelan joint ventures’ assets. The remaining principal amount due to us is payable in quarterly cash installments through the first quarter of 2016. Payments we receive from the sale will be recognized as equity in (income) loss of non-consolidated affiliates in our consolidated statements of operations in the periods such payments are received.

 

The change in other (income) expense, net, during the year ended December 31, 2012 compared to the year ended December 31, 2011 was primarily due to a $13.4 million decrease related to non-income tax based tax receivables in Brazil that we determined were realizable. The change in other (income) expense, net, was also due to a foreign currency loss of $8.2 million and $16.5 million during the years ended December 31, 2012 and 2011, respectively. The reduction in our foreign currency loss for 2012 was impacted by a $7.7 million decrease in translation loss related to remeasurement of our Brazil subsidiary’s U.S. dollar denominated intercompany debt. 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.

 

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Income Taxes

(dollars in thousands)

 

 

 

Years Ended December 31,

 

Increase

 

 

 

2012

 

2011

 

(Decrease)

 

Benefit from income taxes

 

$

(45,755

)

$

(11,717

)

291

%

Effective tax rate

 

38.5

%

3.4

%

35.1

%

 

The increase in our effective tax rate during the year ended December 31, 2012 compared to the year ended December 31, 2011 was primarily due to $51.5 million equity in income of non-consolidated affiliates, which is not subject to income tax, and the $136.6 million long-lived asset impairment charge, which is predominantly tax effected at the U.S. statutory rate. For 2011, our effective tax rate was decreased due to the goodwill impairment charge of $196.8 million, of which only $42.6 million was deductible for income tax purposes, and $48.6 million of valuation allowance recorded against the deferred tax asset for Brazil net operating loss carryforwards.

 

Discontinued Operations

(dollars in thousands)

 

 

 

Years Ended December 31,

 

Increase

 

 

 

2012

 

2011

 

(Decrease)

 

Income (loss) from discontinued operations, net of tax

 

$

35,976

 

$

(8,044

)

547

%

 

Income (loss) from discontinued operations, net of tax, during the years ended December 31, 2012 and 2011 includes our operations in Venezuela that were expropriated in June 2009, including compensation for expropriation and costs associated with our arbitration proceeding, results from our Canadian Operations and results from our contract water treatment business.

 

As discussed in Note 2 to the Financial Statements, in June 2009, PDVSA assumed control over substantially all of our assets and operations in Venezuela. In August 2012, our Venezuelan subsidiary sold its previously nationalized assets to PDVSA Gas for a purchase price of approximately $441.7 million. We received an initial payment of $176.7 million in cash at closing, of which we remitted $50.0 million to repay the amount we collected in January 2010 under the terms of an insurance policy we maintained for the risk of expropriation. In December 2012 we received an installment payment, including an annual charge, of $16.8 million. The remaining principal amount due to us is payable in quarterly cash installments through the third quarter of 2016. We have not recognized amounts payable to us by PDVSA Gas as a receivable and will therefore recognize quarterly payments received in the future as income from discontinued operations in the periods such payments are received. The proceeds from the sale of the assets are not subject to Venezuelan national taxes due to an exemption allowed under the Venezuelan Reserve Law applicable to expropriation settlements. In addition, and in connection with the sale, we and the Venezuelan government agreed to waive rights to assert certain claims against each other. We therefore recorded a reduction in previously unrecognized tax benefits, resulting in a $15.5 million benefit reflected in income (loss) from discontinued operations, net of tax, in our consolidated statements of operations during the year ended December 31, 2012.

 

In June 2012, we committed to a plan to sell our Canadian Operations. The planned disposition meets the criteria established for recognition as discontinued operations and therefore our Canadian Operations are reflected as discontinued operations in our Financial Statements. In conjunction with the planned disposition, we recorded impairment charges totaling $80.2 million during the year ended December 31, 2012.

 

In December 2013, we abandoned our contract water treatment business as part of our continued emphasis on simplification and focus on our core businesses. The abandonment of this business meets the criteria established for recognition as discontinued operations under GAAP. During the year ended December 31, 2012, we evaluated our contract water treatment business and recorded impairment charges of $46.8 million. The impairment charges are reflected in income (loss) from discontinued operations, net of tax, in our consolidated statements of operations.

 

Noncontrolling Interest

 

As of December 31, 2012, noncontrolling interest was comprised of the portion of the Partnership’s earnings that is applicable to the Partnership’s publicly-held limited partner interest. As of December 31, 2012, public unitholders held a 69% ownership interest in the Partnership.

 

Liquidity and Capital Resources

 

Our unrestricted cash balance was $35.7 million at December 31, 2013 compared to $34.6 million at December 31, 2012. Working capital increased to $580.4 million at December 31, 2013 from $463.4 million at December 31, 2012. The increase in working capital was primarily due to increases in accounts receivable and inventory, a decrease in accounts payable and a decrease in billings on uncompleted contracts in excess of costs and estimated earnings, partially offset by a decrease in costs and estimated earnings in excess of billings on uncompleted contracts. The decrease in accounts payable at December 31, 2013 compared to December 31, 2012 was primarily due to a decrease in payables related to fabrication projects in North America. The decrease in costs and estimated earnings in excess of billings on uncompleted contracts and decrease in billings on uncompleted contracts in excess of costs and estimated earnings were primarily driven by the timing of billings on projects at December 31, 2013 compared to December 31, 2012.

 

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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,

 

 

 

2013

 

2012

 

Net cash provided by (used in) continuing operations:

 

 

 

 

 

Operating activities

 

$

348,668

 

$

383,262

 

Investing activities

 

(271,400

)

(341,421

)

Financing activities

 

(156,702

)

(171,290

)

Effect of exchange rate changes on cash and cash equivalents

 

(1,487

)

(486

)

Discontinued operations

 

81,985

 

142,633

 

Net change in cash and cash equivalents

 

$

1,064

 

$

12,698

 

 

Operating Activities.  The decrease in net cash provided by operating activities was primarily due to higher current period increases in working capital and income tax payments, partially offset by improved gross margins in our fabrication and North America contract operations segments and lower interest payments during the year ended December 31, 2013 compared to the year ended December 31, 2012.

 

Investing Activities.  The decrease in net cash used in investing activities was primarily attributable to a $65.3 million increase in proceeds from sale of property, plant and equipment and a $37.0 million decrease in capital expenditures during the year ended December 31, 2013 compared to the year ended December 31, 2012. These activities were partially offset by a $32.7 million decrease in cash payments received from the sale of our Venezuelan joint ventures’ assets during the year ended December 31, 2013 compared to the year ended December 31, 2012.

 

Financing Activities.  The decrease in net cash used in financing activities was primarily due to a $140.9 million decrease in net repayments under our debt facilities during the year ended December 31, 2013 compared to the year ended December 31, 2012. This activity was partially offset by $114.5 million of net proceeds received from the Partnership’s public offering of its common units during the year ended December 31, 2012 and an increase in payments for debt issuance costs of $11.1 million during the year ended December 31, 2013 compared to the year ended December 31, 2012.

 

Discontinued Operations.  The decrease in net cash provided by discontinued operations was primarily attributable to a $74.2 million decrease in proceeds received, net of insurance remittance, from the sale of our Venezuelan subsidiary’s assets to PDVSA Gas during the year ended December 31, 2013 compared to the year ended December 31, 2012, partially offset by proceeds of $12.3 million received from the sale of our Canadian Operations during the year ended December 31, 2013.

 

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 $400 million to $450 million in net capital expenditures during 2014, including (1) contract operations equipment additions and (2) approximately $100 million to $110 million on equipment maintenance capital related to our contract operations business. Net capital expenditures are net of used fleet sales.

 

Long-Term Debt.  As of December 31, 2013, we had approximately $1.5 billion in outstanding debt obligations, consisting of $49.0 million outstanding under our revolving credit facility, $343.7 million outstanding under our 4.25% convertible senior notes, $350.0 million outstanding under our 7.25% senior notes, $263.0 million outstanding under the Partnership’s revolving credit facility, $150.0 million outstanding under the Partnership’s term loan facility and $345.0 million outstanding under the Partnership’s 6% senior notes.

 

In January 2013, we redeemed for cash all $143.8 million principal amount outstanding of our 4.75% Notes at a redemption price of 100% of the principal amount thereof plus accrued but unpaid interest to, but excluding, the redemption date. Upon redemption, the 4.75% Notes were no longer deemed outstanding, interest ceased to accrue thereon and all rights of the holders of the 4.75% Notes ceased to exist. We financed the redemption of the 4.75% Notes through borrowings under our revolving credit facility.

 

In July 2011, we entered into a five-year, $1.1 billion senior secured revolving credit facility (the “Credit Facility”). In March 2012, we decreased the borrowing capacity under this facility to $900.0 million. As of December 31, 2013, we had $49.0 million in outstanding borrowings and $106.1 million in outstanding letters of credit under the Credit Facility. At December 31, 2013, taking into account guarantees through letters of credit, we had undrawn and available capacity of $744.9 million under the Credit Facility.

 

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Borrowings under the 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, 2013, all amounts outstanding under the Credit Facility were LIBOR loans and the applicable margin was 1.5%. The weighted average annual interest rate at December 31, 2013 on the outstanding balance under the Credit Facility was 1.7%.

 

Our Significant Domestic Subsidiaries (as defined in the credit agreement) guarantee the debt under the Credit Facility. Borrowings under the 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 Credit Facility, its assets are not collateral under the Credit Facility and the general partner units in the Partnership are not pledged under the Credit Facility. Subject to certain conditions, at our request, and with the approval of the lenders, the aggregate commitments under the Credit Facility may be increased by up to an additional $300 million.

 

The Credit Facility 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, 2013, we maintained a 10.7 to 1.0 Adjusted EBITDA to Total Interest Expense ratio, a 1.6 to 1.0 consolidated Total Debt to Adjusted EBITDA ratio and a 0.1 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 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 would trigger cross-default provisions under certain of our other debt agreements, which would accelerate our obligation to repay our indebtedness under those agreements. As of December 31, 2013, we were in compliance with all financial covenants under the Credit Facility.

 

In November 2010, we issued $350.0 million aggregate principal amount of 7.25% senior notes (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 Facility 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, respectively, are our and the guarantors’ general unsecured senior obligations, 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 could 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 could 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 remained outstanding after such redemption and the redemption occurred 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 (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 into which the 4.25% Notes can be converted exceeds their principal amount by $169.4 million as of December 31, 2013. We may not redeem the 4.25% Notes prior to their maturity date in June 2014. We have the intent and ability to refinance the maturity of the 4.25% Notes with borrowings under our existing Credit Facility and/or through conversion of the notes into common shares.

 

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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.

 

In November 2010, the Partnership Credit Agreement was amended and restated to provide for a 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. The revolving borrowing capacity under this facility increased to $550.0 million in March 2011 and to $750.0 million in March 2012. The Partnership amended the Partnership Credit Agreement in March 2013 to reduce the borrowing capacity under its revolving credit facility to $650.0 million and extend the maturity date of the term loan and revolving credit facilities to May 2018. As of December 31, 2013, the Partnership had undrawn and available capacity of $387.0 million under its revolving credit facility.

 

The Partnership’s revolving credit and term loan facilities bear 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 the revolving and term loans varies (i) in the case of LIBOR loans, from 2.0% to 3.0% and (ii) in the case of base rate loans, from 1.0% to 2.0%. 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, 2013, all amounts outstanding under these facilities were LIBOR loans and the applicable margin was 2.0%. The weighted average annual interest rate on the outstanding balance of these facilities at December 31, 2013, excluding the effect of interest rate swaps, was 2.2%.

 

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 the Partnership’s ability to incur additional indebtedness, engage in transactions with affiliates, merge or consolidate, sell assets, make certain investments and acquisitions, make loans, grant liens, repurchase equity and pay dividends and distributions. The Partnership Credit Agreement also contains various covenants requiring mandatory prepayments from the net cash proceeds of certain asset transfers. The Partnership must maintain various consolidated financial ratios, including a ratio of EBITDA (as defined in the Partnership Credit Agreement) to Total Interest Expense (as defined in the Partnership Credit Agreement) of not less than 2.75 to 1.0, a ratio of Total Debt (as defined in the Partnership Credit Agreement) to EBITDA of not greater than 5.25 to 1.0 (subject to a temporary increase to 5.5 to 1.0 for any quarter during which an acquisition meeting certain thresholds is completed and for the following two quarters after the acquisition closes) and a ratio of Senior Secured Debt (as defined in the Partnership Credit Agreement) to EBITDA of not greater than 4.0 to 1.0. As of December 31, 2013, the Partnership maintained a 7.5 to 1.0 EBITDA to Total Interest Expense ratio, a 3.1 to 1.0 Total Debt to EBITDA ratio and a 1.7 to 1.0 Senior Secured Debt to EBITDA ratio. A material adverse effect with respect to the Partnership’s assets, liabilities, financial condition, business or operations that, taken as a whole, impacts the Partnership’s ability to perform its obligations under the Partnership Credit Agreement, could lead to a default under that agreement. A default under one of the Partnership’s debt agreements would trigger cross-default provisions under the Partnership’s other debt agreement, which would accelerate the Partnership’s obligation to repay its indebtedness under those agreements. As of December 31, 2013, the Partnership was in compliance with all financial covenants under the Partnership Credit Agreement.

 

In March 2013, the Partnership issued $350.0 million aggregate principal amount of 6% senior notes due April 2021 (the “Partnership 6% Notes”). The Partnership used the net proceeds of $336.9 million, after original issuance discount and issuance costs, to repay borrowings outstanding under its revolving credit facility. The Partnership 6% Notes were issued at an original issuance discount of $5.5 million, which is being amortized using the effective interest method at an interest rate of 6.25% over their term. In January 2014, holders of the 6% Notes exchanged their 6% Notes for registered notes with the same terms.

 

The Partnership 6% Notes are guaranteed on a senior unsecured basis by all of the Partnership’s existing subsidiaries (other than EXLP Finance Corp., which is a co-issuer of the Partnership 6% Notes) and certain of the Partnership’s future subsidiaries. The Partnership 6% Notes and the guarantees, respectively, are the Partnership’s and the guarantors’ general unsecured senior ob