10-K 1 a14-24878_110k.htm 10-K

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, 2014

 

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, 2014 was $1,452,591,680. 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 19, 2015: 68,923,955 shares.

 


 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the registrant’s definitive proxy statement for the 2015 Meeting of Stockholders, which is expected to be filed with the Securities and Exchange Commission within 120 days after December 31, 2014, 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

16

Item 1B.

Unresolved Staff Comments

30

Item 2.

Properties

31

Item 3.

Legal Proceedings

31

Item 4.

Mine Safety Disclosures

31

PART II

Item 5.

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

32

Item 6.

Selected Financial Data

34

Item 7.

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

40

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

60

Item 8.

Financial Statements and Supplementary Data

61

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

61

Item 9A.

Controls and Procedures

61

Item 9B.

Other Information

63

PART III

Item 10.

Directors, Executive Officers and Corporate Governance

63

Item 11.

Executive Compensation

63

Item 12.

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

63

Item 13.

Certain Relationships and Related Transactions and Director Independence

65

Item 14.

Principal Accountant Fees and Services

65

PART IV

Item 15.

Exhibits and Financial Statement Schedules

65

SIGNATURES

70

 



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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 low price of oil or natural gas, which could cause a decline in the demand or pricing 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”);

 

·                  our ability to complete the proposed separation (the “Spinoff”) of our international contract operations, international aftermarket services and global fabrication businesses into an independent, publicly traded company;

 

·                  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 United States of America (“U.S.”) 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;

 

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

 

·                           winning profitable new business;

 

·                           sales of additional 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 natural gas 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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Exterran Partners, L.P.

 

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, 2014, public unitholders held a 63% ownership interest in the Partnership and we owned the remaining equity interest, including all of the general partner interest and incentive distribution rights. 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 we may grow the Partnership through third party acquisitions, organic growth and transfers by us of additional 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, 2014, the Partnership’s fleet included 6,472 compressor units comprising approximately 3,139,000 horsepower, or 75% of our and the Partnership’s combined total U.S. horsepower. The Partnership’s fleet included 229 compressor units, comprising approximately 79,000 horsepower, leased from our wholly-owned subsidiaries and excluded 1 compressor unit, comprising approximately 100 horsepower, owned by the Partnership but leased to our wholly-owned subsidiaries as of December 31, 2014.

 

August 2014 MidCon Acquisition

 

On August 8, 2014, the Partnership completed an acquisition of natural gas compression assets, including a fleet of 162 compressor units, comprising approximately 110,000 horsepower from MidCon Compression, L.L.C. (“MidCon”) for $130.1 million. The purchase price was funded with borrowings under the Partnership’s revolving credit facility. The majority of the horsepower acquired is under a five-year contract operations services agreement with BHP Billiton Petroleum (“BHP Billiton”) to provide compression services. In connection with the acquisition, the contract operations services agreement with BHP Billiton was assigned to the Partnership effective as of the closing.

 

In accordance with the terms of the Purchase and Sale Agreement between the Partnership and MidCon relating to this acquisition, the Partnership directed MidCon to sell a tract of real property and the facility located thereon, a fleet of vehicles, personal property and parts inventory to our wholly-owned subsidiary Exterran Energy Solutions, L.P. (“EESLP”), an indirect parent company of the Partnership, for $4.1 million. The assets acquired by EESLP are used in conjunction with the compression units the Partnership acquired from MidCon to provide compression services. The acquisition of the assets by the Partnership and EESLP from MidCon is referred to as the “August 2014 MidCon Acquisition.”

 

April 2014 MidCon Acquisition

 

On April 10, 2014, the Partnership completed an acquisition of natural gas compression assets, including a fleet of 337 compressor units, comprising approximately 444,000 horsepower from MidCon for $352.9 million. The purchase price was funded with the net proceeds from the Partnership’s public sale of 6.2 million common units and a portion of the net proceeds from the Partnership’s issuance of $350.0 million aggregate principal amount of 6% senior notes due October 2022 (the “Partnership 2014 Notes”). The compressor units were previously used by MidCon to provide compression services to a subsidiary of Access Midstream Partners LP (“Access”). Effective as of the closing of the acquisition, the Partnership and Access entered into a seven-year contract operations services agreement under which the Partnership provides compression services to Williams Partners, L.P. (“Williams,” formerly Access).

 

In accordance with the terms of the Purchase and Sale Agreement between the Partnership and MidCon relating to this acquisition, the Partnership directed MidCon to sell a tract of real property and the facility located thereon, a fleet of vehicles, personal property and parts inventory to our wholly-owned subsidiary EESLP, an indirect parent company of the Partnership, for $7.7 million. The assets acquired by EESLP are used in conjunction with the compression units the Partnership acquired from MidCon to provide compression services. The acquisition of the assets by the Partnership and EESLP from MidCon is referred to as the “April 2014 MidCon Acquisition.”

 

Proposed Spinoff Transaction

 

On November 17, 2014, we announced that our board of directors had authorized management to pursue a plan to separate our international contract operations, international aftermarket services and global fabrication businesses into an independent, publicly traded company (“Spinco”). To effect the Spinoff, we intend to distribute, on a pro rata basis, all of the shares of Spinco common stock to our stockholders as of the record date for the Spinoff. The Spinoff is subject to market conditions, the receipt of an opinion of counsel as to the tax-free nature of the transaction, completion of a review by the U.S. Securities and Exchange Commission of a Form 10 to be filed by Spinco, the execution of separation and intercompany agreements and final approval of our board of directors. Upon completion of the Spinoff, we and Spinco will be independent, publicly traded companies with separate public ownership, boards of directors and management, and we will own and operate the remaining U.S. contract operations and U.S. aftermarket services businesses that we currently own. In addition, we will continue to hold interests in the Partnership, which include the sole general partner interest and certain limited partner interests, as well as all of the incentive distribution rights in the Partnership.

 

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Spinco is expected to issue certain third-party debt instruments and borrow funds on or before the completion of the Spinoff. Certain, if not all, of the proceeds received by Spinco from such borrowings are expected to be distributed to us on or before the completion of the Spinoff and we expect to use those distributed funds to repay, in whole or in part, our (but not the Partnership’s) outstanding debt instruments. Although our current goal is to complete the Spinoff in the second half of 2015, there are no assurances as to when the proposed Spinoff will be completed, if at all, or if the Spinoff will be completed based on the expected plans.

 

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.

 

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;

 

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·                  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, 2014 increased by approximately 5% compared to the twelve months ended November 30, 2013. The U.S. Energy Information Administration (“EIA”) forecasts that total U.S. natural gas consumption will increase by 1.4% in 2015 compared to 2014 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, 2014 increased by approximately 5% compared to the twelve months ended November 30, 2013. The EIA forecasts that total U.S. natural gas marketed production will increase by 4% in 2015 compared to 2014 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.

 

Global oil and U.S. natural gas prices have declined significantly in the last several months, and, as a result, research analysts are forecasting declines in U.S. and worldwide capital spending for drilling activity in 2015, and U.S. producers and other producers around the world have begun to announce reduced capital budgets for this year.

 

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 believe there are opportunities to provide compression services to producers of natural gas liquids. Global oil and U.S. natural gas prices, however, have fallen significantly recently. During periods of lower oil and natural gas prices, production growth could moderate or decline in North America and in other parts of the world, and as a result the demand or pricing for our natural gas compression and oil and natural gas production and processing equipment and services could be adversely affected.

 

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The EIA reports that natural gas consumption outside of the U.S. grew 47% from 2000 through 2012. 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, during 2012 we had significant improvements in our fabrication backlog, which 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. During 2014, our fabrication backlog increased by approximately 40% from December 31, 2013. Additionally, we have seen some shift in the regional mix of our fabrication backlog over the past several years. As of December 31, 2013, our backlog for North America, the Eastern Hemisphere and Latin America represented approximately 43%, 55% and 2%, respectively, of our fabrication backlog. As of December 31, 2014, North America, the Eastern Hemisphere and Latin America accounted for approximately 56%, 37% and 7% 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. 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 significantly improved the total backlog for these products, which increased by approximately 75% from December 31, 2012 to $239.2 million as of December 31, 2013. Total backlog for these products decreased by approximately 22% during 2014, but remained significantly higher than the backlog levels at December 31, 2012 and 2011. If capital investment in drilling activities remains low throughout 2015, we may see lower bookings in our fabrication business in 2015 and in future periods.

 

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.

 

·                  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.

 

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For financial data relating to our business segments or geographic regions that accounted for 10% or more of consolidated revenue in any of the last three fiscal years, see Part II, Item 7 (“Management’s Discussion and Analysis of Financial Condition and Results of Operations”) and Note 24 to the Consolidated Financial Statements included in Part IV, Item 15 (“Financial Statements”) of this report.

 

Compressor Fleet

 

The size and horsepower of our worldwide natural gas compressor fleet on December 31, 2014 is summarized in the following table:

 

 

 

 

 

Aggregate

 

 

 

 

 

Number

 

Horsepower

 

% of

 

Range of Horsepower Per Unit

 

of Units

 

(in thousands)

 

Horsepower

 

0 – 200

 

3,759

 

430

 

8

%

201 – 500

 

2,460

 

671

 

12

%

501 – 800

 

693

 

429

 

8

%

801 – 1,100

 

462

 

445

 

8

%

1,101 – 1,500

 

1,641

 

2,236

 

41

%

1,501 and over

 

609

 

1,234

 

23

%

Total

 

9,624

 

5,445

 

100

%

 

As of December 31, 2014, the Partnership’s fleet included 6,472 of these compressor units comprising approximately 3,139,000 horsepower, or 75% of our and the Partnership’s combined total U.S. horsepower. As of December 31, 2014, the Partnership’s fleet included 229 compressor units, comprising approximately 79,000 horsepower, leased from our wholly-owned subsidiaries and excluded 1 compressor unit, comprising approximately 100 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.

 

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.

 

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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, 2014, our North America contract operations segment provided contract operations services primarily using a fleet of 8,638 natural gas compression units with an aggregate capacity of approximately 4,209,000 horsepower. During the year ended December 31, 2014, 25% of our total revenue and 40% of our total gross margin was generated from North America contract operations. Gross margin, a non-GAAP financial measure, is reconciled, in total, to net income (loss), its most directly comparable financial measure calculated and presented in accordance with GAAP in Part II, Item 6 (“Selected Financial Data — Non-GAAP Financial Measures”) of this report.

 

Our international operations are focused on markets that require both large horsepower compressor applications and full production and processing facilities. Our international contract operations segment typically engages in longer-term contracts and more comprehensive projects than our North America contract operations segment. International projects often require us to provide complete engineering, design and installation services and a greater investment in equipment, facilities and related installation costs. These larger projects may include several compressor units on one site or entire facilities designed to process and treat oil or natural gas to make it suitable for end use. As of December 31, 2014, our international contract operations segment provided contract operations services using a fleet of 986 natural gas compression units with an aggregate capacity of approximately 1,236,000 horsepower and a fleet of production and processing equipment. During the year ended December 31, 2014, 17% of our total revenue and 30% 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, 2014, 14% of our total revenue and 8% of our total gross margin was generated from aftermarket services.

 

Fabrication

 

Compressor and Accessory Fabrication

 

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

 

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, 2014, 14% 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, 2014, our compressor and accessory fabrication backlog was $270.3 million, compared to $157.9 million at December 31, 2013. At December 31, 2014, $24.7 million of future revenue related to our compressor and accessory fabrication backlog is expected to be recognized after December 31, 2015.

 

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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, 2014, 30% of our total revenue and 16% of our total gross margin was generated from our production and processing equipment fabrication and installation business lines.

 

As of December 31, 2014, our production and processing equipment fabrication backlog was $561.2 million, compared to $475.6 million at December 31, 2013. Typically, we expect our production and processing equipment backlog to be produced within a three to 24 month period. At December 31, 2014, $34.3 million of future revenue related to our production and processing equipment backlog is expected to be recognized after December 31, 2015. As of December 31, 2014, our installation backlog was $121.8 million, compared to $46.4 million at December 31, 2013. At December 31, 2014, $0.4 million of future revenue related to our installation backlog is expected to be recognized after December 31, 2015.

 

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 both organically and through third-party acquisitions. Our North America contract operations business is our largest business segment based on gross margin, representing 40% of our gross margin during 2014. We see opportunities to grow this business over the long term 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, we believe the long-term development of shale plays and areas focused on the production of oil and natural gas liquids in North America will lead to future 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.  As the largest provider of natural gas compression services in North America and internationally, we intend to use our scale to achieve cost savings in our operations. We are also focused on increasing productivity and optimizing our processes in our core lines of business. By making our systems and processes more efficient, we intend to lower our internal costs and improve our profitability.

 

Competitive Strengths

 

We believe we have the following key competitive strengths:

 

·                  Breadth and quality of product and service offerings.  We provide our customers a broad variety of products and services, including outsourced compression, production and processing services, as well as the sale of natural gas 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.

 

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·                  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. 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, 2014, we held a 35% 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 products and service providers 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.

 

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.

 

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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 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, 2014, approximately 23% of our revenue was generated in the Eastern Hemisphere and approximately 16% of our revenue was generated in Latin America (primarily in Argentina, 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.

 

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”) of this report. For financial data relating to our geographic concentrations, see Note 24 to the Financial Statements.

 

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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 U.S. 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.” Compliance with the final rule was required by October 2013 and the rule has not had and is not expected to 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 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.

 

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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. The rule has not had and is not expected to have a material adverse impact on our business, financial condition, results of operations or cash flows.

 

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 previously considered legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane. One bill, passed by the House of Representatives in 2009, but never adopted 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 2014.

 

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. On June 23, 2014, the U.S. Supreme Court held that greenhouse gas emissions alone cannot trigger an obligation to obtain such an air permit even if the project will substantially increase the source’s greenhouse gas emissions. However, for those sources that trigger such air permitting requirements based on their traditional criteria pollutant emissions, the permit must include a limit for greenhouse gases. In addition, the Court concluded that the rule was flawed because the EPA failed to identify a de minimis threshold for greenhouse gases below which Best Available Control Technology would not be required. The EPA has yet to set this threshold. This rule affects 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.

 

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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 liabilities 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.

 

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.

 

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Employees

 

As of December 31, 2014, 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.

 

Continued low oil and natural gas prices could decrease demand or pricing 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 oil and 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 with the Henry Hub spot price 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 operations business in these areas during 2012. Since then, natural gas prices in North America improved somewhat and generally were near or above $4.00 per MMBtu for much of 2014, but natural gas prices in 2014 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 2014. Global oil prices have fallen significantly recently. West Texas Intermediate crude oil spot prices as of December 31, 2014 were approximately 41% and 46% lower than prices at September 30, 2014 and December 31, 2013, respectively, which is expected to lead to reduced drilling of oil wells in 2015. Because we provide a significant amount of contract operations services related to the production of associated gas from oil wells and a significant amount of contract operations services related to the use of gas lift to enhance production of oil from oil wells, our operations and our levels of operating horsepower are also impacted by crude oil drilling and production activity. In addition, the Henry Hub spot price for natural gas was approximately $3.10 per MMBtu at December 31, 2014, which was approximately 24% and 27% lower than prices at September 30, 2014 and December 31, 2013, respectively, and the U.S. natural gas liquid composite price was approximately $7.84 per MMBtu for the month of November 2014, which was approximately 20% and 27% lower than prices for the months of September 2014 and December 2013, respectively, which is expected to lead to reduced drilling of gas wells in North America in 2015. If oil or natural gas production growth moderates or declines in North America or other parts of the world, 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, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Moreover, a reduction in demand for our products and services could result in our customers seeking 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, determining not to enter into new contract operations service contracts or purchase new compression and oil and natural gas production and processing equipment, or canceling or delaying orders for our products and services, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. 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.

 

The proposed Spinoff of our international contract operations, international aftermarket services and global fabrication businesses is contingent upon the satisfaction of a number of conditions, may require significant time and attention of our management, may not achieve the intended results, and difficulties in connection with the Spinoff could have an adverse effect on us.

 

As previously disclosed, our board of directors has approved a plan to reorganize our business by means of a Spinoff of our international contract operations, international aftermarket services and global fabrication businesses. For more information see “Proposed Spinoff Transaction” in Part I, Item 1 of this report. The Spinoff is contingent upon the final approval of our board of directors and other conditions, some of which are beyond our control. For this and other reasons, the Spinoff may not be completed in the expected timeframe or at all. Additionally, execution of the proposed Spinoff will continue to require significant expense and time and attention of our management. The Spinoff could distract management from the operation of our business and the execution of our other strategic initiatives. Our employees may also be uncertain about their future roles within the separate companies pending the completion of the Spinoff, which could lead to departures. Further, if the Spinoff is completed, we may not realize the benefits we expect to realize. Any such difficulties could have an adverse effect on our business, results of operations and financial condition. If completed, the Spinoff may also expose us to certain risks that could have an adverse effect on our results of operations and financial condition.

 

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The proposed Spinoff of our international contract operations, international aftermarket services and global fabrication businesses could result in substantial tax liability to us and our stockholders.

 

Historically, companies seeking to perform a tax-free spinoff transaction have been able to seek broad private letter rulings from the Internal Revenue Service (“IRS”) that the proposed spinoff transaction would qualify for tax-free treatment, with the exception of certain issues on which the IRS would not rule. However, in 2013 the IRS announced that it would no longer provide such broad advance rulings but would instead rule only on certain “significant issues.” We have not requested a ruling from the IRS regarding the Spinoff of our international contract operations, international aftermarket services and global fabrication businesses. Prior to completing the Spinoff, we expect to receive an opinion of counsel that the Spinoff should qualify as reorganization under Sections 355 and 368(a)(1)(D) of the Internal Revenue Code of 1986, as amended (the “Code”), and, as a result, neither we nor our stockholders should recognize any gain or loss for U.S. federal income tax purposes as a result of the Spinoff. However, this opinion will not be binding on the IRS or any court. Accordingly, the IRS or the courts may reach conclusions with respect to the Spinoff that are different from the conclusions reached in the opinion of counsel. If the Spinoff and certain related transactions were determined to be taxable to us, we would be subject to a substantial tax liability, which could have a material adverse effect on our business, results of operations and financial condition. In addition, if the Spinoff were taxable to our stockholders, each holder of our common stock who receives shares of Spinco would generally be treated as receiving a taxable distribution of property in an amount equal to the fair market value of the shares received.

 

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, 2014. 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 3 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 523,000 horsepower of compression in Argentina as of December 31, 2014, and we generated $172.5 million of revenue in Argentina, including $78.5 million of revenue from YPF, during the year ended December 31, 2014. 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 freely 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. During 2014, we used Argentine pesos to purchase certain short-term investments in Argentine government issued U.S. dollar denominated bonds. The effective peso to U.S. dollar exchange rate embedded in the purchase price of these bonds resulted in our recognition of a loss during the year ended December 31, 2014 of $6.5 million, which is included in other (income) expense, net, in our consolidated statements of operations.

 

In addition, the Argentine government may adopt additional regulations or policies in the future that may 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 our operations in Argentina.

 

With respect to any particular country in which we operate, the risks inherent in our activities may include the following, the occurrence of any of which could have a material adverse effect on our business, financial condition, results of operations and cash flows:

 

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

 

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

 

·                  work stoppages;

 

·                  training and retaining qualified personnel in international markets;

 

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

 

·                  tariffs and other trade barriers;

 

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

 

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

 

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

 

·                  difficulty in collecting international accounts receivable;

 

·                  potentially longer receipt of payment cycles;

 

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

 

·                  potentially adverse tax consequences or tax law changes;

 

·                  currency controls or restrictions on repatriation of earnings;

 

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

 

·                  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.

 

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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 3 and 9 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, 2014, we have received payments, including annual charges, of approximately $421 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 $142 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 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 current 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 due to the detrimental effect of recent commodity price declines on Venezuela’s economy or for other reasons, our ability to recover in full the remaining proceeds from PDVSA Gas could be adversely impacted.

 

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, the lack of availability of debt or equity financing or other factors that negatively impact our customers’ financial condition could result in a reduction in our customers’ spending for our products and services, which may result in their cancellation of month-to-month contracts, the cancellation or delay of scheduled maintenance of their existing natural gas compression and oil and natural gas production and processing equipment, their determination not to enter into new natural gas compression service contracts or purchase new compression and oil and natural gas production and processing equipment, or their determination to cancel or delay orders for our products and services. Any such action by our customers would reduce 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.

 

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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We are engaged in 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. If this litigation is resolved against us, or if in the future we do not qualify as a Heavy Equipment Dealer or our compressors do not qualify as Heavy Equipment because of new or revised Texas statutes, we will incur additional taxes which would adversely impact our results of operations and cash flows.

 

In 2011, the Texas Legislature enacted changes related to the appraisal of natural gas compressors for ad valorem tax purposes by expanding the definitions of “Heavy Equipment Dealer” and “Heavy Equipment” effective from the beginning of 2012 (the “Heavy Equipment Statutes”). Under the revised statutes, we believe we are a Heavy Equipment Dealer, that our natural gas compressors are Heavy Equipment and that we, therefore, are required to file our ad valorem tax renditions under this new methodology. A large number of appraisal review boards denied our position, and we filed petitions for review in the appropriate district courts. See Note 22 to the Financial Statements for additional information regarding 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.

 

As a result of the new methodology, our ad valorem tax expense (which is reflected in our consolidated statements of operations as a component of cost of sales (excluding depreciation and amortization expense)) includes a benefit of $12.1 million during the year ended December 31, 2014. Since the change in methodology became effective in 2012, we have recorded an aggregate benefit of $26.9 million as of December 31, 2014, of which approximately $6.2 million has been agreed to by a number of appraisal review boards and county appraisal districts and $20.7 million has been disputed and is currently in litigation. Recognizing the similarity of the issues and that these cases will ultimately be resolved by the Texas appellate courts, we have reached, or intend to reach, agreements with some of the appraisal districts to stay or abate certain of these pending district court cases. If we are unsuccessful in our litigation with the appraisal districts, we would be required to pay ad valorem taxes up to the aggregate benefit we have recorded, and the additional ad valorem tax payments may also be subject to substantial penalties and interest. Also, if we are unsuccessful in our litigation with the appraisal districts, or if legislation is enacted in Texas that repeals or alters the Heavy Equipment Statutes such that in the future we do not qualify as a Heavy Equipment Dealer or our compressors do not qualify as Heavy Equipment, then we would likely be required to pay these ad valorem taxes under the old methodology going forward, which would increase our quarterly cost of sales expense up to approximately the amount of our then most recent quarterly benefit recorded, and as a result impact our future results of operations and cash flows.

 

In addition, because the Partnership recorded $10.2 million of the $12.1 million benefit during the year ended December 31, 2014, and is expected to record a significant portion of our and the Partnership’s consolidated benefit in future periods (including 2015),  if this litigation is resolved against us or if legislation is enacted in Texas that repeals or alters the Heavy Equipment statutes, then the Partnership would also be negatively impacted, which could impair its ability to maintain or increase its distributions to its equity holders, including us, and as a result impact our results of operations and cash flows and also our ability to pay dividends in the future.

 

We could be adversely affected by violations of the U.S. Foreign Corrupt Practices Act (“FCPA”), similar worldwide anti-bribery laws and trade control laws. If we are found to have violated the FCPA or other legal requirements, we may be subject to criminal and civil penalties and other remedial measures, which could materially harm our reputation, business, results of operations, financial condition and liquidity.

 

Our international operations require us to comply with U.S. and international laws and regulations, including those involving anti-bribery and anti-corruption. For example, the FCPA and similar laws and regulations of other countries prohibit improper payments to foreign officials for the purpose of obtaining or retaining business or gaining any business advantage.

 

We operate in many parts of the world that experience high levels of corruption, and our business brings us in frequent contact with foreign officials. Our compliance policies and programs mandate compliance with all applicable anti-corruption laws but may not be completely effective in ensuring our compliance. Our training and compliance program and our internal control policies and procedures may not always protect us from violations committed by our employees or agents. Actual or alleged violations of these laws could disrupt our business and cause us to incur significant legal expenses, and could result in a material adverse effect on our reputation, business, results of operations, financial condition and liquidity. If we are found to be liable for FCPA or other anti-bribery law violations due to our own acts or omissions or due to the acts or omissions of others (including our joint venture partners, agents or other third party representatives), we could suffer from severe civil and criminal penalties or other sanctions, which could materially harm our reputation, business, results of operations financial condition and liquidity. Separately, we may face competitive disadvantages if our competitors are able to secure business, licenses or other advantages by making payments or using other methods that are prohibited by U.S. and international laws and regulations.

 

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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. Our compliance policies and programs increase our cost of doing business and may not work effectively to ensure our compliance with trade control laws. If we undergo an investigation of potential violations of trade control laws by U.S. or foreign authorities or if we fail to comply with these laws, we may incur significant legal expenses or be subject to criminal and civil penalties and other sanctions and remedial measures, which could have a material adverse impact on our reputation, business, results of operations, financial condition and liquidity.

 

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 years ended December 31, 2014 and 2013 included foreign currency losses of $8.8 million and $3.0 million, respectively.

 

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

 

We depend on distributions from our subsidiaries, including the Partnership, to meet our capital needs and pay dividends to our stockholders.

 

To generate the funds necessary to meet our obligations, fund our business and pay dividends, 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, payment of dividends and the funding of our business requirements, and as a result could have a material adverse effect on our business, financial condition and results of operations.

 

While we declared and paid quarterly dividends of $0.15 per share of common stock during 2014, there can be no assurance that we will pay dividends in the future.

 

During 2014, our Board of Directors declared and paid four quarterly cash dividends of $0.15 per share of common stock to our stockholders. 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 and operating subsidiaries, including the Partnership;

 

·                  the amount of cash distributions we receive from the Partnership attributable to our ownership interest in the Partnership;

 

·                  our future capital requirements; and

 

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

 

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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.

 

As a result of the April 2014 MidCon Acquisition, the Partnership depends on Williams Partners, L.P. (“Williams”) for a significant portion of its revenue. The Partnership’s loss of its business with Williams or the inability or failure of Williams to meet its payment obligations may adversely affect the Partnership’s financial results, which could limit the amount of cash the Partnership has available for distribution to its equity holders, including us.

 

For the year ended December 31, 2013, no customer individually accounted for 10% or more of the Partnership’s total revenue. In connection with the April 2014 MidCon Acquisition, the Partnership and Access Midstream Partners LP (“Access”) entered into a seven-year contract operations services agreement under which the Partnership provided contract compression services in 2014 to Access in regions including the Permian, Eagle Ford, Barnett, Anadarko, Mississippi Lime, Granite Wash, Woodford, Haynesville and Niobrara Basins. During the year ended December 31, 2014, Access accounted for approximately 12% of the Partnership’s revenue. Access merged with Williams in February 2015 and, when combined, Access and Williams would have accounted for approximately 15% of the Partnership’s revenue during the year ended December 31, 2014. The Partnership’s loss of its business with Williams, unless offset by additional contract compression services revenue from other customers, or the inability or failure of Williams to meet its payment obligations could have a material adverse effect on the Partnership’s business, results of operations, financial condition and ability to make cash distributions to its equity holders, including us. A reduction in the Partnership’s cash distributions to us 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, 2014, we had approximately $2.0 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, 2014, we maintained a 14.8 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 0.8 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, 2014, 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. Because the August 2014 MidCon Acquisition closed during the third quarter of 2014, the Partnership’s Total Debt to EBITDA ratio threshold was temporarily increased to 5.5 to 1.0 during the quarter ended September 30, 2014 and will continue at that level through March 31, 2015, reverting to 5.25 to 1.0 for the quarter ending June 30, 2015 and subsequent quarters. As of December 31, 2014, the Partnership maintained a 5.2 to 1.0 EBITDA to Total Interest Expense ratio, a 4.3 to 1.0 Total Debt to EBITDA ratio and a 2.0 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 agreements, which would accelerate the Partnership’s obligation to repay its indebtedness under those agreements. As of December 31, 2014, 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.

 

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

 

As of December 31, 2014, after taking into consideration interest rate swaps, we had $585.5 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, 2014 would result in an annual increase in our interest expense of approximately $5.9 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 22 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 may not be able to consummate additional contributions or sales of portions of our U.S. contract operations business to the Partnership.

 

In the future, we may transfer additional portions of our U.S. contract operations business to the Partnership, 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 any 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 a portion 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.

 

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.

 

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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.

 

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 IRS 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 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 U.S. 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 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 U.S. 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.

 

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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, the Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that could affect publicly traded partnerships. If successful, the Obama administration’s proposal or other similar proposals could eliminate 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. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for the Partnership to meet the exception for certain publicly traded partnerships to be treated as partnerships 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 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.

 

Tax legislation and administrative initiatives or challenges to our tax positions could adversely affect our results of operations and financial condition.

 

We operate in locations throughout the United States and internationally and, as a result, we are subject to the tax laws and regulations of U.S. federal, state, local and foreign governments. From time to time, various legislative or administrative initiatives may be proposed that could adversely affect our tax positions. There can be no assurance that our tax provision or tax payments will not be adversely affected by these initiatives. In addition, international, U.S. federal, state and local tax laws and regulations are extremely complex and subject to varying interpretations. There can be no assurance that our tax positions will not be challenged by relevant tax authorities or that we would be successful in any such challenge.

 

U.S. Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect demand for our contract operations services and production and processing equipment.

 

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into target geological formations to fracture the surrounding rock and stimulate production. Recently, there has been increased public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies, and proposals have been made to enact separate U.S. federal, state and local legislation that would increase the regulatory burden imposed on hydraulic fracturing.

 

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At the U.S. federal level, the EPA has asserted U.S. federal regulatory authority pursuant to the U.S. federal Safe Drinking Water Act (the “SDWA”) over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2013 addressing the performance of such activities. Also, in May 2014, the EPA issued an Advance Notice of Proposed Rulemaking to collect data on chemicals used in hydraulic fracturing operations under Section 8 of the Toxic Substances Control Act. To date, no other action has been taken. Further, the EPA has announced its intention to propose regulations under the CWA by sometime in 2015 governing wastewater discharges from hydraulic fracturing and certain other natural gas operations. In addition, the EPA is conducting a study of the potential impacts of hydraulic fracturing activities on water resources and a draft final report is anticipated sometime in 2015 for peer review and public comment. The results of this study or similar governmental review could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise. Also, the U.S. Department of the Interior published a revised proposed rule on May 16, 2013, that would update exiting regulation of hydraulic fracturing activities on U.S. federal lands, including requirements for chemical disclosure, wellbore integrity and handling of flowback water.

 

At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example in May 2013, the Texas Railroad Commission adopted new rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. Local governments may also seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance of well drilling in general or hydraulic fracturing in particular. If new or more stringent U.S. 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, experience delays or curtailment in the pursuit of exploration, development or production activities and perhaps even be precluded from drilling wells. Any such restrictions 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.” Compliance with the final rule was required by October 2013.

 

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.

 

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.

 

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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 and changes in these regulations could increase our costs or liabilities.

 

We are subject to a variety of U.S. federal, state, local and international laws and regulations relating to, for example, 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. Moreover, failure to comply with these environmental laws and regulations may result in the imposition of administrative, civil and criminal penalties and the issuance of injunctions delaying or prohibiting operations.

 

We may need to apply for or amend facility permits or licenses from time to time with respect to storm water or wastewater discharges, waste handling, or air emissions relating to manufacturing activities or equipment operations, which subjects us to new or revised permitting conditions that may be onerous or costly to comply with. In addition, certain of our customer service arrangements may require us to operate, on behalf of a specific customer, petroleum storage units such as underground tanks or pipelines and other regulated units, all of which may impose additional compliance and permitting obligations.

 

We conduct operations at numerous facilities in a wide variety of locations across the continental U.S. and internationally. The operations at many of these facilities require environmental permits or other authorizations. Additionally, natural gas compressors at many of our customers’ facilities require individual air permits or general authorizations to operate under various air regulatory programs established by rule or regulation. These permits and authorizations frequently contain numerous compliance requirements, including monitoring and reporting obligations and operational restrictions, such as emission limits. Given the large number of facilities in which we operate, and the numerous environmental permits and other authorizations that are applicable to our operations, we may occasionally identify or be notified of technical violations of certain requirements existing in various permits or other authorizations. Occasionally, we have been assessed penalties for our non-compliance, and we could be subject to such penalties in the future.

 

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

 

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

 

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

 

The U.S. Congress has previously considered legislation to restrict or regulate emissions of greenhouse gases, such as carbon dioxide and methane. One bill, passed by the House of Representatives in 2009, but never adopted 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 2014.

 

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. On June 23, 2014, the U.S. Supreme Court held that greenhouse gas emissions alone cannot trigger an obligation to obtain such an air permit even if the project will substantially increase the source’s greenhouse gas emissions. However, for those sources that trigger such air permitting requirements based on their traditional criteria pollutant emissions, the permit must include a limit for greenhouse gases. In addition, the Court concluded that the rule was flawed because the EPA failed to identify a de minimis threshold for greenhouse gases below which Best Available Control Technology would not be required. The EPA has yet to set this threshold. This rule affects 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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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, 2014:

 

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 22 (“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, 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

 

Year Ended December 31, 2014

 

 

 

 

 

First Quarter

 

$

44.66

 

$

33.42

 

Second Quarter

 

$

45.90

 

$

40.81

 

Third Quarter

 

$

47.01

 

$

41.16

 

Fourth Quarter

 

$

45.35

 

$

30.58

 

 

On February 19, 2015, the closing price of our common stock was $32.35 per share. As of February 12, 2015, there were approximately 1,319 holders of record of our common stock.

 

We had not paid any cash dividends on our common stock since our formation through the year ended December 31, 2013. During 2014, our Board of Directors declared and paid quarterly cash dividends of $0.15 per share of common stock to our stockholders. The following table sets forth dividends declared and paid during 2014 per common share:

 

Declaration Date

 

Payment Date

 

Dividends per
Common Share

 

Total Dividends

 

February 25, 2014

 

March 28, 2014

 

$

0.15

 

$

10.0 million

 

April 29, 2014

 

May 16, 2014

 

0.15

 

10.0 million

 

July 31, 2014

 

August 18, 2014

 

0.15

 

10.0 million

 

October 30, 2014

 

November 17, 2014

 

0.15

 

10.3 million

 

 

On January 30, 2015, our board of directors declared a quarterly dividend of $0.15 per share of common stock which was paid on February 17, 2015 to stockholders of record at the close of business on February 9, 2015. 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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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, 2009. 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.

 

Comparison of Five Year Cumulative Total Return

 

GRAPHIC

 

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.

 

Unregistered Sales of Equity Securities and Use of Proceeds

 

Repurchase of Equity Securities

 

The following table summarizes our repurchases of equity securities during the three months ended December 31, 2014:

 

Period

 

Total Number of
Shares Repurchased
(1)

 

Average
Price Paid
Per Unit

 

Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs

 

Maximum Number of Shares
yet to be Purchased Under the
Publicly Announced Plans or
Programs

 

October 1, 2014 - October 31, 2014

 

6,250

 

$

44.86

 

N/A

 

N/A

 

November 1, 2014 - November 30, 2014

 

 

 

N/A

 

N/A

 

December 1, 2014 - December 31, 2014

 

12,327

 

31.79

 

N/A

 

N/A

 

Total

 

18,577

 

$

36.19

 

N/A

 

N/A

 

 


(1)         Represents shares withheld to satisfy employees’ tax withholding obligations in connection with vesting of restricted stock awards during the period.

 

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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, 2014, which has been derived from our audited Financial Statements. As discussed in Note 3 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,

 

 

 

2014

 

2013

 

2012

 

2011

 

2010

 

Statement of Operations Data:

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

2,899,738

 

$

3,160,404

 

$

2,794,246

 

$

2,612,625

 

$

2,394,037

 

Gross margin(1)

 

1,031,294

 

963,006

 

829,408

 

720,414

 

784,707

 

Selling, general and administrative

 

377,754

 

358,173

 

375,647

 

352,096

 

350,709

 

Depreciation and amortization

 

386,071

 

327,505

 

346,177

 

352,793

 

387,571

 

Long-lived asset impairment(2)

 

46,679

 

28,637

 

136,614

 

6,068

 

143,874

 

Restructuring charges(3)

 

7,553

 

 

6,471

 

11,594

 

 

Goodwill impairment(4)

 

 

 

 

196,807

 

 

Interest expense

 

114,178

 

115,745

 

134,376

 

149,473

 

136,149

 

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

 

(14,553

)

(19,000

)

(51,483

)

471

 

609

 

Other (income) expense, net

 

1,747

 

(24,501

)

506

 

(5,597

)

(11,481

)

Provision for (benefit from) income taxes

 

58,657

 

84,719

 

(45,755

)

(11,717

)

(64,559

)

Income (loss) from continuing operations

 

53,208

 

91,728

 

(73,145

)

(331,574

)

(158,165

)

Income (loss) from discontinued operations, net of tax(6)

 

72,674

 

64,014

 

35,976

 

(8,044

)

44,924

 

Net income (loss) attributable to noncontrolling interest

 

27,716

 

32,578

 

2,317

 

990

 

(11,416

)

Net income (loss) attributable to Exterran stockholders

 

98,166

 

123,164

 

(39,486

)

(340,608

)

(101,825

)

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

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

0.38

 

$

0.90

 

$

(1.19

)

$

(5.31

)

$

(2.37

)

Diluted

 

$

0.36

 

$

0.89

 

$

(1.19

)

$

(5.31

)

$

(2.37

)

Weighted average common shares outstanding used in income (loss) per common share:

 

 

 

 

 

 

 

 

 

 

 

Basic

 

66,234

 

64,454

 

63,436

 

62,624

 

61,995

 

Diluted

 

69,090

 

65,003

 

63,436

 

62,624

 

61,995

 

Other Financial Data:

 

 

 

 

 

 

 

 

 

 

 

EBITDA, as adjusted(7)

 

$

658,839

 

$

633,893

 

$

460,661

 

$

388,089

 

$

434,361

 

Capital expenditures:

 

 

 

 

 

 

 

 

 

 

 

Contract Operations Equipment:

 

 

 

 

 

 

 

 

 

 

 

Growth(8)

 

$

389,712

 

$

231,195

 

$

261,548

 

$

132,986

 

$

126,546

 

Maintenance(9)

 

96,144

 

95,197

 

100,208

 

90,477

 

69,257

 

Other

 

55,839

 

65,333

 

66,975

 

48,687

 

35,610

 

Cash flows provided by (used in):

 

 

 

 

 

 

 

 

 

 

 

Operating activities

 

$

379,369

 

$

355,704

 

$

389,925

 

$

120,443

 

$

366,313

 

Investing activities

 

(929,851

)

(196,451

)

(205,451

)

(239,184

)

(102,965

)

Financing activities

 

558,481

 

(156,702

)

(171,290

)

99,290

 

(298,667

)

Dividends declared and paid per common share

 

$

0.60

 

$

 

$

 

$

 

$

 

Balance Sheet Data:

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

39,739

 

$

35,665

 

$

34,601

 

$

21,903

 

$

44,361

 

Working capital(10)

 

654,958

 

580,425

 

463,429

 

454,046

 

402,401

 

Property, plant and equipment, net

 

3,326,892

 

2,820,272

 

2,838,719

 

2,911,711

 

2,990,284

 

Total assets

 

4,857,147

 

4,227,157

 

4,254,847

 

4,360,662

 

4,741,536

 

Long-term debt

 

2,026,902

 

1,502,155

 

1,564,923

 

1,773,039

 

1,897,147

 

Total Exterran stockholder’s equity

 

1,797,260

 

1,662,090

 

1,478,613

 

1,437,236

 

1,609,448

 

 


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

 

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(2)                  Year ended December 31, 2014: During 2014, we evaluated the future deployment of our idle fleet and determined to retire and either sell or re-utilize the key components of approximately 310 idle compressor units, representing approximately 131,000 horsepower, previously used to provide services in our North America and international contract operations segments. As a result, we performed an impairment review and recorded a $33.3 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 fleet review during 2014, 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 certain of the remaining units. This resulted in an additional impairment of $12.7 million to reduce the book value of each unit to its estimated fair value.

 

During the year ended December 31, 2014, we evaluated other long-lived assets for impairment and recorded long-lived asset impairments of $0.7 million on these assets.

 

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.

 

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.

 

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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.

 

(3)                  Year ended December 31, 2014: As discussed in Note 2 to the Financial Statements, in November 2014, we announced that our board of directors had authorized management to pursue a plan to separate our international contract operations, international aftermarket services and global fabrication businesses into an independent, publicly traded company. During the year ended December 31, 2014, we incurred $2.2 million of costs associated with the planned Spinoff which were primarily related to legal and consulting fees. The costs incurred in conjunction with the planned Spinoff are included in restructuring charges in our consolidated statements of operations. This separation is expected to be completed in the second half of 2015.

 

In January 2014, we announced a plan to centralize our make-ready operations to improve the cost and efficiency of our shops and further enhance the competitiveness of our fleet of compressors. As part of this plan, we examined both recent and anticipated changes in the North America market, including the throughput demand of our shops and the addition of new equipment to our fleet. To better align our costs and capabilities with the current market, we determined to close several of our make-ready shops. The centralization of our make-ready operations was completed in the second quarter of 2014. During the year ended December 31, 2014, we incurred $5.4 million of restructuring charges primarily related to termination benefits and a non-cash write-down of inventory associated with the centralization of our make-ready operations.

 

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 were the result of 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.

 

(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.

 

(5)                  Years ended December 31, 2014, 2013 and 2012: As discussed in Note 9 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 $14.7 million, $19.0 million and $14.1 million during the years ended December 31, 2014, 2013 and 2012, respectively. The remaining principal amount due to us of approximately $26 million as of December 31, 2014, 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.

 

(6)                  Years ended December 31, 2014, 2013 and 2012: As discussed in Note 3 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 $72.6 million, $69.3 million and $16.8 million during the years ended December 31, 2014, 2013, and 2012, respectively. The remaining principal amount due to us of approximately $116 million as of December 31, 2014, 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.

 

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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.

 

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

 

(8)               Growth capital expenditures are made to expand or to replace partially or fully depreciated assets or to expand the operating capacity or revenue of existing or new assets, whether through construction, acquisition or modification. The majority of our growth capital expenditures are related to the acquisition cost of new compressor units and processing and treating equipment that we add to our fleet and installation costs on integrated projects. In addition, growth capital expenditures can also include the upgrading of major components on an existing compressor unit where the current configuration of the compressor unit is no longer in demand and the compressor unit is not likely to return to an operating status without the capital expenditures. These latter expenditures substantially modify the operating parameters of the compressor unit such that it can be used in applications that it previously was not suited for.

 

(9)         Maintenance capital expenditures are made to maintain the existing operating capacity of our assets and related cash flows further extending the useful lives of the assets. Maintenance capital expenditures are related to the major overhauls of significant components of a compressor unit, such as the engine, compressor and cooler, that return the components to a like new condition, but do not modify the applications that the compressor unit was designed for.

 

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

 

Non-GAAP Financial Measures

 

We define gross margin as total revenue less cost of sales (excluding depreciation and amortization expense). Gross margin is included as a supplemental disclosure because it is a primary measure used by our management 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,

 

 

 

2014

 

2013

 

2012

 

2011

 

2010

 

Net income (loss)

 

$

125,882

 

$

155,742

 

$

(37,169

)

$

(339,618

)

$

(113,241

)

Selling, general and administrative

 

377,754

 

358,173

 

375,647

 

352,096

 

350,709

 

Depreciation and amortization

 

386,071

 

327,505

 

346,177

 

352,793

 

387,571

 

Long-lived asset impairment

 

46,679

 

28,637

 

136,614

 

6,068

 

143,874

 

Restructuring charges

 

7,553

 

 

6,471

 

11,594

 

 

Goodwill impairment

 

 

 

 

196,807

 

 

Interest expense

 

114,178

 

115,745

 

134,376

 

149,473

 

136,149

 

Equity in (income) loss of non-consolidated affiliates

 

(14,553

)

(19,000

)

(51,483

)

471

 

609

 

Other (income) expense, net

 

1,747

 

(24,501

)

506

 

(5,597

)

(11,481

)

Provision for (benefit from) income taxes

 

58,657

 

84,719

 

(45,755

)

(11,717

)

(64,559

)

(Income) loss from discontinued operations, net of tax

 

(72,674

)

(64,014

)

(35,976

)

8,044

 

(44,924

)

Gross margin

 

$

1,031,294

 

$

963,006

 

$

829,408

 

$

720,414

 

$

784,707

 

 

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, expensed acquisition costs and other items. 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, expensed acquisition costs and other items. 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,

 

 

 

2014

 

2013

 

2012

 

2011

 

2010

 

Net income (loss)

 

$

125,882

 

$

155,742

 

$

(37,169

)

$

(339,618

)

$

(113,241

)

(Income) loss from discontinued operations, net of tax

 

(72,674

)

(64,014

)

(35,976

)

8,044

 

(44,924

)

Depreciation and amortization

 

386,071

 

327,505

 

346,177

 

352,793

 

387,571

 

Long-lived asset impairment

 

46,679

 

28,637

 

136,614

 

6,068

 

143,874

 

Restructuring charges

 

7,553

 

 

6,471

 

11,594

 

 

Goodwill impairment

 

 

 

 

196,807

 

 

Investment in non-consolidated affiliates impairment

 

197

 

 

224

 

471

 

609

 

Proceeds from sale of joint venture assets

 

(14,750

)

(19,000

)

(51,707

)

 

 

Interest expense

 

114,178

 

115,745

 

134,376

 

149,473

 

136,149

 

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

 

3,614

 

4,313

 

7,406

 

14,174

 

(6,255

)

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

)

Loss on sale of businesses

 

961

 

 

 

 

 

Expensed acquisition costs

 

2,471

 

246

 

 

 

 

Provision for (benefit from) income taxes

 

58,657

 

84,719

 

(45,755

)

(11,717

)

(64,559

)

EBITDA, as adjusted

 

$

658,839

 

$

633,893

 

$

460,661

 

$

388,089

 

$

434,361

 

 

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

 

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our 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 natural gas 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.

 

Proposed Spinoff Transaction

 

On November 17, 2014, we announced that our board of directors had authorized management to pursue a plan to separate (the “Spinoff”) our international contract operations, international aftermarket services and global fabrication businesses into an independent, publicly traded company (“Spinco”). To effect the Spinoff, we intend to distribute, on a pro rata basis, all of the shares of Spinco common stock to our stockholders as of the record date for the Spinoff. The Spinoff is subject to market conditions, the receipt of an opinion of counsel as to the tax-free nature of the transaction, completion of a review by the U.S. Securities and Exchange Commission of a Form 10 to be filed by Spinco, the execution of separation and intercompany agreements and final approval of our board of directors. Upon completion of the Spinoff, we and Spinco will be independent, publicly traded companies with separate public ownership, boards of directors and management, and we will own and operate the remaining U.S. contract operations and U.S. aftermarket services businesses that we currently own. In addition, we will continue to hold interests in the Partnership, which include the sole general partner interest and certain limited partner interests, as well as all of the incentive distribution rights in the Partnership.

 

Spinco is expected to issue certain third-party debt instruments and borrow funds on or before the completion of the Spinoff. Certain, if not all, of the proceeds received by Spinco from such borrowings are expected to be distributed to us on or before the completion of the Spinoff and we expect to use those distributed funds to repay, in whole or in part, our (but not the Partnership’s) outstanding debt instruments. Although our current goal is to complete the Spinoff in the second half of 2015, there are no assurances as to when the proposed Spinoff will be completed, if at all, or if the Spinoff will be completed based on the expected plans.

 

Unless otherwise indicated, this discussion in Part II, Item 7 (“Management’s Discussion and Analysis of Financial Condition and Results of Operations”) excludes the potential future impact of the proposed Spinoff transaction, if consummated. The effect of the proposed Spinoff transaction could significantly change and materially impact our business, financial condition, results of operations and cash flows.

 

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 products and service providers, changes in oil and natural gas exploration and production spending normally result in changes in demand for our products and services.

 

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Natural gas consumption in the U.S. for the twelve months ended November 30, 2014 increased by approximately 5% compared to the twelve months ended November 30, 2013. The EIA forecasts that total U.S. natural gas consumption will increase by 1.4% in 2015 compared to 2014 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, 2014 increased by approximately 5% compared to the twelve months ended November 30, 2013. The EIA forecasts that total U.S. natural gas marketed production will increase by 4% in 2015 compared to 2014 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.

 

Global oil and U.S. natural gas prices have declined significantly in the last several months, and, as a result, research analysts are forecasting declines in U.S. and worldwide capital spending for drilling activity in 2015, and U.S. producers and other producers around the world have begun to announce reduced capital budgets for this year.

 

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.

 

During 2014, we continued to see steady activity in North America 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 continued to be partially offset by horsepower declines in more mature and predominantly dry gas markets, where we provide a significant amount of contract operations services. During 2014, excluding operating horsepower added through acquisitions, our operating horsepower increased at a higher rate in the shale plays and areas focused on the production of oil and natural gas liquids than the declines we experienced in the more mature and predominately dry gas plays in North America. Historically, oil and natural gas prices in North America have been volatile. Global oil prices have fallen significantly recently. West Texas Intermediate crude oil spot prices as of December 31, 2014 were approximately 41% and 46% lower than prices at September 30, 2014 and December 31, 2013, respectively, which is expected to lead to reduced drilling of oil wells in 2015. Because we provide a significant amount of contract operations services related to the production of associated gas from oil wells and a significant amount of contract operations services related to the use of gas lift to enhance production of oil from oil wells, our operations and our levels of operating horsepower are also impacted by crude oil drilling and production activity. In addition, the Henry Hub spot price for natural gas was approximately $3.10 per MMBtu at December 31, 2014, which was approximately 24% and 27% lower than prices at September 30, 2014 and December 31, 2013, respectively, and the U.S. natural gas liquid composite price was approximately $7.84 per MMBtu for the month of November 2014, which was approximately 20% and 27% lower than prices for the months of September 2014 and December 2013, respectively, which is expected to lead to reduced drilling of gas wells in North America in 2015. During periods of lower oil or natural gas prices, oil and natural gas production growth could moderate or decline in North America and internationally, and as a result the demand or pricing for our contract operations services and oil and natural gas production and processing equipment could be adversely affected. Booking activity levels for our fabricated products in North America during the year ended December 31, 2014 increased by approximately 46% compared to the year ended December 31, 2013 and our North America fabrication backlog increased by approximately 82% as of December 31, 2014 compared to December 31, 2013. Continued growth in North America requires capital investment by our customers in new projects over the long run. As a result of these low oil and gas prices, we believe there will be less oil and gas drilling activity in North America in 2015 compared to 2014. If capital investment in drilling activities remains low throughout 2015, we may see lower bookings in our North America fabrication business in 2015 and in future periods.

 

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. Growth in our international services and products businesses is somewhat dependent on international infrastructure projects, many of which are based on longer-term plans of our customers that can be driven by their local market demand and, to some extent, local pricing for natural gas and can be less tied to near term commodity prices.

 

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. Based on demand we see for contract operations, we anticipate investing more capital in our international contract operations business and less capital in our North America contract operations business in 2015 than we did in 2014. The increased investment in our international contract operations business during 2015 is driven by several large multi-year projects contracted in 2014 that are scheduled to start earning revenue in 2015 and 2016.

 

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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, scheduled interest and debt repayments and anticipated dividends through December 31, 2015; 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 may from time to time seek to repurchase our equity. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.

 

We may 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.

 

Certain Key Challenges and Uncertainties

 

Market conditions in the oil and 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 Oil and Natural Gas Pricing.  During 2014, we continued to see steady activity in North America 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 continued to be partially offset by horsepower declines in more mature and predominantly dry gas markets, where we provide a significant amount of contract operations services. Historically, oil and natural gas prices in North America have been volatile. Global oil prices and North America natural gas prices have fallen significantly recently. During periods of lower oil or natural gas prices, oil and natural gas production growth could moderate or decline in North America, and as a result the demand or pricing for our natural gas compression and oil and natural gas production and processing equipment and services 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.

 

Execution of the Proposed Spinoff.  Execution of the proposed Spinoff transaction will require significant expense and the time and attention of our management. The Spinoff could distract management from the operation of our business and the execution of our other strategic initiatives. Our employees may also be uncertain about their future roles within the separate companies pending the completion of the Spinoff, which could lead to departures. Further, if the Spinoff is completed, we may not realize the benefits we expect to realize. Any such difficulties could have an adverse effect on our business, results of operations and financial condition. If completed, the Spinoff may also expose us to certain risks that could have an adverse effect on our results of operations and financial condition. The Spinoff is contingent upon the final approval of our board of directors and other conditions, some of which are beyond our control. For this and other reasons, the Spinoff may not be completed in the expected timeframe or at all.

 

Personnel, Hiring, Training and Retention.  Both in North America and internationally, we believe our ability to grow may 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 oil and 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. Global oil prices and North America natural gas prices have fallen significantly recently, and, as a result, research analysts are forecasting declines in U.S. and worldwide capital spending for drilling activity in 2015, and producers in the U.S. and other parts of the world have begun to announce reduced capital budgets for this year. In addition, 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.

 

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Summary of Results

 

As discussed in Note 3 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 generated net income attributable to Exterran stockholders of $98.2 million and $123.2 million during the years ended December 31, 2014 and 2013, respectively, and net loss attributable to Exterran stockholders of $39.5 million during the year ended December 31, 2012. The decrease in net income attributable to Exterran stockholders during the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily due to an increase in depreciation and amortization expense, a $20.0 million decrease in gain on sale of property, plant and equipment, an increase in SG&A expense and an increase in long-lived asset impairment, partially offset by an increase in gross margin and a decrease in income tax expense. 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, an increase in income from discontinued operations and a $22.8 million 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. Our EBITDA, as adjusted, was $658.8 million, $633.9 million and $460.7 million during the years ended December 31, 2014, 2013 and 2012, respectively. EBITDA, as adjusted, during the year ended December 31, 2014 compared to the year ended December 31, 2013 increased primarily due to higher gross margin as discussed above, partially offset by a $20.0 million decrease in gain on sale of property, plant and equipment and an increase in SG&A expense. EBITDA, as adjusted, during the year ended December 31, 2013 compared to the year ended December 31, 2012 increased primarily due to higher gross margins as discussed above and a $22.8 million increase in gain on sale of property, plant and equipment 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.

 

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,

 

 

 

2014

 

2013

 

2012

 

Revenue:

 

 

 

 

 

 

 

North America Contract Operations

 

$

729,103

 

$

627,844

 

$

596,011

 

International Contract Operations

 

493,853

 

476,016

 

463,957

 

Aftermarket Services

 

392,774

 

395,600

 

385,861

 

Fabrication

 

1,284,008

 

1,660,944

 

1,348,417

 

 

 

$

2,899,738

 

$

3,160,404

 

$

2,794,246

 

Gross Margin(1):

 

 

 

 

 

 

 

North America Contract Operations

 

$

412,961

 

$

345,355

 

$

311,308

 

International Contract Operations

 

308,445

 

279,072

 

279,349

 

Aftermarket Services

 

84,342

 

86,182

 

82,271

 

Fabrication

 

225,546

 

252,397

 

156,480

 

 

 

$

1,031,294

 

$

963,006

 

$

829,408

 

Gross Margin percentage(2):

 

 

 

 

 

 

 

North America Contract Operations

 

57

%

55

%

52

%

International Contract Operations

 

62

%

59

%

60

%

Aftermarket Services

 

21

%

22

%

21

%

Fabrication

 

18

%

15

%

12

%

 


(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.

 

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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,

 

 

 

2014

 

2013

 

2012

 

Total Available Horsepower (at period end):

 

 

 

 

 

 

 

North America

 

4,209

 

3,429

 

3,376

 

International

 

1,236

 

1,255

 

1,265

 

Total

 

5,445

 

4,684

 

4,641

 

Total Operating Horsepower (at period end):

 

 

 

 

 

 

 

North America

 

3,700

 

2,884

 

2,900

 

International

 

976

 

986

 

1,007

 

Total

 

4,676

 

3,870

 

3,907

 

Average Operating Horsepower:

 

 

 

 

 

 

 

North America

 

3,346

 

2,871

 

2,839

 

International

 

969

 

995

 

991

 

Total

 

4,315

 

3,866

 

3,830

 

Horsepower Utilization (at period end):

 

 

 

 

 

 

 

North America

 

88

%

84

%

86

%

International

 

79

%

79

%

80

%

Total

 

86

%

83

%

84

%

 

 

 

December 31,

 

 

 

2014

 

2013

 

2012

 

Compressor and Accessory Fabrication Backlog

 

$

270,297

 

$

157,893

 

$

256,315

 

Production and Processing Equipment Fabrication Backlog

 

561,153

 

475,565

 

563,826

 

Installation Backlog

 

121,751

 

46,429

 

245,573

 

Fabrication Backlog

 

$

953,201

 

$

679,887

 

$

1,065,714

 

 

The Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013

 

North America Contract Operations

(dollars in thousands)

 

 

 

Years Ended December 31,

 

Increase

 

 

 

2014

 

2013

 

(Decrease)

 

Revenue

 

$

729,103

 

$

627,844

 

16

%

Cost of sales (excluding depreciation and amortization expense)

 

316,142

 

282,489

 

12

%

Gross margin

 

$

412,961

 

$

345,355

 

20

%

Gross margin percentage

 

57

%

55

%

2

%

 

The increase in revenue during the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily attributable to a 17% increase in average operating horsepower, which included the assets acquired in the August 2014 MidCon Acquisition and the April 2014 MidCon Acquisition as well as organic growth in operating horsepower, and higher rates in the current year, partially offset by a $12.1 million decrease in revenue with little incremental cost due to the termination of three natural gas processing plant contracts during the second quarter of 2013. Gross margin (defined as revenue less cost of sales, excluding depreciation and amortization expense) and gross margin percentage increased during the year ended December 31, 2014 compared to the year ended December 31, 2013 primarily due to the revenue increase explained above. 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’) to this report.

 

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International Contract Operations

(dollars in thousands)

 

 

 

Years Ended December 31,

 

Increase

 

 

 

2014

 

2013

 

(Decrease)

 

Revenue

 

$

493,853

 

$

476,016

 

4

%

Cost of sales (excluding depreciation and amortization expense)

 

185,408

 

196,944

 

(6

)%

Gross margin

 

$

308,445

 

$

279,072

 

11

%

Gross margin percentage

 

62

%

59

%

3

%

 

The increase in revenue during the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily due to a $16.1 million increase in revenue in Brazil primarily related to the start-up of a project in the current year with little incremental costs, an $8.0 million increase in revenue related to contracts that commenced in 2013 in Trinidad and Iraq, a $3.8 million increase in revenue in Mexico primarily due to accelerated revenues associated with a project that terminated in the second quarter of 2014 and a $3.8 million increase in revenue in Indonesia primarily due to an increase in production. These increases in revenue were partially offset by a $7.2 million decrease in revenue in Argentina driven by devaluation of the Argentine peso in the current year partially offset by higher rates in the current year period and a $6.1 million decrease in Colombia primarily due to recognition of revenue with no incremental cost on the termination of a contract during the year ended December 31, 2013. Gross margin and gross margin percentage increased during the year ended December 31, 2014 compared to the year ended December 31, 2013 primarily due to the revenue increase explained above, excluding the devaluation of the Argentine peso in the current year as the impact on gross margin and gross margin percentage was insignificant.

 

Aftermarket Services

(dollars in thousands)

 

 

 

Years Ended December 31,

 

Increase

 

 

 

2014

 

2013

 

(Decrease)

 

Revenue

 

$

392,774

 

$

395,600

 

(1

)%

Cost of sales (excluding depreciation and amortization expense)

 

308,432

 

309,418

 

0

%

Gross margin

 

$

84,342

 

$

86,182

 

(2

)%

Gross margin percentage

 

21

%

22

%

(1

)%

 

The decrease in revenue during the year ended December 31, 2014 compared to the year ended December 31, 2013 was due to a decrease in revenue in North America of $4.9 million, partially offset by increases in revenue in the Eastern Hemisphere and Latin America of $1.1 million and $1.0 million, respectively. Gross margin decreased during the year ended December 31, 2014 compared to the year ended December 31, 2013 primarily due to a decrease in gross margin in North America of $4.6 million, partially offset by an increase in gross margin in the Eastern Hemisphere of $2.6 million.

 

Fabrication

(dollars in thousands)

 

 

 

Years Ended December 31,

 

Increase

 

 

 

2014

 

2013

 

(Decrease)

 

Revenue

 

$

1,284,008

 

$

1,660,944

 

(23

)%

Cost of sales (excluding depreciation and amortization expense)

 

1,058,462

 

1,408,547

 

(25

)%

Gross margin

 

$

225,546

 

$

252,397

 

(11

)%

Gross margin percentage

 

18

%

15

%

3

%

 

The decrease in revenue during the year ended December 31, 2014 compared to the year ended December 31, 2013 was due to lower revenue in North America, Latin America and the Eastern Hemisphere of $229.0 million, $83.3 million and $64.6 million, respectively. The decrease in revenue in North America was due to a decrease of $143.6 million in installation revenue primarily due to a project for one customer that was completed in 2013 and a decrease of $122.4 million in production and processing equipment revenue, partially offset by a $37.0 million increase in compressor revenue. The decrease in Latin America revenue was due to decreases of $59.2 million, $14.0 million and $10.1 million in installation revenue, production and processing equipment revenue and compressor revenue, respectively. The decrease in revenue in the Eastern Hemisphere was due to a decrease of $106.4 million in compressor revenue, partially offset by increases of $24.0 million and $17.8 million in installation revenue and production and processing equipment revenue, respectively. The decrease in gross margin was primarily caused by the revenue decrease explained above and additional costs charged to a project in North America related to a warranty expense accrual during the year ended December 31, 2014, partially offset by cost overruns on three large turnkey projects recorded during the year ended December 31, 2013. The increase in gross margin percentage was primarily caused by cost overruns on three large turnkey projects recorded during the year ended December 31, 2013, partially offset by additional costs charged to a project in North America related to a warranty expense accrual during the year ended December 31, 2014.

 

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Costs and Expenses

(dollars in thousands)

 

 

 

Years Ended December 31,

 

Increase

 

 

 

2014

 

2013

 

(Decrease)

 

Selling, general and administrative

 

$

377,754

 

$

358,173

 

5

%

Depreciation and amortization

 

386,071

 

327,505

 

18

%

Long-lived asset impairment

 

46,679

 

28,637

 

63

%

Restructuring charges

 

7,553

 

 

n/a

 

Interest expense

 

114,178

 

115,745

 

(1

)%

Equity in income of non-consolidated affiliates

 

(14,553

)

(19,000

)

(23

)%

Other (income) expense, net

 

1,747

 

(24,501

)

(107

)%

 

The increase in SG&A expense during the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily due to a $14.5 million increase in compensation and benefits costs and a $5.9 million increase in state and local taxes. SG&A as a percentage of revenue was 13% and 11% during the years ended December 31, 2014 and 2013, respectively.

 

Depreciation and amortization expense during the year ended December 31, 2014 compared to the year ended December 31, 2013 increased primarily due to accelerated depreciation on contract operations projects in Brazil and an increase in property, plant and equipment and intangible asset additions, including the assets acquired in the August 2014 MidCon Acquisition and the April 2014 MidCon Acquisition.

 

During the year ended December 31, 2014, we evaluated the future deployment of our idle fleet and determined to retire and either sell or re-utilize the key components of approximately 310 idle compressor units, representing approximately 131,000 horsepower, previously used to provide services in our North America and international contract operations segments. As a result, we performed an impairment review and recorded a $33.3 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 fleet review during 2014, 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 certain of the remaining units. This resulted in an additional impairment of $12.7 million to reduce the book value of each unit to its estimated fair value.

 

During the year ended December 31, 2014, we evaluated other long-lived assets for impairment and recorded long-lived asset impairments of $0.7 million on these assets.

 

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.

 

As discussed in Note 2 to the Financial Statements, in November 2014, we announced that our board of directors had authorized management to pursue a plan to separate our international contract operations, international aftermarket services and global fabrication businesses into an independent, publicly traded company. During the year ended December 31, 2014, we incurred $2.2 million of costs associated with the planned Spinoff which were primarily related to legal and consulting fees. The costs incurred in conjunction with the planned Spinoff are included in restructuring charges in our consolidated statements of operations. This separation is expected to be completed in the second half of 2015. We cannot currently estimate the total restructuring costs that will be incurred as a result of the Spinoff. See Note 15 to the Financial Statements for further discussion of these charges.

 

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In January 2014, we announced a plan to centralize our make-ready operations to improve the cost and efficiency of our shops and further enhance the competitiveness of our fleet of compressors. As part of this plan, we examined both recent and anticipated changes in the North America market, including the throughput demand of our shops and the addition of new equipment to our fleet. To better align our costs and capabilities with the current market, we determined to close several of our make-ready shops. The centralization of our make-ready operations was completed in the second quarter of 2014. During the year ended December 31, 2014, we incurred $5.4 million of restructuring charges primarily related to termination benefits and a non-cash write-down of inventory associated with the centralization of our make-ready operations. See Note 15 to the Financial Statements for further discussion of these charges.

 

Interest expense during the year ended December 31, 2014 compared to the year ended December 31, 2013 decreased due to a decrease in the weighted average effective interest rate on our debt, partially offset by an increase in the average balance of long-term debt. The decrease in the weighted average effective interest rate was primarily due to the redemption of $355.0 million aggregate principal amount of 4.25% convertible senior notes (the “4.25% Notes”) in the second quarter of 2014 with borrowings from our revolving credit facility, including the impact of a decrease in amortization of the debt discount on the 4.25% Notes in the current year, partially offset by the issuance of the Partnership 2014 Notes in April 2014 and the issuance of $350.0 million aggregate principal amount of the Partnership’s 6% senior notes in March 2013 (the “Partnership 2013 Notes”).

 

In March 2012, our Venezuelan joint ventures sold their assets to PDVSA Gas. We received payments, including an annual charge, of $14.7 million and $19.0 million during the years ended December 31, 2014 and 2013, respectively. The remaining principal amount due to us of approximately $26 million as of December 31, 2014, is payable in quarterly cash installments through the first quarter of 2016. In January 2015, we received an installment payment, including an annual charge, of $5.0 million that was due to us in December 2014. 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, was primarily due to a $20.0 million decrease in gain on sale of property, plant and equipment and a $6.5 million loss recognized during the year ended December 31, 2014 on short-term investments related to the purchase of Argentine government issued U.S. dollar denominated bonds using Argentine pesos. The change in other (income) expense, net, was also due to foreign currency losses of $8.8 million and $3.0 million during the years ended December 31, 2014 and 2013, respectively. Foreign currency losses included translation losses of $3.6 million and $4.3 million during the years ended December 31, 2014 and 2013, respectively, related to the functional currency remeasurement of our foreign subsidiaries’ U.S. dollar denominated intercompany obligations.

 

Income Taxes

(dollars in thousands)

 

 

 

Years Ended December 31,

 

Increase

 

 

 

2014

 

2013

 

(Decrease)

 

Provision for (benefit from) income taxes

 

$

58,657

 

$

84,719

 

(31

)%

Effective tax rate

 

52.4

%

48.0

%

4.4

%

 

The decrease in income tax expense during the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily due to a reduction in pre-tax income in the current year period, a $9.0 million valuation allowance recorded in the prior year period against the deferred tax asset for Italy net operating losses and a $3.0 million state tax benefit recognized in the current year period for amendments to prior years’ tax returns. These activities were partially offset by a $7.2 million valuation allowance recorded in the fourth quarter 2014 against foreign tax credits expiring in 2015.

 

Discontinued Operations

(dollars in thousands)

 

 

 

Years Ended December 31,

 

Increase

 

 

 

2014

 

2013

 

(Decrease)

 

Income from discontinued operations, net of tax

 

$

72,674

 

$

64,014

 

14

%

 

Income from discontinued operations, net of tax, during the years ended December 31, 2014 and 2013 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.

 

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As discussed in Note 3 to the Financial Statements, in August 2012, our Venezuelan subsidiary sold its previously nationalized assets to PDVSA Gas. We received installment payments, including an annual charge, totaling $72.6 million and $69.3 million during the years ended December 31, 2014 and 2013, respectively. The remaining principal amount due to us of approximately $116 million as of December 31, 2014, 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.

 

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 during the year ended December 31, 2013. As discussed in Note 3 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. Therefore, our contract water treatment business is reflected as discontinued operations in our consolidated financial statements. This business was previously included in our North American contract operations business segment. During the year ended December 31, 2013, we evaluated our contract water treatment business and recorded impairment charges of $2.4 million.

 

Noncontrolling Interest

 

Noncontrolling interest comprises of the portion of the Partnership’s earnings that is applicable to the Partnership’s publicly-held limited partner interest. As of December 31, 2014, public unitholders held a 63% ownership interest in the Partnership.

 

The Year Ended December 31, 2013 Compared to the 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.

 

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Table of Contents

 

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.

 

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 gross margins on work performed in the Eastern Hemisphere during the year ended December 31, 2013.

 

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 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.

 

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Table of Contents

 

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.

 

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 rec