10-K 1 a14-24877_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.: 001-33078

 

Exterran Partners, L.P.

(Exact name of registrant as specified in its charter)

 

Delaware

 

22-3935108

(State or other jurisdiction of

 

(I.R.S. Employer

incorporation or organization)

 

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 Units representing limited partner interests

 

NASDAQ Global Select Market

 

Securities Registered Pursuant to Section 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 o No x

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act. Yes 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 common units held by non-affiliates of the registrant (treating directors and executive officers of the registrant’s general partner and holders of 5% or more of the common units outstanding, for this purpose, as if they were affiliates of the registrant) as of June 30, 2014, the last business day of the registrant’s most recently completed second fiscal quarter, was $763,172,309. This calculation does not reflect a determination that such persons are affiliates for any other purpose.

 

As of February 19, 2015, there were 55,666,044 common units outstanding.

 


 

DOCUMENTS INCORPORATED BY REFERENCE: NONE

 

 

 



Table of Contents

 

Table of Contents

 

 

 

Page

PART I

Item 1.

Business

4

Item 1A.

Risk Factors

16

Item 1B.

Unresolved Staff Comments

34

Item 2.

Properties

34

Item 3.

Legal Proceedings

34

Item 4.

Mine Safety Disclosures

36

 

 

 

PART II

Item 5.

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

37

Item 6.

Selected Financial Data

39

Item 7.

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

44

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

58

Item 8.

Financial Statements and Supplementary Data

58

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

58

Item 9A.

Controls and Procedures

59

Item 9B.

Other Information

61

 

 

 

PART III

Item 10.

Directors, Executive Officers and Corporate Governance

61

Item 11.

Executive Compensation

66

Item 12.

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

86

Item 13.

Certain Relationships and Related Transactions and Director Independence

88

Item 14.

Principal Accountant Fees and Services

92

 

 

 

PART IV

Item 15.

Exhibits and Financial Statement Schedules

92

 

SIGNATURES

96

 

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PART I

 

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

 

This report contains “forward-looking statements.” All statements other than statements of historical fact contained in this report are forward-looking statements, including, without limitation, statements regarding Exterran Partners, L.P.’s (together with its subsidiaries, “we,” “our,” “us” or “the Partnership”) business growth strategy and projected costs; future financial position; the sufficiency of available cash flows to fund continuing operations and make cash distributions; the expected amount of our capital expenditures; future revenue, gross margin and other financial or operational measures related to our business; the future value of our equipment; plans and objectives of our management for our future operations; and any potential contribution of additional assets from Exterran Holdings, Inc. (individually, and together with its wholly-owned subsidiaries, “Exterran Holdings”) to us. 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.

 

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 services;

 

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

 

·          our dependence on Exterran Holdings to provide services and compression equipment, including its ability to hire, train and retain key employees and to timely and cost effectively obtain compression equipment and components necessary to conduct our business;

 

·          changes in economic or political conditions, including terrorism and legislative changes;

 

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

 

·          loss of our status as a partnership for United States of America (“U.S.”) federal income tax purposes;

 

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

 

·          the financial condition of our customers;

 

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

 

·          growing our asset base and asset utilization;

 

·          winning profitable new business;

 

·          integrating acquired businesses;

 

·          generating sufficient cash;

 

·          accessing the capital markets at an acceptable cost; and

 

·          purchasing additional contract operations contracts and equipment from Exterran Holdings;

 

·          liability related to the provision of our 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.

 

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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

 

General

 

We are a Delaware limited partnership formed in June 2006 to provide natural gas contract operations services to customers throughout the U.S. We completed our initial public offering in October 2006. We are the market leader in the U.S. full-service natural gas compression business. As of December 31, 2014, public unitholders held a 63% ownership interest in us and Exterran Holdings owned our remaining equity interests, including our general partner interest and all of the incentive distribution rights. Exterran General Partner, L.P., our general partner, is an indirect, wholly-owned subsidiary of Exterran Holdings and has sole responsibility for conducting our business and for managing our operations, which are conducted through our wholly-owned limited liability company, EXLP Operating LLC. Because our general partner is a limited partnership, its general partner, Exterran GP LLC, conducts our business and operations. Exterran GP LLC’s board of directors and officers, which we sometimes refer to as our board of directors and our officers, make decisions on our behalf. All of those directors are elected by Exterran Holdings.

 

Our contract operations services primarily include designing, sourcing, owning, installing, operating, servicing, repairing and maintaining equipment to provide natural gas compression services to our customers. We monitor our customers’ compression services requirements over time and, as necessary, modify the level of services and related equipment we employ to address changing operating conditions. We only operate in one segment; see the Consolidated Financial Statements included in Part II, Item 8 (“Financial Statements”) of this report for more information on results of operations and financial condition.

 

We are a party to an omnibus agreement with Exterran Holdings, our general partner and others (as amended and/or restated, the “Omnibus Agreement”), which includes, among other things:

 

·          certain agreements not to compete between Exterran Holdings and its affiliates, on the one hand, and us and our affiliates, on the other hand;

 

·          Exterran Holdings’ obligation to provide all operational staff, corporate staff and support services reasonably necessary to operate our business and our obligation to reimburse Exterran Holdings for such services;

 

·          the terms under which we, Exterran Holdings, and our respective affiliates may transfer, exchange or lease compression equipment among one another;

 

·          the terms under which we may purchase newly-fabricated contract operations equipment from Exterran Holdings;

 

·          Exterran Holdings’ grant to us of a license to use certain intellectual property, including our logo; and

 

·          Exterran Holdings’ and our obligations to indemnify each other for certain liabilities.

 

Our general partner does not receive any compensation for managing our business, but it is entitled to reimbursement of all direct and indirect expenses incurred on our behalf. Exterran Holdings and our general partner are also entitled to distributions on their limited partner interest and general partner interest, respectively and, if specified requirements are met, our general partner is entitled to distributions on its incentive distribution rights. From January 1, 2014 through December 31, 2014, our general partner received $10.6 million in distributions on its incentive distribution rights. For further discussion of our cash distribution policy, see “Cash Distribution Policy” included in Part II, Item 5 (“Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities”) of this report.

 

During each of the years ended December 31, 2013 and 2012, we acquired from Exterran Holdings contract operations service agreements and a fleet of compressor units used to provide compression services under those agreements (the 2013 and 2012 acquisitions are referred to as the “March 2013 Contract Operations Acquisition” and the “March 2012 Contract Operations Acquisition,” respectively).

 

On August 8, 2014, we 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 “August 2014 MidCon Acquisition”). The purchase price was funded with borrowings under our revolving credit facility. The majority of the horsepower we acquired is utilized under a five-year contract operations services agreement with BHP Billiton Petroleum (“BHP

 

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Billiton”) to provide compression services. In connection with the acquisition, the contract operations services agreement with BHP Billiton was assigned to us effective as of the closing. During the year ended December 31, 2014, we incurred transaction costs of approximately $1.0 million related to the August 2014 MidCon Acquisition, which is reflected in other (income) expense, net, in our consolidated statements of operations.

 

In accordance with the terms of the Purchase and Sale Agreement relating to this acquisition, we directed MidCon to sell a tract of real property and the facility located thereon, a fleet of vehicles, personal property and parts inventory to a wholly-owned subsidiary of Exterran Holdings that is our indirect parent company for $4.1 million.

 

On April 10, 2014, we 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 “April 2014 MidCon Acquisition”). The purchase price was funded with the net proceeds from the sale, pursuant to a public underwritten offering, of 6.2 million common units and a portion of the net proceeds from the issuance of $350.0 million aggregate principal amount of 6% senior notes due October 2022 (the “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, we and Access entered into a seven-year contract operations services agreement under which we provide compression services to Williams Partners, L.P. (“Williams,” formerly Access). During the year ended December 31, 2014, we incurred transaction costs of approximately $1.5 million related to the April 2014 MidCon Acquisition, which is reflected in other (income) expense, net, in our consolidated statements of operations.

 

In accordance with the terms of the Purchase and Sale Agreement relating to this acquisition, we directed MidCon to sell a tract of real property and the facility located thereon, a fleet of vehicles, personal property and parts inventory to a wholly-owned subsidiary of Exterran Holdings that is our indirect parent company for $7.7 million.

 

Exterran Holdings intends for us to be the primary long-term growth vehicle for its U.S. contract operations business and may, but is not obligated to, offer us the opportunity to purchase additional portions of its U.S. contract operations business over time. Likewise, we are not required to purchase any additional portions of such business. The consummation of any future purchase of additional portions of Exterran Holdings’ U.S. contract operations business and the timing of any such purchase will depend upon, among other things, our ability to reach an agreement with Exterran Holdings regarding the terms of such purchase, which will require the approval of the conflicts committee of our board of directors. The timing of such transactions would also depend on, among other things, market and economic conditions and our access to additional debt and equity capital. Future acquisitions of assets from Exterran Holdings may increase or decrease our operating performance, financial position and liquidity. Unless otherwise indicated, this discussion in Part I, Item 1 (“Business”) excludes any future potential transfers of additional contract operations customer service agreements and equipment from Exterran Holdings to us.

 

Proposed Exterran Holdings Spinoff Transaction

 

On November 17, 2014, Exterran Holdings announced that it will pursue a plan to separate (the “Spinoff”) its international contract operations, international aftermarket services and global fabrication businesses into an independent, publicly traded company (“Spinco”). To effect the Spinoff, Exterran Holdings intends to distribute, on a pro rata basis, all of the shares of Spinco common stock to its stockholders as of the record date for the Spinoff. The Spinoff is subject to market conditions, the execution of separation and intercompany agreements and certain other conditions and approvals. Upon completion of the Spinoff, Exterran Holdings and Spinco will be independent, publicly traded companies with separate public ownership, boards of directors and management, and Exterran Holdings will own and operate the remaining U.S. contract operations and U.S. aftermarket services businesses that Exterran Holdings currently owns. In addition, Exterran Holdings will continue to hold its equity interests in us, including our general partner interest and certain limited partner interests, and all of the incentive distribution rights. Although Exterran Holdings currently intends 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.

 

Natural Gas Compression Industry Overview

 

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

 

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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;

 

·          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.

 

We believe the U.S. natural gas compression services industry continues to have growth potential over time due to, among other things, increased natural gas production from unconventional sources and aging producing natural gas fields that will require more compression to continue producing the same volume of natural gas.

 

Contract Operations Services Overview

 

We provide comprehensive contract operations services, including the personnel, equipment, tools, materials and supplies to meet our customers’ natural gas compression needs. Based on the operating specifications at the customer’s location and the customer’s unique compression needs, these services include designing, sourcing, owning, installing, operating, servicing, repairing and maintaining equipment. When providing contract operations 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 Exterran Holdings develops new techniques and procedures. Because Exterran Holdings’ field technicians provide maintenance on substantially all of our contract operations equipment, they are familiar with the condition of our equipment

 

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and can readily identify potential problems. In our and Exterran Holdings’ 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. If a unit requires maintenance or reconfiguration, Exterran Holdings’ maintenance personnel service it as quickly as possible to meet our customers’ needs.

 

Our customers typically contract for our contract operations 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 for our contract compression services, which is typically between six and twelve months, contract compression 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, and the natural gas we use as fuel for our compressors is supplied by our customers, we have limited direct exposure to commodity price fluctuations. See “General Terms of our Contract Operations Customer Service Agreements,” below, for a more detailed description.

 

We intend to continue to work with Exterran Holdings to manage our respective U.S. fleets as one pool of compression equipment from which we can each readily fulfill our respective customers’ service needs. When one of Exterran Holdings’ salespersons is advised of a new contract operations services opportunity allocable to us, he or she will obtain relevant information concerning the project, including natural gas flow, pressure and natural gas composition, and then review our and Exterran Holdings’ fleets for an available and appropriate compressor unit. If we have enough lead time for a potential project, we may choose to purchase newly-fabricated equipment from Exterran Holdings or others to fulfill our customers’ needs. Please read Part III, Item 13 (“Certain Relationships and Related Transactions and Director Independence”) of this report for additional information regarding our ability to share or exchange compression equipment with, or purchase equipment from, Exterran Holdings.

 

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

 

Range of Horsepower Per Unit

 

Number of Units

 

Aggregate
Horsepower
(in thousands)

 

% of
Horsepower

 

0-200

 

2,737

 

317

 

10

%

201-500

 

1,899

 

506

 

16

%

501-800

 

408

 

255

 

8

%

801-1,100

 

213

 

202

 

7

%

1,101-1,500

 

924

 

1,257

 

40

%

1,501 and over

 

291

 

602

 

19

%

Total(1)

 

6,472

 

3,139

 

100

%

 


(1)                  Includes 229 compressor units, comprising approximately 79,000 horsepower, leased from Exterran Holdings and excludes 1 compressor unit, comprising approximately 100 horsepower, leased to Exterran Holdings (see Note 3 to the Financial Statements).

 

Over the last several years, Exterran Holdings has undertaken efforts to standardize its compressor fleet around major components and key suppliers. Because a significant portion of our fleet consists of Exterran Holdings’ former fleet, we benefit from these efforts, as well. Standardization of our fleet:

 

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

 

·          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.

 

As mentioned above, pursuant to the Omnibus Agreement, Exterran Holdings provides us with all operational staff, corporate staff and support services necessary to run our business.

 

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Business Strategy

 

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

 

·          Leverage our relationship with Exterran Holdings.  Our relationship with Exterran Holdings provides us numerous revenue and cost advantages, including the ability to access new and idle compression equipment, deploy that equipment in most of the major natural gas producing regions in the U.S. and provide maintenance and operational support on a more cost effective basis than we could without this relationship.

 

·          Build our business organically by capitalizing on the long-term fundamentals for the U.S. natural gas compression industry.  We believe our ability to efficiently meet our customers’ evolving compression needs, our long-standing customer relationships and our large compressor fleet will enable us to capitalize on what we believe are long-term fundamentals for the U.S. natural gas compression industry. These fundamentals include increased unconventional natural gas production, decreasing natural reservoir pressures, significant natural gas resources in the U.S. and the continued need for compression services.

 

·          Grow our business through acquisitions.  We plan to grow over time through accretive acquisitions of assets from Exterran Holdings, third-party compression providers and natural gas transporters or producers. Including our initial public offering, we have completed eight acquisitions from Exterran Holdings of compressor units comprising approximately 2.4 million horsepower, and during 2014, we completed two third-party acquisitions from MidCon that included a fleet of compressor units comprising approximately 0.6 million horsepower. Exterran Holdings may, but is not obligated to, offer us the opportunity to purchase additional portions of its U.S. contract operations business over time. The consummation of any future purchase of additional portions of Exterran Holdings’ business and the timing of any such purchase will depend upon, among other things, our ability to reach an agreement with Exterran Holdings regarding the terms of such purchase, which will require the approval of the conflicts committee of our board of directors. The timing of such transactions would also depend on, among other things, market and economic conditions and our access to additional debt and equity capital.

 

Competitive Strengths

 

We believe we have the following key competitive strengths:

 

·          Our relationship with Exterran Holdings.  Our relationship with Exterran Holdings and our access to its personnel, fabrication operations, logistical capabilities, geographic scope and operational efficiencies allow us to provide a full complement of contract operations services. We and Exterran Holdings intend to continue to manage our respective U.S. compression fleets as one pool of compression equipment from which we can more easily fulfill our respective customers’ needs. This relationship also gives us an advantage in pursuing compression opportunities throughout the U.S. As of December 31, 2014, Exterran Holdings owned approximately 1.1 million horsepower of compression equipment, excluding the compression equipment owned by us, in its U.S. contract operations business. We believe we will benefit from the opportunity to purchase additional portions of that business from Exterran Holdings over time. Exterran Holdings also intends, but is not obligated, to offer us the opportunity to purchase newly-fabricated compression equipment.

 

·          Focus on providing superior customer serviceWe 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.

 

·          Stable fee-based cash flows.  We charge a fixed monthly fee for our contract operations services that our customers are generally required to pay, regardless of the volume of natural gas we compress in that month. We believe this fee structure reduces volatility and enhances our ability to generate relatively stable and predictable cash flows.

 

·          Large fleet in many major producing regions.  Our large fleet and numerous operating locations throughout the U.S. combined with our ability, as a result of our relationship with Exterran Holdings, to efficiently move equipment among producing regions, means that we are not dependent on production activity in any particular region.

 

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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 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 is 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 business is tied primarily to natural gas 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, and the natural gas we use as fuel for our compressors 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.

 

Customers

 

Our current customer base consists of companies engaged in various aspects of the oil and natural gas industry, including natural gas producers, processors, gatherers, transporters and storage providers. We have entered into preferred vendor arrangements with some of our customers that give us preferential consideration for the compression needs of these customers. In exchange, we provide these customers with enhanced product availability, product support and favorable pricing. During the year ended December 31, 2014, Access accounted for approximately 12% of our consolidated revenue. Access merged with Williams in February 2015 and, when combined, Access and Williams would have accounted for approximately 15% of our consolidated revenue during the year ended December 31, 2014. No other customer accounted for more than 10% of our consolidated revenue in 2014. The loss of our business with Williams, unless offset by additional contract compression services revenue from other customers, or the inability or failure of Williams to meet their payment obligations could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

 

Sales and Marketing

 

Our marketing and client service functions are coordinated and performed by Exterran Holdings’ sales and field service personnel. Salespeople and field service personnel regularly visit our customers to ensure customer satisfaction, to determine customer needs as to services currently being provided and to ascertain potential future compression services requirements. This ongoing communication allows us to quickly identify and respond to customer requests.

 

General Terms of our Contract Operations Customer Service Agreements

 

The following discussion describes select material terms common to our standard contract operations service agreements. We typically enter into a master service agreement with each customer that sets forth the general terms and conditions of our services, and then enter into a separate supplemental service agreement for each distinct site at which we will provide contract operations services.

 

Term and Termination.  Our customers typically contract for our contract operations services on a site-by-site basis. Following the initial minimum term for our contract compression services, which is typically between six and twelve months, contract compression services generally continue until terminated by either party with 30 days’ advance notice.

 

Fees and Expenses.  Our customers pay a fixed monthly fee for our contract operations services, which generally is based on expected natural gas volumes and pressures associated with a specific application. Our customers generally are required to pay our monthly fee even during periods of limited or disrupted natural gas flows. We are typically responsible for the costs and expenses associated with our compression equipment used to provide the contract operations services, other than fuel gas, which is provided by our customers.

 

Service Standards and Specifications.  We provide contract operations services according to the particular specifications of each job, as set forth in the applicable contract. These are typically turn-key service contracts under which we supply all service and support and

 

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use our own compression equipment to provide the contract operations services as necessary for a particular application. In certain circumstances, if the availability of our services does not meet certain percentages specified in our contracts, our customers are generally entitled, upon request, to specified credits against our service fees.

 

Title; Risk of Loss.  We own and retain title to or have an exclusive possessory interest in all compression equipment used to provide the contract operations services and we generally bear risk of loss for such equipment to the extent not caused by gas conditions, our customers’ acts or omissions or the failure or collapse of the customer’s over-water job site upon which we provide the contract operations services.

 

Insurance.  Typically, both we and our customers are required to carry general liability, worker’s compensation, employers’ liability, automobile and excess liability insurance. Exterran Holdings insures our property and operations and is substantially self-insured for worker’s compensation, employer’s liability, property, auto liability, general liability and employee group health claims in view of the relatively high per-incident deductibles Exterran Holdings absorbs under its insurance arrangements for these risks.

 

Suppliers

 

Currently, our sole supplier of newly-fabricated equipment is Exterran Holdings. Pursuant to the Omnibus Agreement, we may purchase newly-fabricated compression equipment from Exterran Holdings or its affiliates at Exterran Holdings’ cost to fabricate such equipment plus a fixed margin, which may be modified with the approval of Exterran Holdings and the conflicts committee of our board of directors. In connection with the Spinoff transaction, Exterran Holdings intends to contribute its global fabrication business to Spinco. We currently intend to negotiate an agreement with Spinco, pursuant to which we may continue to purchase newly fabricated compression equipment from Spinco following the Spinoff. There are no assurances that we will be able to negotiate such an agreement on terms comparable to the terms of the Omnibus Agreement. We may also transfer, exchange or lease compression equipment with Exterran Holdings. Alternatively, we can purchase newly-fabricated or already existing compression equipment from third parties.

 

We rely on Exterran Holdings, who in turn relies on a limited number of suppliers, for some of the components used in our products. We and Exterran Holdings believe alternative sources of these components are generally available but at prices that may not be as economically advantageous to us as those offered by our existing suppliers. We believe Exterran Holdings’ relations with its suppliers are satisfactory.

 

Competition

 

The natural gas compression services 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.

 

Increased size and geographic scope offer compression services providers operating and cost advantages. As the number of compression applications and size of the compression fleet increases, the number of required sales, administrative and maintenance personnel increases at a lesser rate, resulting in operational efficiencies and potential cost advantages. Additionally, broad geographic scope allows compression service providers to more efficiently provide services to all customers, particularly those with compression applications in remote locations. Our relationship with Exterran Holdings allows us to access a large, diverse fleet of compression equipment and a broad geographic base of operations and related operational personnel that we believe gives us more flexibility in meeting our customers’ needs than many of our competitors. We also believe that our relationship with Exterran Holdings provides us with resources that allow us to efficiently manage our customers’ compression services needs.

 

Non-competition Arrangement with Exterran Holdings

 

Under the Omnibus Agreement, subject to the provisions described below, Exterran Holdings has agreed not to offer or provide compression services in the U.S. to our contract operations services customers that are not also contract operations services customers of Exterran Holdings. Compression services include natural gas contract compression services, but exclude fabrication of compression equipment, sales of compression equipment or material, parts or equipment that are components of compression equipment, leasing of compression equipment without also providing related compression equipment service, gas processing operations services and operation, maintenance, service, repairs or overhauls of compression equipment owned by third parties. Similarly, we have agreed not to offer or provide compression services to Exterran Holdings’ U.S. contract operations services customers that are not also our contract operations services customers.

 

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Some of our customers are also Exterran Holdings’ contract operations services customers, which we refer to as overlapping customers. We and Exterran Holdings have agreed, subject to the exceptions described below, not to provide contract operations services to an overlapping customer at any site at which the other was providing such services to an overlapping customer on the date of the most recent amendment to the Omnibus Agreement, each being referred to as a “Partnership site” or an “Exterran site.” Pursuant to the Omnibus Agreement, if an overlapping customer requests contract operations services at a Partnership site or an Exterran site, whether in addition to or in replacement of the equipment existing at such site on the date of the most recent amendment to the Omnibus Agreement, we may provide contract operations services if such overlapping customer is a Partnership overlapping customer, and Exterran Holdings will be entitled to provide such contract operations services if such overlapping customer is an Exterran overlapping customer. Additionally, any additional contract operations services provided to a Partnership overlapping customer will be provided by us and any additional services provided to an Exterran overlapping customer will be provided by Exterran Holdings.

 

Exterran Holdings also has agreed that new customers for contract compression services are for our account unless the new customer is unwilling to contract with us or unwilling to do so under our form of compression services agreement. In that case, Exterran Holdings may provide compression services to the new customer. If we or Exterran Holdings enter into a compression services contract with a new customer, either we or Exterran Holdings, as applicable, will receive the protection of the applicable non-competition arrangements described above in the same manner as if such new customer had been a compression services customer of either us or Exterran Holdings on the date of the Omnibus Agreement.

 

The non-competition arrangements described above do not apply to:

 

·          our provision of contract compression services to a particular Exterran Holdings customer or customers, with the approval of Exterran Holdings;

 

·          Exterran Holdings’ provision of contract compression services to a particular customer or customers of ours, with the approval of the conflicts committee of our board of directors;

 

·          our purchase and ownership of not more than five percent of any class of securities of any entity that provides contract compression services to Exterran Holdings’ contract compression services customers;

 

·          Exterran Holdings’ purchase and ownership of not more than five percent of any class of securities of any entity that provides contract compression services to our contract compression services customers;

 

·          Exterran Holdings’ ownership of us;

 

·          our acquisition, ownership and operation of any business that provides contract compression services to Exterran Holdings’ contract compression services customers if Exterran Holdings has been offered the opportunity to purchase the business for its fair market value from us and Exterran Holdings declines to do so. However, if neither the Omnibus Agreement nor the non-competition arrangements described above have already terminated, we will agree not to provide contract compression services to Exterran Holdings’ customers that are also customers of the acquired business at the sites at which Exterran Holdings is providing contract operations services to them at the time of the acquisition;

 

·          Exterran Holdings’ acquisition, ownership and operation of any business that provides contract compression services to our contract operations services customers if we have been offered the opportunity to purchase the business for its fair market value from Exterran Holdings and we decline to do so with the concurrence of the conflicts committee of our board of directors. However, if neither the Omnibus Agreement nor the non-competition arrangements described above have already terminated, Exterran Holdings will agree not to provide contract operations services to our customers that are also customers of the acquired business at the sites at which we are providing contract operations services to them at the time of the acquisition; or

 

·          a situation in which one of our customers (or its applicable business) and a customer of Exterran Holdings (or its applicable business) merge or are otherwise combined, in which case, each of we and Exterran Holdings may continue to provide contract operations services to the applicable combined entity or business without being in violation of the non-competition provisions, but Exterran Holdings and the conflicts committee of our board of directors must negotiate in good faith to implement procedures or such other arrangements, as necessary, to protect the value to each of Exterran Holdings and us of the business of providing contract operations services to each such customer or its applicable business.

 

Unless the Omnibus Agreement is terminated earlier due to a change of control of Exterran GP LLC, our general partner or us, the non-competition provisions of the Omnibus Agreement will terminate on December 31, 2015 or on the date on which a change of control of Exterran Holdings occurs, whichever event occurs first. If a change of control of Exterran Holdings occurs, and neither the

 

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Omnibus Agreement nor the non-competition arrangements have already terminated, Exterran Holdings will agree for the remaining term of the non-competition arrangements not to provide contract operations services to our customers at any site where we are providing contract operations services at the time of the change of control.

 

Environmental and Other Regulations

 

Government Regulation

 

Our operations are subject to stringent and complex U.S. federal, state and local 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 and local 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 ability to make cash distributions to our unitholders.

 

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 ability to make cash distributions to our unitholders.

 

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 ability to make cash distributions to our unitholders.

 

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.

 

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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 ability to make cash distributions to our unitholders.

 

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 Exterran Holdings’ facilities on which we may store inactive compression units have applied for and obtained industrial wastewater discharge permits as well as sought coverage under local wastewater ordinances. In addition, many of those facilities have filed notices of intent for coverage under statewide storm water general permits and developed and implemented storm water pollution prevention plans, as required. U.S. federal laws also require development and implementation of spill prevention, controls, and countermeasure plans, including appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak at such facilities.

 

Waste Management and Disposal

 

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

 

While we do not own any material facilities or properties, we use Exterran Holdings’ properties for the storage and maintenance and repair of inactive compressor units and lease some properties used in support of our operations. 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 used 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, Exterran Holdings is currently working with the prior owners who have undertaken to monitor and clean up contamination that occurred prior to Exterran Holdings’ 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.

 

Indemnification for Environmental Liabilities

 

Under the Omnibus Agreement, Exterran Holdings has agreed to indemnify us, for a three-year period following each applicable asset acquisition from Exterran Holdings, against certain potential environmental claims, losses and expenses associated with the ownership and operation of the acquired assets that occur before the acquisition date. Exterran Holdings’ maximum liability for environmental

 

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indemnification obligations under the Omnibus Agreement cannot exceed $5 million, and Exterran Holdings will not have any obligation under the environmental or any other indemnification until our aggregate losses exceed $250,000. Exterran Holdings will have no indemnification obligations with respect to environmental claims made as a result of additions to or modifications of environmental laws promulgated after such acquisition date. We have agreed to indemnify Exterran Holdings against environmental liabilities occurring on or after the applicable acquisition date related to our assets to the extent Exterran Holdings is not required to indemnify us.

 

Employees and Labor Relations

 

We do not have any employees. Under the Omnibus Agreement, we reimburse Exterran Holdings for the allocated costs of its personnel who provide direct or indirect support for our operations. Exterran Holdings considers its employee relations to be 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 Partners, L.P., 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:

 

·          the Code of Business Conduct and Ethics of Exterran GP LLC; and

 

·          the charters of the audit, conflicts and compensation committees of Exterran GP LLC.

 

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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 our ability to make cash distributions to our unitholders could be negatively impacted.

 

Risks Related to Our Business

 

We have been in the past dependent on our cost caps from Exterran Holdings to generate sufficient cash from operating surplus to enable us to make cash distributions approximating our current distribution rate. These cost caps were in effect through December 31, 2014; however, effective January 1, 2015, the cost caps provisions of the Omnibus Agreement terminated. Their termination may reduce the amount of cash flow available to unitholders in the future and, accordingly, could impair our ability to maintain or increase our distributions.

 

Under the Omnibus Agreement, our obligation to reimburse Exterran Holdings for any cost of sales that it incurred in the operation of our business and any cash SG&A expense allocated to us was capped (after taking into account any such costs we incurred and paid directly) through December 31, 2014. Cost of sales was capped at $21.75 per operating horsepower per quarter through December 31, 2013 and $22.50 per operating horsepower per quarter from January 1, 2014 through December 31, 2014. SG&A costs were capped at $12.5 million per quarter from April 1, 2013 through December 31, 2013, $15.0 million per quarter from January 1, 2014 through April 9, 2014 and $17.7 million per quarter from April 10, 2014 through December 31, 2014.

 

Our cost of sales exceeded the cap provided in the Omnibus Agreement by $2.5 million, $12.4 million and $16.6 million during 2014, 2013, and 2012, respectively. Our SG&A expenses exceeded the cap provided in the Omnibus Agreement by $11.4 million, $12.8 million and $8.2 million during 2014, 2013 and 2012, respectively. Accordingly, our EBITDA, as further adjusted, and our distributable cash flow (please see Part II, Item 6 (“Selected Financial Data — Non-GAAP Financial Measures”) of this report for a discussion of EBITDA, as further adjusted, and distributable cash flow) would have been approximately $13.9 million, $25.2 million and $24.8 million lower during 2014, 2013 and 2012, respectively, without the benefit of the cost caps. As a result, without the benefit of the cost caps, our distributable cash flow coverage (distributable cash flow for the period divided by distributions declared to all unitholders for the period, including incentive distribution rights) would have been 1.20x, 1.13x and 1.02x during 2014, 2013 and 2012, respectively, rather than the actual distributable cash flow coverage (which includes the benefit of cost caps) of 1.30x, 1.36x and 1.29x during 2014, 2013, and 2012, respectively.

 

These cost caps were in effect through December 31, 2014; however, effective January 1, 2015, the cost caps provisions of the Omnibus Agreement terminated. Their termination could reduce the amount of cash flow available to unitholders in the future and, accordingly, could impair our ability to maintain or increase our distributions.

 

Continued low oil and natural gas prices in the U.S. could decrease demand for our natural gas compression services and, as a result, adversely affect our business and decrease our revenue and cash available for distribution.

 

Our revenue, earnings and financial position are affected by, among other things, market conditions that impact demand and pricing for natural gas compression services. 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 the U.S. 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, where we provide a significant amount of contract operations services, which led to a decline in our business in these areas during 2012. Since then, natural gas prices in the U.S. 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 the U.S., 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

 

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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 2015. If oil or natural gas production growth moderates or declines in the U.S., the level of production activity and the demand for our contract operations services could decrease, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. A reduction in demand for our services could also force us to reduce our pricing substantially, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. Moreover, a reduction in demand for our services could result in our customers seeking to preserve capital by canceling month-to-month contracts, determining not to enter into new contract operations service contracts, or canceling or delaying orders for our contract operations services, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. Additionally, 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.

 

Due to our significant relationship with Exterran Holdings, adverse developments concerning Exterran Holdings could adversely affect us, even if we have not suffered any similar developments.

 

Through its subsidiaries, Exterran Holdings owns all of our general partner interests, including all of the incentive distribution rights, and a significant amount of our limited partner interests. Our access to Exterran Holdings’ personnel, fabrication operations, logistical capabilities, geographic scope and operational efficiencies allows us to provide a full complement of contract operations services. In addition, we benefit from a number of arrangements in the Omnibus Agreement between us and Exterran Holdings (please see Note 3 to the Financial Statements for further discussion of the Omnibus Agreement). A material adverse effect upon Exterran Holding’s assets, liabilities, financial condition, business or operations could impact Exterran Holdings’ ability to continue to provide these benefits to us. As a result, we could experience a material adverse effect upon our business, results of operations, financial condition and ability to make cash distributions to our unitholders, even if we have not suffered any similar developments.

 

Following the closing of the Spinoff transaction, certain of Exterran Holdings’ fabrication operations, logistical capabilities, geographic scope and operational efficiencies will be contributed to Spinco. Certain key personnel of Exterran Holdings may become employees of Spinco. Exterran Holdings’ loss of these capabilities and key personnel could have a material adverse effect upon our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

 

As we continue to acquire additional compression equipment from Exterran Holdings we expect that our maintenance capital expenditures will increase, which could reduce the amount of cash available for distribution.

 

Exterran Holdings manages its and our respective U.S. fleets as one pool of compression equipment from which we can each readily fulfill our respective customers’ service needs. When we or Exterran Holdings are advised of a contract operations services opportunity, Exterran Holdings reviews both our and its fleet for an available and appropriate compressor unit. Given that the majority of the idle compression equipment has been and is currently held by Exterran Holdings, much of the idle compression equipment required for these contract operations services opportunities has been held by Exterran Holdings. Under the Omnibus Agreement, the owner of the equipment being transferred is required to pay the costs associated with making the idle equipment suitable for the proposed customer and then has generally leased the equipment to the recipient of the equipment or exchanged the equipment for other equipment of the recipient. Since Exterran Holdings has owned the majority of such equipment, Exterran Holdings has generally had to bear a larger portion of the maintenance capital expenditures associated with making transferred equipment ready for service. For equipment that is then leased to the recipient, the maintenance capital cost is a component of the lease rate that is paid under the lease. As we acquire more compression equipment, we expect that more of our equipment will be available to satisfy our or Exterran Holdings’ customer requirements. As a result, we expect that our maintenance capital expenditures will increase, which could reduce our cash available for distribution.

 

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 $1.3 billion in outstanding debt obligations. Many factors, including factors beyond our control, may affect our ability to make payments on our outstanding indebtedness. These factors include those discussed elsewhere in these Risk Factors and those listed in the Disclosure Regarding Forward-Looking Statements section included in Part I of this report.

 

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

 

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

 

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

 

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·                  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.

 

A substantial portion of our cash flow must be used to service our debt obligations, and future interest rate increases could reduce the amount of our cash available for distribution.

 

At December 31, 2014, we had $1.3 billion in outstanding debt obligations, consisting of $344.8 million net of the unamortized discount outstanding under the 2014 Notes, $345.5 million net of the unamortized discount outstanding under our 6% senior notes due April 2021 (the “2013 Notes”), $460.0 million outstanding under our revolving credit facility and $150.0 million outstanding under our term loan. The senior secured credit agreement (the “Credit Agreement”), which consists of a revolving credit facility and term loan facility, requires that we make mandatory prepayments of the term loan with the net cash proceeds of certain asset transfers. Borrowings under our senior secured credit facility bear interest at floating rates. We have effectively fixed a portion of the floating rate debt through the use of interest rate swaps; however, changes in economic conditions could result in higher interest rates, thereby increasing our interest expense and reducing our funds available for capital investment, operations or distributions to our unitholders. As of December 31, 2014, after taking into consideration interest rate swaps, we had $210.0 million of outstanding indebtedness that was effectively subject to floating interest rates. A 1% increase in the effective interest rate on our outstanding debt subject to floating interest rates at December 31, 2014 would result in an annual increase in our interest expense of approximately $2.1 million. Any such increase in our interest expense could reduce the amount of cash we have available for distribution.

 

Covenants in our Credit Agreement may impair our ability to operate our business.

 

The Credit Agreement contains various covenants with which we must comply, including, but not limited to, restrictions on the use of proceeds from borrowings and limitations on our 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 Credit Agreement also contains various covenants requiring mandatory prepayments from the net cash proceeds of certain asset transfers. We must maintain various consolidated financial ratios, including a ratio of EBITDA (as defined in the Credit Agreement) to Total Interest Expense (as defined in the Credit Agreement) of not less than 2.75 to 1.0, a ratio of Total Debt (as defined in the 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 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, our 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, we 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 on our assets, liabilities, financial condition, business or operations that, taken as a whole, impacts our ability to perform our obligations under the Credit Agreement, could lead to a default under that agreement.

 

The breach of any of our covenants could result in a default under our Credit Agreement which could cause our indebtedness under our Credit Agreement to become due and payable. A default under one of our debt agreements would trigger cross-default provisions under our other debt agreements, which would accelerate our obligation to repay our indebtedness under those agreements. If the repayment obligations on any of our indebtedness were to be so accelerated, we may not be able to repay the debt or refinance the debt on acceptable terms, and our financial position would be materially adversely affected. As of December 31, 2014, we are in compliance with all financial covenants under our Credit Agreement.

 

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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 available for distribution.

 

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 Part I, Item 3 (“Legal Proceedings”) and Note 15 (“Commitments and Contingencies”) to the Financial Statements included in this report 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 $10.2 million during the year ended December 31, 2014. Since the change in methodology became effective in 2012, we have recorded an aggregate benefit of $20.7 million as of December 31, 2014, of which approximately $4.6 million has been agreed to by a number of appraisal review boards and county appraisal districts and $16.1 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, including our cash available for distribution and accordingly, could impair our ability to maintain or increase our distributions.

 

Our inability to fund purchases of additional compression equipment could adversely impact our results of operations and cash available for distribution.

 

We may not be able to maintain or grow our asset and customer base unless we have access to sufficient capital to purchase additional compression equipment. Cash flow from our operations and availability under our senior secured credit facility may not provide us with sufficient cash to fund our capital expenditure requirements, including any funding requirements related to acquisitions. Additionally, pursuant to our partnership agreement, we intend to distribute all of our “available cash,” as defined in our partnership agreement, to our unitholders on a quarterly basis. Therefore, a significant portion of our cash flow from operations will be used to fund such distributions. As a result, we intend to fund our growth capital expenditures and acquisitions, including future acquisitions of compression services contracts and equipment from Exterran Holdings, with external sources of capital including additional borrowings under our senior secured credit facility and/or public or private offerings of equity or debt. Our ability to grow our asset and customer base could be impacted by any limits on our ability to access equity and debt capital.

 

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to holders of our common units at our current distribution rate.

 

We may not have sufficient available cash from operating surplus each quarter to enable us to make cash distributions at our current distribution rate. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things, the risks described in this section.

 

In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:

 

·          the level of capital expenditures we make;

 

·          the cost of acquisitions;

 

·          our debt service requirements and other liabilities;

 

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·          fluctuations in our working capital needs;

 

·          our ability to refinance our debt in the future or borrow funds and access capital markets;

 

·          restrictions contained in our debt agreements; and

 

·          the amount of cash reserves established by our general partner.

 

Failure to generate sufficient cash flow, together with the absence of alternative sources of capital, could adversely impact our results of operations and cash available for distribution to our unitholders.

 

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

 

Many of our customers finance their exploration and development activities through cash flow from operations, the incurrence of debt or the issuance of equity. During times when the oil or natural gas markets weaken, our customers are more likely to experience a downturn in their financial condition. A reduction in borrowing bases under reserve-based credit facilities and the lack of availability of debt or equity financing could result in a reduction in our customers’ spending for our services. For example, our customers could seek to preserve capital by canceling month-to-month contracts or determining not to enter into any new natural gas compression service contracts, thereby reducing demand for our services. Reduced demand for our services could adversely affect our business, financial condition, results of operations and ability to make cash distributions to our unitholders. 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.

 

Our agreement not to compete with Exterran Holdings could limit our ability to grow.

 

We have entered into an Omnibus Agreement with Exterran Holdings and several of its subsidiaries. The Omnibus Agreement includes certain agreements not to compete between us and our affiliates, on the one hand, and Exterran Holdings and its affiliates, on the other hand. This agreement not to compete with Exterran Holdings could limit our ability to grow. For further discussion of the Omnibus Agreement, please see Note 3 to the Financial Statements.

 

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

 

Our business is highly competitive and there are low barriers to entry. We experience competition from companies that 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 contracts with our customers at rates sufficient to maintain current revenue and cash flows could be adversely affected by the activities of our competitors. If our competitors substantially increase the resources they devote to the development and marketing of competitive services or substantially decrease the prices at which they offer their services, we may not be able to compete effectively. In addition, we could face significant competition from new entrants into our industry. Some of our existing competitors or new entrants may expand or fabricate new compressor units that would create additional competition for the services we provide to our customers. In addition, our customers may purchase and operate their own compressor fleets in lieu of using our natural gas compression services. Any of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

 

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, results of operations, financial condition and ability to make cash distributions to our unitholders.

 

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

 

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We depend on Williams Partners, L.P. (“Williams”) for a significant portion of our revenue. The loss of our business with Williams or the inability or failure of Williams to meet its payment obligations may adversely affect our financial results.

 

For the year ended December 31, 2013, no customer individually accounted for 10% or more of our total revenue. In connection with the April 2014 MidCon Acquisition, we and Access Midstream Partners, L.P. (“Access”) entered into a seven-year contract operations services agreement under which we 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 our consolidated revenue. Access merged with Williams in February 2015 and, when combined, Access and Williams would have accounted for approximately 15% of our consolidated revenue during the year ended December 31, 2014. The loss of our business with Williams, unless offset by additional contract compression services revenue from other customers, or the inability or failure of Williams to meet their payment obligations could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

 

We may not be able to grow our cash flows if we do not expand our business, which could limit our ability to maintain or increase distributions to our unitholders.

 

Our ability to grow the per unit distribution on our units is dependent in part upon our ability to expand our business. Our future growth will depend upon a number of factors, some of which we cannot control. These factors include our ability to:

 

·          acquire additional U.S. contract operations services business from Exterran Holdings;

 

·          consummate accretive acquisitions;

 

·          enter into contracts for new services with our existing customers or new customers; and

 

·          obtain required financing for our existing and new operations.

 

A deficiency in any of these factors could adversely affect our ability to achieve growth in the level of our cash flows or realize benefits from acquisitions.

 

If we do not make acquisitions on economically acceptable terms, our future growth and our ability to maintain or increase distributions to our unitholders could be limited.

 

Our ability to grow depends, in part, on our ability to make accretive acquisitions. If we are unable to make accretive acquisitions either because we are: (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (ii) unable to obtain financing for these acquisitions on economically acceptable terms, or (iii) outbid by competitors, then our future growth and ability to maintain or increase distributions could be limited. Furthermore, even if we make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations per unit.

 

Any acquisition involves potential risks, including, among other things:

 

·          an inability to integrate successfully the businesses we acquire;

 

·          the assumption of unknown liabilities;

 

·          limitations on rights to indemnity from the seller;

 

·          mistaken assumptions about the cash generated or anticipated to be generated by the business acquired or the overall costs of equity or debt;

 

·          the diversion of management’s attention from other business concerns;

 

·          unforeseen operating difficulties; and

 

·          customer or key employee losses at the acquired businesses.

 

If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of our future funds and other resources. In addition, competition from other buyers could reduce our acquisition opportunities or cause us to pay a higher price than we might otherwise pay.

 

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Exterran Holdings continues to own and operate a substantial U.S. contract compression business, competition from which could adversely impact our results of operations and cash available for distribution.

 

Exterran Holdings and its affiliates, other than us, are prohibited from competing directly or indirectly with us with respect to certain of our existing customers and certain locations where we currently conduct business, and with respect to any new contract compression services customer that approaches either Exterran Holdings or ourselves, until the earlier of December 31, 2015, a change of control of Exterran Holdings or our general partner, or the removal or withdrawal of our general partner. Otherwise, Exterran Holdings is not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. Exterran Holdings continues to own and operate a U.S. contract operations business, including natural gas compression, and continues to engage in international contract operations, fabrication and aftermarket service activities. Exterran Holdings is a large, established participant in the contract operations business, and has significantly greater resources, including idle compression equipment, operating personnel, fabrication operations, vendor relationships and experience, than we have, which factors may make it more difficult for us to compete with it with respect to commercial activities as well as for acquisition candidates. Exterran Holdings and its affiliates may acquire, fabricate or dispose of additional natural gas compression or other assets in the future without any obligation to offer us the opportunity to purchase any of those assets. As a result, competition from Exterran Holdings could adversely impact our results of operations and cash available for distribution.

 

We may be unable to grow through acquisitions of Exterran Holdings’ U.S. contract operations business, which could limit our ability to maintain or increase distributions to our unitholders.

 

Exterran Holdings is under no obligation to offer us the opportunity to purchase any of its U.S. contract operations business, and its board of directors owes fiduciary duties to the stockholders of Exterran Holdings, and not our unitholders, in making any decision to offer us this opportunity. Likewise, we are not required to purchase any additional portions of such business.

 

The consummation of any such purchases will depend upon, among other things, our ability to reach an agreement with Exterran Holdings regarding the terms of such purchases (which will require the approval of the conflicts committee of our board of directors) and our ability to finance such purchases on acceptable terms. Additionally, Exterran Holdings may be limited in its ability to consummate sales of additional portions of such business to us by the terms of its existing or future credit facilities or indentures. Furthermore, our senior secured credit facility includes covenants that may limit our ability to finance acquisitions. If a sale of any additional portion of Exterran Holdings’ U.S. contract operations business would be restricted or prohibited by such covenants, we or Exterran Holdings may be required to seek waivers of such provisions or refinance those debt instruments in order to consummate a sale, neither of which may be accomplished timely, if at all. If we are unable to grow through additional acquisitions of Exterran Holdings’ U.S. contract operations business, our ability to maintain or increase distributions to our unitholders may be limited.

 

Many of our compression services contracts with customers 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 and cash available for distribution.

 

The length of our compression services contracts with customers varies based on operating conditions and customer needs. Our initial contract terms are not long enough to enable us to recoup the cost of acquiring the equipment we use to provide compression 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 compression 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 revenue and net income and could require us to record additional asset impairments. This could have a material adverse effect upon our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

 

Our ability to manage and grow our business effectively may be adversely affected if Exterran Holdings loses management or operational personnel.

 

Most of our officers are also officers or employees of Exterran Holdings. Additionally, we do not have any of our own employees, but rather rely on Exterran Holdings’ employees to operate our business. We believe that Exterran Holdings’ ability to hire, train and retain qualified personnel will continue to be challenging and important as we grow. When general industry conditions are good, the supply of experienced operational, fabrication and field personnel, in particular, decreases as other energy and manufacturing companies’ needs for the same personnel increase. Our ability to grow and to continue our current level of service to our customers will be adversely impacted if Exterran Holdings is unable to successfully hire, train and retain these important personnel.

 

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If we are unable to purchase compression equipment from Exterran Holdings or others, we may not be able to retain existing customers or compete for new customers, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

 

Exterran Holdings is under no obligation to offer or sell to us newly-fabricated or idle compression equipment and may choose not to do so timely or at all. We may not be able to purchase newly-fabricated or idle compression equipment from third-party producers or marketers of such equipment or from our competitors. If we are unable to purchase compression equipment on a timely basis to meet the demands of our customers, our existing customers may terminate their contractual relationships with us, or we may not be able to compete for business from new or existing customers, either of which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

 

Our reliance on Exterran Holdings as an operator of our assets and our limited ability to control certain costs could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

 

Pursuant to the Omnibus Agreement, Exterran Holdings provides us with all administrative and operational services, including without limitation all operations, marketing, maintenance and repair, periodic overhauls of compression equipment, inventory management, legal, accounting, treasury, insurance administration and claims processing, risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit, taxes and engineering services necessary to run our business. Our operational success and ability to execute our growth strategy depends significantly upon Exterran Holdings’ satisfactory operation of our assets and performance of these services. Our reliance on Exterran Holdings as an operator of our assets and our resulting limited ability to control certain costs could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

 

We indirectly depend on particular suppliers and are vulnerable to product shortages and price increases, which could have a negative impact on our results of operations.

 

Some of the components used in our compressors are obtained by Exterran Holdings from a single source or a limited group of suppliers. Exterran Holdings’ 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. Exterran Holdings does not have long-term contracts with some of these sources, and its 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, since any increase in component prices for compression equipment fabricated by Exterran Holdings for us will be passed on to us, a significant increase in the price of one or more of these components could have a negative impact on our results of operations.

 

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, including our ability to make cash distributions to our unitholders. 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 Part I, Item 3 (“Legal Proceedings”) and also Note 15 (“Commitments and Contingencies”) to the Financial Statements included in this report 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.

 

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.

 

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 as a result could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our unitholders.

 

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.

 

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

 

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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 ability to make cash distributions to our unitholders.

 

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 and local laws and regulations, including relating to the environment, health and safety, 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 states 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. The operations at many of these facilities require U.S. federal, state or local 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 U.S. federal, state and local 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 ability to make cash distributions to our unitholders.

 

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 to substantial liability for personal injury, wrongful death, property damage, pollution and other environmental damages. Exterran Holdings insures our property and operations against many of these risks; however, the insurance it carries may not be adequate to cover our claims or losses. Exterran Holdings currently has minimal amount of insurance on our offshore assets. In addition, Exterran Holdings is substantially self-insured for worker’s compensation, employer’s liability, property, auto liability, general liability and employee group health claims in view of the relatively high per-incident deductibles it absorbs under its 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, results of operations and financial condition could be negatively impacted.

 

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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, as a result, we are subject to the tax laws and regulations of U.S. federal, state, and local 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, 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.

 

Risks Inherent in an Investment in Our Common Units

 

Exterran Holdings controls our general partner, which has sole responsibility for conducting our business and managing our operations. Exterran Holdings has conflicts of interest, which may permit it to favor its own interests to our unitholders’ detriment.

 

Exterran Holdings owns and controls our general partner. Most of our executive officers are officers of Exterran Holdings. Therefore, conflicts of interest may arise between Exterran Holdings and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders. These conflicts include, among others, the following situations:

 

·          neither our partnership agreement nor any other agreement requires Exterran Holdings to pursue a business strategy that favors us. Exterran Holdings’ directors and officers have a fiduciary duty to make these decisions in the best interests of the owners of Exterran Holdings, which may be contrary to our interests;

 

·          our general partner controls the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and Exterran Holdings, on the other hand, including provisions governing administrative services, acquisitions and transfers of compression equipment and non-competition provisions;

 

·          our general partner controls whether we agree to acquire additional contract operations customers or assets from Exterran Holdings that are offered to us by Exterran Holdings and the terms of such acquisitions;

 

·          our general partner is allowed to take into account the interests of parties other than us, such as Exterran Holdings and its affiliates, in resolving conflicts of interest;

 

·          other than as provided in our Omnibus Agreement with Exterran Holdings, Exterran Holdings and its affiliates are not limited in their ability to compete with us. Exterran Holdings will continue to engage in U.S. and international contract operations services as well as third-party sales coupled with aftermarket service contracts and may, in certain circumstances, compete with us with respect to any future acquisition opportunities;

 

·          Exterran Holdings’ U.S. and international contract compression services businesses and its third-party equipment customers may compete with us for newly-fabricated and idle compression equipment and Exterran Holdings is under no obligation to offer equipment to us for purchase or use;

 

·          all of the officers and employees of Exterran Holdings who provide services to us also will devote significant time to the business of Exterran Holdings, and will be compensated by Exterran Holdings for the services rendered to it;

 

·          our general partner has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

 

·          our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and reserves, each of which can affect the amount of cash that is distributed to unitholders;

 

·          our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or a growth capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders;

 

·          our general partner determines which costs incurred by it and its affiliates are reimbursable by us and Exterran Holdings determines the allocation of shared overhead expenses;

 

·          our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

 

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·          our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

 

·          our general partner may exercise its limited right to call and purchase common units if it and its affiliates own more than 80% of the common units; and

 

·          our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

 

Cost reimbursements due to our general partner and its affiliates for services provided, which are determined by our general partner, are substantial and reduce our cash available for distribution to our unitholders.

 

Pursuant to the Omnibus Agreement we entered into with Exterran Holdings, our general partner, and others, Exterran Holdings receives reimbursement for the payment of operating expenses related to our operations and for the provision of various general and administrative services for our benefit. Payments for these services are substantial and reduce the amount of cash available for distribution to unitholders. Following the closing of the Spinoff transaction, Exterran Holdings will continue to provide these services for our benefit. However, the Spinoff transaction could materially affect Exterran Holdings’ costs for performing these services and could cause Exterran Holdings to alter its methodologies of allocating costs for performing services to us. Any such increase in costs or change in allocation methodologies could, in turn, increase the amount that we reimburse Exterran Holdings for performing these services. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

 

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

 

Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:

 

·          permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to our partnership agreement;

 

·          provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;

 

·          generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of our board of directors acting in good faith and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

 

·          provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

 

·          provides that in resolving conflicts of interest, it will be presumed that in making its decision the general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

 

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Holders of our common units have limited voting rights and are not entitled to elect our general partner or its general partner’s directors, which could reduce the price at which the common units will trade.

 

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders do not elect our general partner or its general partner’s board of directors, and have no right to elect our general partner or its general partner’s board of directors on an annual or other continuing basis. Our board of directors is chosen by its sole member, a subsidiary of Exterran Holdings. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they have little ability to remove our general partner. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

 

Even if holders of our common units are dissatisfied, they cannot currently remove our general partner without its consent.

 

Unitholders are unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common units voting together as a single class is required to remove our general partner. As of December 31, 2014, our general partner and its affiliates owned 35% of our aggregate outstanding common units.

 

Control of our general partner may be transferred to a third party without unitholder consent.

 

Our general partner, which is indirectly wholly owned by Exterran Holdings, may transfer its general partner interest to a third party in a merger, or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of Exterran Holdings, the owner of our general partner, from transferring all or a portion of its ownership interest in our general partner to a third party. The new owners of our general partner would then be in a position to replace the board of directors and officers of our general partner’s general partner with its own choices and thereby influence the decisions taken by the board of directors and officers.

 

We may issue additional units without unitholder approval, which would dilute our unitholders’ existing ownership interests.

 

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance of additional common units or other equity securities of equal or senior rank by us will have the following effects:

 

·          our unitholders’ proportionate ownership interest in us will decrease;

 

·          the amount of cash available for distribution on each unit may decrease;

 

·          the ratio of taxable income to distributions may increase;

 

·          the relative voting strength of each previously outstanding unit may be diminished; and

 

·          the market price of the common units may decline.

 

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units, other than our general partner and its affiliates, including Exterran Holdings.

 

Unitholders’ voting rights are further restricted by our partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, including Exterran Holdings, their transferees and persons who acquired such units with the prior approval of our board of directors, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions.

 

Affiliates of our general partner may sell common units in the public or private markets, which could have an adverse impact on the trading price of the common units.

 

At December 31, 2014, Exterran Holdings and its affiliates held 19,618,918 common units. The sale of these common units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

 

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Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.

 

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. At December 31, 2014, our general partner and its affiliates owned 35% of our aggregate outstanding common units.

 

Unitholder liability may not be limited if a court finds that unitholder action constitutes control of our business.

 

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Unitholders could be liable for any and all of our obligations as if they were a general partner if:

 

·          a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

 

·          a unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitutes “control” of our business.

 

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

 

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

 

The market price of our common units may be influenced by many factors.

 

Our common units are traded publicly on the NASDAQ Global Select Market under the symbol “EXLP.”

 

The market price of our common units may be influenced by many factors, some of which are beyond our control, including:

 

·          our quarterly distributions;

 

·          our quarterly or annual earnings or those of other companies or partnerships in our industry;

 

·          changes in commodity prices, including oil, natural gas and natural gas liquids;

 

·          changes in demand for natural gas in the U.S.;

 

·          loss of a large customer;

 

·          changes in interest rates;

 

·          announcements by us or our competitors of significant contracts or acquisitions;

 

·          changes in accounting standards, policies, guidance, interpretations or principles;

 

·          tax legislation;

 

·          general economic conditions;

 

·          the failure of securities analysts to cover our common units or changes in financial estimates by analysts;

 

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·          future sales of our common units; and

 

·          the other factors described in these Risk Factors.

 

Increases in interest rates could adversely impact our unit price, our ability to issue additional equity or incur debt to make acquisitions or for other purposes, and our ability to make distributions to our unitholders.

 

As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue additional equity or incur debt to make acquisitions or for other purposes and our ability to make distributions to our unitholders.

 

Tax Risks to Common Unitholders

 

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes. We could lose our status as a partnership for a number of reasons, including not having enough “qualifying income.” If the Internal Revenue Service (“IRS”) were to treat us as a corporation for U.S. federal income tax purposes, our cash available for distribution would be substantially reduced.

 

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. The IRS has made no determination on our partnership status or any other tax matter affecting us.

 

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

 

If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to additional entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us. Further, distributions to unitholders would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to our unitholders. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

 

The tax treatment of publicly traded partnerships or an investment in our 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 us, or an investment in our common units 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 we rely for our treatment as a partnership for U.S. federal income tax purposes.

 

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Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us 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 an investment in our common units. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to additional entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

 

If we were subjected to additional entity-level taxation by individual states, it would reduce our cash available for distribution.

 

Changes in current state law may subject us to additional entity-level taxation by individual states. 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. Currently we are subject to income and franchise taxes in several states. Imposition of such taxes on us reduces the cash available for distribution to our unitholders and may adversely affect the value of our common units. Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

 

If the IRS contests the U.S. federal income tax positions we take, the market for our common units may be adversely affected, and the costs of any IRS contest will reduce our cash available for distribution.

 

The IRS has made no determination with respect to our treatment as a partnership for U.S. federal income tax purposes, the classification of any of the gross income from our business operations as “qualifying income” under Section 7704 of the Internal Revenue Code, or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take, and a court may not agree with some or all of those positions. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will result in a reduction in cash available for distribution and thus will be borne indirectly by our unitholders and our general partner.

 

Unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

 

Because our unitholders are treated as partners to whom we will allocate taxable income, which could be different in amount than the cash we distribute, they will be required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

 

Tax gain or loss on the disposition of our common units could be more or less than expected.

 

Unitholders who sell common units recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units they sell will, in effect, become taxable income to them if they sell such common units at a price greater than their tax basis in those common units, even if the price received is less than the original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, unitholders who sell their units may incur a tax liability in excess of the amount of cash they receive from the sale.

 

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

 

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (“IRAs”), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. Tax-exempt entities or a non-U.S. persons should consult their tax advisors before investing in our common units.

 

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We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

 

Due to a number of factors, including our inability to match transferors and transferees of common units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to unitholders’ tax returns.

 

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, and, if successful, we would be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

 

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury regulations. The U.S. Treasury Department’s proposed Treasury Regulations allowing a similar monthly simplifying convention are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS were to successfully challenge this method or new Treasury Regulations were issued, we could be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

 

A unitholder whose units are the subject of a securities loan (e.g. a loan to a “short seller” to cover a short sale of units) may be considered to have disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

 

Because there are no specific rules governing the U.S. federal income consequences of loaning a partnership interest, a unitholder whose units are the subject of securities loan may be considered to have disposed of the loaned units. In that case, the unitholder may no longer be treated as a partner for tax purposes with respect to those units and may recognize gain or loss from such disposition during the period of the loan. Moreover, during the period of such loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder for those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

 

We have adopted certain valuation methodologies in determining unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methods or the resulting allocations, and such a challenge could adversely affect the value of our common units.

 

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our respective assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our respective assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

 

A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

 

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for U.S. federal income tax purposes.

 

We will be considered to have constructively terminated as a partner for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same unit will count only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns for one calendar year. However, pursuant to an IRS relief procedure, the IRS may allow, among other things, a constructively terminated partnership to

 

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provide a single Schedule K-1 for the calendar year in which a termination occurs. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for U.S. federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The Spinoff transaction is expected to result in a constructive termination on the date of the transaction for U.S. federal income tax purposes. As a result, our taxable year for all unitholders during the year the Spinoff transaction is consummated is expected to end on the date of the Spinoff transaction and may result in a deferral of depreciation deductions. Any such deferral could result in increased taxable income to unitholders in the year the Spinoff transaction is consummated.

 

Unitholders may become subject to international, state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire property.

 

In addition to U.S. federal income taxes, unitholders will likely be subject to other taxes, including international, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own or acquire property now or in the future, even if they do not live in any of those jurisdictions. Unitholders will likely be required to file international, state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, they may be subject to penalties for failure to comply with those requirements. We conduct business and/or own assets in the states of Alabama, Arkansas, California, Colorado, Illinois, Kansas, Kentucky, Louisiana, Michigan, Mississippi, Missouri, Montana, Nebraska, New Mexico, New York, North Dakota, Ohio, Oklahoma, Pennsylvania, Tennessee, Texas, Utah, West Virginia, Wisconsin and Wyoming. Each of these states, other than Tennessee, Texas and Wyoming, currently imposes a personal income tax on individuals. A majority of these states impose an income tax on corporations and other entities that may be unitholders. As we make acquisitions or expand our business, we may conduct business or own assets in additional states that impose a personal income tax or that impose entity level taxes to which certain unitholders could be subject. It is each unitholder’s responsibility to file all applicable U.S. federal, international, state and local tax returns.

 

Item 1B.  Unresolved Staff Comments

 

None.

 

Item 2.  Properties

 

Our executive office is located at 16666 Northchase Drive, Houston, Texas 77060 and our telephone number is 281-836-7000. We do not own or lease any material facilities or properties. Pursuant to our Omnibus Agreement, we reimburse Exterran Holdings for the cost of our pro rata portion of the properties we utilize in connection with our business.

 

Item 3.  Legal Proceedings

 

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. As a result of this 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 $10.2 million during the year ended December 31, 2014. Since the change in methodology became effective in 2012, we have recorded an aggregate benefit of $20.7 million as of December 31, 2014. A large number of appraisal review boards denied our position, although some accepted it, and we filed 82 petitions for review in the appropriate district courts with respect to the 2012 tax year, 92 petitions for review in the appropriate district courts with respect to the 2013 tax year, and 121 petitions for review in the appropriate district courts with respect to the 2014 tax year. Since we filed the petitions, many of the cases, pending in the same county, have been consolidated. Only five cases have advanced to the point of trial or submission of summary judgment motions on the merits, and only three cases have been decided, with two decisions rendered by the same presiding judge. One other case was dismissed without reaching the merits.

 

On October 17, 2013, the 143rd Judicial District Court of Loving County, Texas ruled in EXLP Leasing LLC & EES Leasing LLC v. Loving County Appraisal District that our wholly-owned subsidiary EXLP Leasing LLC (“EXLP Leasing”) and EES Leasing LLC (“EES Leasing”), a subsidiary of Exterran Holdings, are Heavy Equipment Dealers and that their compressors qualify as Heavy Equipment, but the district court further held that the Heavy Equipment Statutes were unconstitutional as applied to EXLP Leasing’s and EES Leasing’s compressors. EES Leasing and EXLP Leasing appealed the district court’s constitutionality holding to the Eighth Court of Appeals in El Paso, Texas. The case has been fully briefed and was argued before the Court of Appeals on October 9, 2014. No decision has been issued.

 

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On October 28, 2013, the 143rd Judicial District Court of Ward County, Texas ruled in EES Leasing LLC & EXLP Leasing LLC v. Ward County Appraisal District that EXLP Leasing and EES Leasing are Heavy Equipment Dealers and that their compressors qualify as Heavy Equipment, but the court held that the Heavy Equipment Statutes were unconstitutional as applied to their compressors. EXLP Leasing and EES Leasing have appealed the district court’s constitutionality holding to the Eighth Court of Appeals in El Paso, Texas, and the Ward County Appraisal District has cross-appealed the district court’s ruling that EXLP Leasing and EES Leasing are Heavy Equipment Dealers and that their compressors qualify as Heavy Equipment. The case has been fully briefed and was also argued before the Court of Appeals on October 9, 2014. No decision has been issued.

 

On March 18, 2014, the 10th Judicial District Court in Galveston, Texas ruled in EXLP Leasing LLC & EES Leasing LLC v. Galveston Central Appraisal District that EXLP Leasing and EES Leasing are Heavy Equipment Dealers and that their compressors qualify as Heavy Equipment, but the court held the Heavy Equipment Statutes unconstitutional as applied to their compressors. EXLP Leasing and EES Leasing have filed their appellate brief challenging the district court’s constitutionality holding with the Fourteenth Court of Appeals in Houston, Texas. The case has been fully briefed and was argued before the Court of Appeals on February 12, 2015. No decision has been issued.

 

In EES Leasing v. Irion County Appraisal District, EES Leasing and the appraisal district each filed motions for summary judgment concerning the applicability and constitutionality of the Heavy Equipment Statutes in the 51st Judicial District Court of Irion County, Texas. On May 20, 2014, the district court entered an order denying both EES Leasing’s and the appraisal district’s motions for summary judgment, holding that a fact issue existed as to the applicability of the Heavy Equipment Statutes to the one compressor at issue. At a hearing on December 1, 2014, the presiding judge for the 51st District Court indicated that she would consolidate this 2012 tax year case with a 2013 tax year case. EES Leasing LLC and EXLP Leasing LLC v. Irion County Appraisal District, and set the consolidated case for trial on August 10-11, 2015.

 

EES Leasing and EXLP Leasing also filed a motion for summary judgment in EES Leasing LLC & EXLP Leasing LLC v. Harris County Appraisal District, pending in the 189th Judicial District Court of Harris County, Texas. The court heard arguments on the motion on December 6, 2013 but has yet to rule. No trial date has been set.

 

One court has dismissed EXLP Leasing’s and EES Leasing’s tax appeals for lack of jurisdiction without reaching the merits of the appeal. In EXLP Leasing LLC et. al v. Webb County Appraisal District, filed in the 406th Judicial District Court in Webb County, United Independent School District (“United ISD”) intervened as a party in interest and sought to dismiss the lawsuit arguing that the district court was without jurisdiction to hear the appeal. Under Section 42.08(b) of the Texas Tax Code, a property owner must pay before the delinquency date the lesser of (1) the amount of taxes due on the portion of the taxable value of the property that is not in dispute or (2) the amount of taxes due on the property under the order from which the appeal is taken. EXLP Leasing and EES Leasing paid zero taxes to Webb County because the entire amount of tax assessed by Webb County was in dispute. Instead, as required by the Heavy Equipment Statutes and Texas Comptroller forms, EXLP Leasing and EES Leasing paid taxes on the compressors at issue to Victoria County, where they maintain their inventory and place of business. The Webb County Appraisal District and United ISD contest EXLP Leasing’s and EES Leasing’s position that the Heavy Equipment Statutes have special situs provisions requiring that taxes be paid where the dealer has a business location and keeps its inventory, instead arguing that taxes are payable to the county where each compressor is located as of January 1 of the tax year at issue. The court granted United ISD’s motion to dismiss on April 1, 2014 and declined EXLP Leasing’s and EES Leasing’s motion to reconsider. EXLP Leasing and EES Leasing have appealed the dismissal order to the Fourth Court of Appeals in San Antonio, Texas. The case has been fully briefed, and it will be decided on submission.

 

In Webb County, United ISD has four delinquency lawsuits pending against EXLP Leasing and EES Leasing in the 49th District Court of Webb County, Texas (“49th District Court”). In light of the pending appeal of the 406th District Court of Webb County, the 49th District Court granted the motion to continue these delinquency lawsuits filed by EXLP Leasing and EES Leasing, and there is no current trial date for the delinquency lawsuits.

 

We continue to believe that the revised statutes are constitutional as applied to natural gas compressors. 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 2012, 2013, and 2014 district court cases. Please see Note 15 (“Commitments and Contingencies”) to the Financial Statements included in this report for a discussion of our ad valorem tax expense and benefit relating to the Heavy Equipment Statutes, which is incorporated by reference into this Item 3.

 

In the ordinary course of business, we are also involved in various other pending or threatened legal actions. While management is unable to predict the ultimate outcome of these actions, it believes that any ultimate liability arising from any of these other actions will not have a material adverse effect on our consolidated financial position, results of operations or cash flows, including our ability to make cash distributions to our unitholders. However, because of the inherent uncertainty of litigation, we cannot provide assurance that the resolution of any particular claim or proceeding to which we are a party will not have a material adverse effect on our consolidated financial position, results of operations or cash flows, including our ability to make cash distributions to our unitholders.

 

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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 units trade on the NASDAQ Global Select Market under the symbol “EXLP.” On February 19, 2015, the closing price of a common unit was $23.09. At the close of business on February 12, 2015, based upon information received from our transfer agent and brokers and nominees, we had 14 registered common unitholders and approximately 15,450 street name holders. The following table sets forth the range of high and low sale prices for our common units and cash distributions declared per common unit for the periods indicated.

 

 

 

Price Range

 

Cash Distribution
Declared per

 

 

 

High

 

Low

 

Common Unit(1)

 

Year Ended December 31, 2013:

 

 

 

 

 

 

 

First Quarter

 

$

26.45

 

$

20.50

 

$

0.5175

 

Second Quarter

 

$

31.44

 

$

26.11

 

$

0.5225

 

Third Quarter

 

$

32.39

 

$

26.77

 

$

0.5275

 

Fourth Quarter

 

$

31.48

 

$

25.61

 

$

0.5325

 

Year Ended December 31, 2014:

 

 

 

 

 

 

 

First Quarter

 

$

31.00

 

$

27.94

 

$

0.5375

 

Second Quarter

 

$

30.17

 

$

27.10

 

$

0.5425

 

Third Quarter

 

$

30.64

 

$

27.61

 

$

0.5525

 

Fourth Quarter

 

$

30.14

 

$

19.01

 

$

0.5575

 

 


(1)                  Cash distributions declared for each quarter are paid in the following calendar quarter.

 

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.

 

Cash Distribution Policy

 

Within 45 days after the end of each quarter, we will distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. However, there is no guarantee that we will pay any specific distribution level on the units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. We will be prohibited from making any distributions to unitholders if doing so would cause an event of default, or an event of default exists, under our senior secured credit facility.

 

We make distributions of available cash (as defined in our partnership agreement) from operating surplus in the following manner:

 

·          first, 98% to the common unitholders, pro rata, and 2% to our general partner, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

 

·          second, 98% to common unitholders, pro rata, and 2% to our general partner, until each unit has received a distribution of $0.4025;

 

·          third, 85% to all common unitholders, pro rata, and 15% to our general partner, until each unit has received a distribution of $0.4375;

 

·          fourth, 75% to all common unitholders, pro rata, and 25% to our general partner, until each unit has received a total of $0.5250; and

 

·          thereafter, 50% to all common unitholders, pro rata, and 50% to our general partner.

 

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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 Units
Repurchased (1)

 

Average
Price Paid
Per Unit

 

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

 

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

 

October 1, 2014 - October 31, 2014

 

 

$

 

N/A

 

N/A

 

November 1, 2014 - November 30, 2014

 

 

 

N/A

 

N/A

 

December 1, 2014 - December 31, 2014

 

1,311

 

20.85

 

N/A

 

N/A

 

Total

 

1,311

 

$

20.85

 

N/A

 

N/A

 

 


(1)         Represents units withheld to satisfy employees’ tax withholding obligations in connection with vesting of phantom units during the period.

 

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Item 6.  Selected Financial Data

 

The table below shows selected financial data for Exterran Partners, L.P. for each of the five years in the period ended December 31, 2014, which has been derived from our audited Financial Statements. The following information should be read together with Management’s Discussion and Analysis of Financial Condition and Results of Operations and the Financial Statements contained in this report (in thousands, except per unit data):

 

 

 

Years Ended December 31,

 

 

 

2014(1)

 

2013(2)

 

2012(2)

 

2011(2)

 

2010(2)

 

Statement of Operations Data

 

 

 

 

 

 

 

 

 

 

 

Revenue

 

$

581,036

 

$

466,193

 

$

387,493

 

$

308,274

 

$

237,636

 

Gross margin(3)

 

342,998

 

264,148

 

204,333

 

145,349

 

113,394

 

Depreciation and amortization

 

128,196

 

103,711

 

88,298

 

67,930

 

52,518

 

Long-lived asset impairment(4)

 

12,810

 

5,350

 

29,560

 

1,060

 

24,976

 

Restructuring charges

 

702

 

 

 

 

 

Selling, general and administrative — affiliates

 

80,521

 

61,971

 

49,889

 

39,380

 

34,830

 

Interest expense

 

57,811

 

37,068

 

25,167

 

30,400

 

24,037

 

Other (income) expense, net

 

(74

)

(9,481

)

(35

)

(392

)

(314

)

Provision for income taxes

 

1,313

 

1,506

 

945

 

918

 

680

 

Net income (loss)

 

61,719

 

64,023

 

10,509

 

6,053

 

(23,333

)

Weighted average common units outstanding:

 

 

 

 

 

 

 

 

 

 

 

Basic

 

54,107

 

47,651

 

41,371

 

31,390

 

21,360

 

Diluted

 

54,109

 

47,667

 

41,382

 

31,403

 

21,360

 

Weighted average subordinated units outstanding(5):

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

 

 

 

 

 

3,747

 

5,731

 

Diluted

 

 

 

 

 

 

 

3,747

 

5,731

 

Income (loss) per common unit:

 

 

 

 

 

 

 

 

 

 

 

Basic

 

$

0.89

 

$

1.18

 

$

0.14

 

$

0.09

 

$

(0.90

)

Diluted

 

$

0.89

 

$

1.18

 

$

0.14

 

$

0.09

 

$

(0.90

)

Income (loss) per subordinated unit(5):

 

 

 

 

 

 

 

 

 

 

 

Basic

 

 

 

 

 

 

 

$

0.09

 

$

(0.90

)

Diluted

 

 

 

 

 

 

 

$

0.09

 

$

(0.90

)

Other Financial Data:

 

 

 

 

 

 

 

 

 

 

 

EBITDA, as further adjusted(3)

 

$

280,248

 

$

238,833

 

$

180,729

 

$

139,804

 

$

105,163

 

Distributable cash flow(3)

 

$

177,628

 

$

152,976

 

$

117,966

 

$

90,284

 

$

66,831

 

Capital expenditures:

 

 

 

 

 

 

 

 

 

 

 

Growth(6)

 

$

258,636

 

$

126,635

 

$

119,460

 

$

21,389

 

$

12,215

 

Maintenance(7)

 

45,316

 

41,401

 

38,368

 

28,861

 

15,898

 

Cash flows provided by (used in):

 

 

 

 

 

 

 

 

 

 

 

Operating activities

 

$

185,764

 

$

158,286

 

$

125,217

 

$

80,090

 

$

43,682

 

Investing activities

 

(772,407

)

(117,132

)

(228,940

)

(106,463

)

(29,042

)

Financing activities

 

586,756

 

(41,114

)

103,860

 

26,328

 

(14,793

)

Cash distributions declared and paid per limited partner unit in respective periods

 

$

2.1650

 

$

2.0800

 

$

2.0000

 

$

1.9200

 

$

1.8550

 

 

 

 

December 31,

 

 

 

2014(1)

 

2013(2)

 

2012(2)

 

2011(2)

 

2010(2)

 

Balance Sheet Data

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

295

 

$

182

 

$

142

 

$

5

 

$

50

 

Working capital(8)

 

60,256

 

46,802

 

1,661

 

21,121

 

14,751

 

Total assets

 

2,009,444

 

1,368,063

 

1,163,536

 

991,005

 

813,345

 

Long-term debt

 

1,300,295

 

757,955

 

680,500

 

545,500

 

449,000

 

Partners’ capital

 

683,341

 

591,755

 

439,000

 

423,766

 

350,737

 

 


(1)         During 2014, we completed the August 2014 MidCon Acquisition and the April 2014 MidCon Acquisition, which on a combined basis included a fleet of 499 compressor units, comprising approximately 554,000 horsepower. The results of operations attributable to the assets acquired in the August 2014 MidCon Acquisition and the April 2014 MidCon Acquisition have been included in our consolidated financial statements since the date of acquisition. Please see Note 2 to the Financial Statements for further discussion on these acquisitions.

 

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(2)         In March 2013, March 2012, June 2011 and August 2010 we acquired from Exterran Holdings contract operations customer service agreements and a fleet of compressor units used to provide compression services under those agreements. An acquisition of a business from an entity under common control is generally accounted for in accordance with accounting principles generally accepted in the U.S. (“GAAP”) by the acquirer with retroactive application as if the acquisition date was the beginning of the earliest period included in the financial statements. Retroactive effect of these acquisitions was impracticable because such retroactive application would have required significant assumptions in a prior period that cannot be substantiated. Accordingly, our financial statements include the assets acquired, liabilities assumed, revenue and direct operating expenses associated with the acquisitions beginning on the date of each such acquisition.

 

(3)         Gross margin, EBITDA, as further adjusted, and distributable cash flow are non-GAAP financial measures. They are defined, reconciled to net income (loss) and discussed further in “Non-GAAP Financial Measures” below.

 

(4)         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 110 idle compressor units, representing approximately 30,000 horsepower, previously used to provide services. As a result, we performed an impairment review and recorded a $10.1 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 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 $2.3 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 $0.4 million on these assets.

 

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 110 idle compressor units, representing approximately 25,000 horsepower, previously used to provide services. As a result, we performed an impairment review and recorded a $5.4 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 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 260 idle compressor units, representing approximately 71,000 horsepower, previously used to provide services. As a result, we performed an impairment review and recorded a $22.2 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 $7.4 million to reduce the book value of each unit to its estimated fair value.

 

During 2011 and 2010, we reviewed our idle compression fleet for units that were not of the type, configuration, make or model that are cost effective to maintain and operate. Our estimate of the impaired long-lived asset’s fair value was based on either the expected net sale proceeds compared to other fleet units we recently sold and/or a review of other units recently offered for sale by third parties, or the estimated component value of the equipment we plan to use. The net book value of these assets exceeded the fair value by $1.1 million and $0.4 million, respectively, during the years ended December 31, 2011 and 2010, and was recorded as a long-lived asset impairment. Additionally, during December 2010, we completed an evaluation of our longer-term strategies and determined to retire and sell approximately 370 idle compressor units, representing approximately 117,000 horsepower, previously used to provide services in our business. As a result of this decision to sell these compressor units, we performed an impairment review and based on that review, recorded a $24.6 million asset impairment to reduce the book value of each unit to its estimated fair value.

 

(5)         All of our subordinated units were owned by a wholly-owned subsidiary of Exterran Holdings. As of both June 30, 2011 and 2010, we met the requirements under our partnership agreement for early conversion of 1,581,250 of these subordinated units into common units. Accordingly, in each of August 2011 and 2010, 1,581,250 subordinated units owned by Exterran Holdings converted into common units. As of September 30, 2011, we met the requirements under our partnership agreement for the end of the subordination period and, therefore, our remaining 3,162,500 subordinated units converted into common units in November 2011.

 

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(6)         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. Substantially all of our growth capital expenditures are related to the acquisition cost of new compressor units that we add to our fleet. In addition to the cost of new compressor units, 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.

 

(7)         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.

 

(8)        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 GAAP. Our gross margin may not be comparable to a similarly titled measure of another company because other entities may not calculate gross margin in the same manner.

 

Gross margin has certain material limitations associated with its use as compared to net income (loss). These limitations are primarily due to the exclusion of interest expense, depreciation and amortization expense, SG&A expense and impairments. 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 partnership 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)

 

$

61,719

 

$

64,023

 

$

10,509

 

$

6,053

 

$

(23,333

)

Depreciation and amortization

 

128,196

 

103,711

 

88,298

 

67,930

 

52,518

 

Long-lived asset impairment

 

12,810

 

5,350

 

29,560

 

1,060

 

24,976

 

Restructuring charges

 

702

 

 

 

 

 

Selling, general and administrative — affiliates

 

80,521

 

61,971

 

49,889

 

39,380

 

34,830

 

Interest expense

 

57,811

 

37,068

 

25,167

 

30,400

 

24,037

 

Other (income) expense, net

 

(74

)

(9,481

)

(35

)

(392

)

(314

)

Provision for income taxes

 

1,313

 

1,506

 

945

 

918

 

680

 

Gross margin

 

$

342,998

 

$

264,148

 

$

204,333

 

$

145,349

 

$

113,394

 

 

We define EBITDA, as further adjusted, as net income (loss) (a) excluding 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, expensed acquisition costs, other items and non-cash SG&A costs (b) plus the amounts reimbursed to us by Exterran Holdings as a result of the caps on cost of sales and SG&A costs provided in the Omnibus Agreement, which amounts are treated as capital contributions from Exterran Holdings for accounting purposes. We believe EBITDA, as further 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 expense, impairment charges), tax consequences, caps on operating and SG&A costs, non-cash SG&A costs and reimbursements, impairment charges, restructuring charges and other items. Management uses EBITDA, as

 

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further adjusted, as a supplemental measure to review current period operating performance, comparability measures and performance measures for period to period comparisons. Our EBITDA, as further adjusted, may not be comparable to a similarly titled measure of another company because other entities may not calculate EBITDA in the same manner.

 

In the first quarter of 2014, we revised our definition of EBITDA, as further adjusted, to add back expensed acquisition costs. This adjustment was made because management uses the resulting EBITDA, as further adjusted, as a supplemental measure to review current period operating performance. EBITDA, as further adjusted, for the years ended December 31, 2013, 2012, 2011 and 2010 has been restated to exclude this amount for comparison purposes.

 

EBITDA, as further 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 further adjusted, are significant and necessary components to the operations of our business, and, therefore, EBITDA, as further adjusted, should only be used as a supplemental measure of our operating performance.

 

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

 

 

 

Years Ended December 31,

 

 

 

2014

 

2013

 

2012

 

2011

 

2010

 

Net income (loss)

 

$

61,719

 

$

64,023

 

$

10,509

 

$

6,053

 

$

(23,333

)

Provision for income taxes

 

1,313

 

1,506

 

945

 

918

 

680

 

Depreciation and amortization

 

128,196

 

103,711

 

88,298

 

67,930

 

52,518

 

Long-lived asset impairment

 

12,810

 

5,350

 

29,560

 

1,060

 

24,976

 

Restructuring charges

 

702

 

 

 

 

 

Cap on operating and selling, general and administrative costs provided by Exterran Holdings

 

13,850

 

25,180

 

24,758

 

32,397

 

24,720

 

Non-cash selling, general and administrative costs — affiliates

 

1,376

 

1,174

 

797

 

532

 

1,209

 

Interest expense

 

57,811

 

37,068

 

25,167

 

30,400

 

24,037

 

Expensed acquisition costs

 

2,471

 

821

 

695

 

514

 

356

 

EBITDA, as further adjusted

 

$

280,248

 

$

238,833

 

$

180,729

 

$

139,804

 

$

105,163

 

 

We define distributable cash flow as net income (loss) (a) plus depreciation and amortization expense, impairment charges, restructuring charges, expensed acquisition costs, non-cash SG&A costs, interest expense and any amounts reimbursed to us by Exterran Holdings as a result of the caps on cost of sales and SG&A costs provided in the Omnibus Agreement, which amounts are treated as capital contributions from Exterran Holdings for accounting purposes, (b) less cash interest expense (excluding amortization of deferred financing fees, amortization of debt discount and non-cash transactions related to interest rate swaps) and maintenance capital expenditures, and (c) excluding gains or losses on asset sales and other items. Distributable cash flow is a supplemental financial measure that management and, we believe, external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess our operating performance as compared to other publicly traded partnerships without regard to historical cost basis. We also believe distributable cash flow is an important liquidity measure because it allows management and external users of our financial statements the ability to compute the ratio of distributable cash flow to the cash distributions declared to all unitholders, including incentive distribution rights, to determine the rate at which the distributable cash flow covers the distribution. Our distributable cash flow may not be comparable to a similarly titled measure of another company because other entities may not calculate distributable cash flow in the same manner.

 

Distributable cash flow 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 distributable cash flow are significant and necessary components to the operations of our business, and, therefore, distributable cash flow 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 distributable cash flow (in thousands, except ratios):

 

 

 

Years Ended December 31,

 

 

 

2014

 

2013

 

2012

 

2011

 

2010

 

Net income (loss)

 

$

61,719

 

$

64,023

 

$

10,509

 

$

6,053

 

$

(23,333

)

Depreciation and amortization

 

128,196

 

103,711

 

88,298

 

67,930

 

52,518

 

Long-lived asset impairment

 

12,810

 

5,350

 

29,560

 

1,060

 

24,976

 

Restructuring charges

 

702

 

 

 

 

 

Cap on operating and selling, general and administrative costs provided by Exterran Holdings

 

13,850

 

25,180

 

24,758

 

32,397

 

24,720

 

Non-cash selling, general and administrative costs — affiliates

 

1,376

 

1,174

 

797

 

532

 

1,209

 

Interest expense

 

57,811

 

37,068

 

25,167

 

30,400

 

24,037

 

Expensed acquisition costs

 

2,471

 

821

 

695

 

514

 

356

 

Less: Gain on sale of property, plant and equipment

 

(2,466

)

(10,140

)

(689

)

(919

)

(667

)

Less: Cash interest expense

 

(53,525

)

(32,810

)

(22,761

)

(18,822

)

(21,087

)

Less: Maintenance capital expenditures

 

(45,316

)

(41,401

)

(38,368

)

(28,861

)

(15,898

)

Distributable cash flow

 

$

177,628

 

$

152,976

 

$

117,966

 

$

90,284

 

$

66,831

 

 

 

 

 

 

 

 

 

 

 

 

 

Distributions declared to all unitholders for the period, including incentive distributions rights

 

$

136,829

 

$

112,705

 

$

91,617

 

$

74,214

 

$

54,913

 

Distributable cash flow coverage(1)

 

1.30

x

1.36

x

1.29

x

1.22

x

1.22

x

Distributable cash flow coverage (without the benefit of the cost caps)(2)

 

1.20

x

1.13

x

1.02

x

0.78

x

0.77

x

 


(1)         Defined as distributable cash flow for the period divided by distributions declared to all unitholders for the period, including incentive distribution rights.

 

(2)         Defined as distributable cash flow excluding the benefit of the cost caps divided by distributions declared to all unitholders for the period, including incentive distribution rights. The benefit received by us from the caps on operating and selling, general and administrative costs provided by Exterran Holdings was $13.9 million, $25.2 million, $24.8 million, $32.4 million and $24.7 million during the years ended December 31, 2014, 2013, 2012, 2011 and 2010, respectively.

 

The following table reconciles our net cash provided by operating activities to distributable cash flow (in thousands):

 

 

 

Years Ended December 31,

 

 

 

2014

 

2013

 

2012

 

2011

 

2010

 

Net cash provided by operating activities

 

$

185,764

 

$

158,286

 

$

125,217

 

$

80,090

 

$

43,682

 

(Provision for) benefit from doubtful accounts

 

(1,060

)

25

 

(494

)

(83

)

(1,292

)

Restructuring charges

 

702

 

 

 

 

 

Cap on operating and selling, general and administrative costs provided by Exterran Holdings

 

13,850

 

25,180

 

24,758

 

32,397

 

24,720

 

Expensed acquisition costs

 

2,471

 

821

 

695

 

514

 

356

 

Payments for settlement of interest rate swaps that include financing elements

 

(3,793

)

(2,207

)

 

 

 

Maintenance capital expenditures

 

(45,316

)

(41,401

)

(38,368

)

(28,861

)

(15,898

)

Changes in assets and liabilities

 

25,010

 

12,272

 

6,158

 

6,227

 

15,263

 

Distributable cash flow

 

$

177,628

 

$

152,976

 

$

117,966

 

$

90,284

 

$

66,831

 

 

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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 Delaware limited partnership formed in June 2006 to provide natural gas contract operations services to customers throughout the U.S. Our contract operations services primarily include designing, sourcing, owning, installing, operating, servicing, repairing and maintaining equipment to provide natural gas compression services to our customers.

 

Our customers typically contract for our contract operations services on a site-by-site basis for a specific monthly service rate that is reduced if we fail to operate in accordance with the contract terms. Following the initial minimum term for our contract compression services, which is typically between six and twelve months, contract compression 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. See “General Terms of Our Contract Operations Customer Service Agreements,” in Part I, Item 1 (“Business”) of this report, for a more detailed description.

 

Generally, our overall business activity and revenue increase as the demand for natural gas increases. Demand for our compression services is linked more directly to natural gas consumption and production than to exploration activities, which helps limit our direct exposure to commodity price risk. Because we typically do not take title to the natural gas we compress, and the natural gas we use as fuel for our compressors is supplied by our customers, our direct exposure to commodity price risk is further reduced.

 

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

 

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.

 

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.

 

Oil and 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 have begun to announce reduced capital budgets for this year.

 

Our Performance Trends and Outlook

 

Our results of operations depend upon the level of activity in the U.S. energy market. Oil and natural gas prices and the level of drilling and exploration activity can be volatile. For example, oil and natural gas exploration and development activity and the number of well completions typically decline when there is a significant reduction in oil and natural gas prices or significant instability in energy markets.

 

Our revenue, earnings and financial position are affected by, among other things, market conditions that impact demand and pricing for natural gas compression, our customers’ decisions between using our services or our competitors’ services, our customers’ decisions regarding whether to own and operate the equipment themselves, and the timing and consummation of acquisitions of additional contract operations customer service agreements and equipment from Exterran Holdings or others. As a result of expected declines in customer spending in 2015, we anticipate investing less capital in new fleet units in 2015 than we did in 2014.

 

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During 2014, we continued to see steady activity in certain 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 the year ended December 31, 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 the U.S. Historically, oil and natural gas prices in the U.S. 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 2015. During periods of lower oil or natural gas prices, oil and natural gas production growth could moderate or decline in the U.S. A 1% decrease in average operating horsepower of our contract operations fleet during the year ended December 31, 2014 would have resulted in a decrease of approximately $5.8 million and $3.4 million in our revenue and gross margin (defined as revenue less cost of sales, excluding depreciation and amortization expense), respectively. Gross margin is a non-GAAP financial measure. For a reconciliation of gross margin to net income (loss), its most directly comparable financial measure, calculated and presented in accordance with GAAP, please see Part II, Item 6 (“Selected Financial Data — Non-GAAP Financial Measures”) of this report.

 

Exterran Holdings intends for us to be the primary long-term growth vehicle for its U.S. contract operations business and may, but is not obligated to, offer us the opportunity to purchase additional portions of its U.S. contract operations business over time. Likewise, we are not required to purchase any additional portions of such business. The consummation of any future purchase of additional portions of Exterran Holdings’ U.S. contract operations business and the timing of any such purchase will depend upon, among other things, our ability to reach an agreement with Exterran Holdings regarding the terms of such purchase, which will require the approval of the conflicts committee of our board of directors. The timing of such transactions would also depend on, among other things, market and economic conditions and our access to additional debt and equity capital. Future acquisitions of assets from Exterran Holdings may increase or decrease our operating performance, financial position and liquidity. Unless otherwise indicated, this discussion of performance trends and outlook excludes any future potential transfers of additional contract operations customer service agreements and equipment from Exterran Holdings to us.

 

Certain Key Challenges and Uncertainties

 

Market conditions in the oil and natural gas industry and competition in the natural gas compression industry represent key challenges and uncertainties. In addition to these, we believe the following represent some of the key challenges and uncertainties we will face in the near future:

 

Termination of Cost Caps from Exterran Holdings.  Under the Omnibus Agreement, our obligation to reimburse Exterran Holdings for any cost of sales that it incurred in the operation of our business and any cash SG&A expense allocated to us was capped (after taking into account any such costs we incurred and paid directly) through December 31, 2014. Cost of sales was capped at $21.75 per operating horsepower per quarter through December 31, 2013 and $22.50 per operating horsepower per quarter from January 1, 2014 through December 31, 2014. SG&A costs were capped at $9.0 million per quarter from June 10, 2011 through March 7, 2012, $10.5 million per quarter from March 8, 2012 through March 31, 2013, $12.5 million per quarter from April 1, 2013 through December 31, 2013, $15.0 million per quarter from January 1, 2014 through April 9, 2014 and $17.7 million per quarter from April 10, 2014 through December 31, 2014. Our cost of sales exceeded the cap provided in the Omnibus Agreement by $2.5 million, $12.4 million and $16.6 million during the years ended December 31, 2014, 2013, and 2012, respectively. Our SG&A expenses exceeded the cap provided in the Omnibus Agreement by $11.4 million, $12.8 million and $8.2 million during the years ended December 31, 2014, 2013 and 2012, respectively. Accordingly, our EBITDA, as further adjusted, and our distributable cash flow (please see Part II, Item 6 (“Selected Financial Data — Non-GAAP Financial Measures”) of this report for a discussion of EBITDA, as further adjusted, and distributable cash flow) would have been approximately $13.9 million, $25.2 million and $24.8 million lower during the years ended December 31, 2014, 2013 and 2012, respectively, without the benefit of the cost caps. As a result, without the benefit of the cost caps, our distributable cash flow coverage (distributable cash flow for the period divided by distributions declared to all unitholders for the period, including incentive distribution rights) would have been 1.20x, 1.13x and 1.02x during the years ended December 31, 2014, 2013 and 2012, respectively, rather than the actual distributable cash flow coverage (which includes the benefit of cost caps) of 1.30x, 1.36x and 1.29x during the years ended December 31, 2014, 2013, and 2012, respectively. These cost caps were in effect through December 31, 2014; however, effective January 1, 2015, the cost caps provisions of the Omnibus Agreement terminated. Their termination could reduce the amount of cash flow available to unitholders in the future and, accordingly, could impair our ability to maintain or increase our distributions.

 

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U.S. Market and Oil and Natural Gas Pricing.  During 2014, we continued to see steady activity in certain 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 the year ended December 31, 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 the U.S. Historically, oil and natural gas prices in the U.S. 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 2015. During periods of lower oil or natural gas prices, oil and natural gas production growth could moderate or decline in the U.S, and as a result the demand or pricing for our contract operations 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 contracts 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 and our distributable cash flow.

 

Additional Purchases of Exterran Holdings’ Contract Operations Business By Us.  We plan to grow over time through accretive acquisitions of assets from Exterran Holdings, third-party compression providers and natural gas transporters or producers. The consummation of any future purchase of additional portions of Exterran Holdings’ business and the timing of any such purchase will depend upon, among other things, our ability to reach an agreement with Exterran Holdings regarding the terms of any such purchase, which will require the approval of the conflicts committee of our board of directors. The timing of such transactions would also depend on, among other things, market and economic conditions and our access to additional debt and equity capital. Future acquisitions of assets from Exterran Holdings or third parties may increase or decrease our operating performance, financial position and liquidity.

 

Labor.  We have no employees. Exterran Holdings provides all operational staff, corporate staff and support services necessary to run our business, and therefore we depend on Exterran Holdings’ ability to hire, train and retain qualified personnel. Although Exterran Holdings has been able to satisfy personnel needs in these positions thus far, retaining employees in our industry is a challenge. Our ability to grow and to continue to make quarterly distributions will depend in part on Exterran Holdings’ success in hiring, training and retaining these employees.

 

Operating Highlights

 

The following table summarizes total available horsepower, total operating horsepower, average operating horsepower and horsepower utilization percentages (in thousands, except percentages):

 

 

 

Years Ended December 31,

 

 

 

2014

 

2013

 

2012

 

Total Available Horsepower (at period end)(1)

 

3,139

 

2,417

 

2,084

 

Total Operating Horsepower (at period end)(1)

 

3,040

 

2,264

 

1,991

 

Average Operating Horsepower

 

2,710

 

2,155

 

1,883

 

Horsepower Utilization:

 

 

 

 

 

 

 

Spot (at period end)

 

97

%

94

%

96

%

Average

 

95

%

94

%

93

%

 


(1)                  Includes compressor units comprising approximately 79,000, 109,000 and 163,000 horsepower leased from Exterran Holdings as of December 31, 2014, 2013 and 2012, respectively. Excludes compressor units comprising approximately 100, 8,000 and 9,000 horsepower leased to Exterran Holdings as of December 31, 2014, 2013 and 2012, respectively (see Note 3 to the Financial Statements).

 

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Summary of Results

 

Net income.  We generated net income of $61.7 million, $64.0 million and $10.5 million during the years ended December 31, 2014, 2013 and 2012, respectively. The decrease in net income during the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily due to increases in interest expense and long-lived asset impairment in the current year period and the termination of two natural gas processing plant contracts during the second quarter of 2013 resulting in the recognition of $9.8 million of gross margin and $6.8 million of gain on sale of property, plant and equipment. These activities were offset by the inclusion of the results from the assets acquired in the August 2014 MidCon Acquisition, the April 2014 MidCon Acquisition and the March 2013 Contract Operations Acquisition, which resulted in higher current year gross margin and depreciation and amortization expense and contributed to the increase in SG&A expense. The increase in net income during the year ended December 31, 2013 compared to the year ended December 31, 2012 was primarily due to an increase in gross margin, a decrease in long-lived asset impairment and a $9.5 million increase in gain on sale of property, plant and equipment, partially offset by an increase in interest expense. The increase in net income during the year ended December 31, 2013 compared to the year ended December 31, 2012 was impacted by the assets acquired in the March 2013 Contract Operations Acquisition and the March 2012 Contract Operations Acquisition, which resulted in higher 2013 gross margin, depreciation and amortization expense and SG&A expense.

 

EBITDA, as further adjusted.  Our EBITDA, as further adjusted, was $280.2 million, $238.8 million and $180.7 million during the years ended December 31, 2014, 2013 and 2012, respectively. The increase in EBITDA, as further adjusted, during the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily due to the impact of the assets acquired in the August 2014 MidCon Acquisition, the April 2014 MidCon Acquisition and the March 2013 Contract Operations Acquisition, including improved gross margin. These activities were partially offset by $9.8 million of gross margin and $6.8 million of gain on sale of property, plant and equipment recognized on two natural gas processing plant contracts that terminated during the second quarter of 2013, a decrease of $9.8 million in the benefit received by us from the cap on operating costs provided by Exterran Holdings and the impact of the increase in the SG&A costs cap from an average of $12.0 million per quarter during the year ended December 31, 2013 to an average of $17.0 million per quarter during the year ended December 31, 2014. The increase in EBITDA, as further adjusted, during the year ended December 31, 2013 compared to the year ended December 31, 2012 was primarily due to the impact of the assets acquired in the March 2013 Contract Operations Acquisition and the March 2012 Contract Operations Acquisition, including improved gross margin, and a $9.5 million increase in gain on sale of property, plant and equipment. These activities were partially offset by the impact of the increase in the SG&A costs cap from an average of $10.2 million per quarter during the year ended December 31, 2012 to an average of $12.0 million per quarter during the year ended December 31, 2013 and a decrease of $4.2 million in the benefit received by us from the cap on operating costs provided by Exterran Holdings. For a reconciliation of EBITDA, as further adjusted, to net income (loss), its most directly comparable financial measure calculated and presented in accordance with GAAP, please see Part II, Item 6 (“Selected Financial Data — Non-GAAP Financial Measures”) of this report.

 

Distributable cash flow.  Our distributable cash flow was $177.6 million, $153.0 million and $118.0 million during the years ended December 31, 2014, 2013 and 2012, respectively, and distributable cash flow coverage (distributable cash flow for the period divided by distributions declared to all unitholders for the period, including incentive distribution rights) was 1.30x, 1.36x and 1.29x during the years ended December 31, 2014, 2013 and 2012, respectively. The increases in distributable cash flow during the year ended December 31, 2014 compared to the year ended December 31, 2013 and the year ended December 31, 2013 compared to the year ended December 31, 2012 were primarily due to increases in the gross margin discussed above, partially offset by the impact of increases in the SG&A costs cap discussed above, decreases in benefits received from the cap on operating costs provided by Exterran Holdings discussed above, increases in cash interest expense and increases in maintenance capital expenditures. Distributable cash flow and distributable cash flow coverage during the year ended December 31, 2013 benefited from $9.8 million of gross margin recognized on two natural gas processing plant contracts that terminated during the second quarter of 2013. Additionally, distributable cash flow coverage was impacted by an increase in distributions declared to all unitholders, including incentive distribution rights, from $91.6 million during the year ended December 31, 2012 to $136.8 million during the year ended December 31, 2014. The increase in cash distributions declared was due to the issuance of additional common units and general partner units and an increase of distributions declared per unit, including the increase in the distributions on incentive distribution rights, during the years ended December 31, 2014 and 2013. For a reconciliation of distributable cash flow to net income (loss) and net cash provided by operating activities, its most directly comparable financial measures calculated and presented in accordance with GAAP, please see Part II, Item 6 (“Selected Financial Data — Non-GAAP Financial Measures”) of this report.

 

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Financial Results of Operations

 

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

 

The following table summarizes our revenue, gross margin, gross margin percentage, expenses and net income (dollars in thousands):

 

 

 

Years Ended December 31,

 

 

 

2014

 

2013

 

Revenue

 

$

581,036

 

$

466,193

 

Gross margin(1)

 

342,998

 

264,148

 

Gross margin percentage(2)

 

59

%

57

%

Expenses:

 

 

 

 

 

Depreciation and amortization

 

$

128,196

 

$

103,711

 

Long-lived asset impairment

 

12,810

 

5,350

 

Restructuring charges

 

702

 

 

Selling, general and administrative — affiliates

 

80,521

 

61,971

 

Interest expense

 

57,811

 

37,068

 

Other (income) expense, net

 

(74

)

(9,481

)

Provision for income taxes

 

1,313

 

1,506

 

Net income

 

$

61,719

 

$

64,023

 

 


(1)               Defined as revenue less cost of sales, excluding depreciation and amortization expense. For a reconciliation of gross margin to net income (loss), its most directly comparable financial measure calculated and presented in accordance with GAAP, please see Part II, Item 6 (“Selected Financial Data — Non-GAAP Financial Measures”) of this report.

 

(2)               Defined as gross margin divided by revenue.

 

Revenue.  The increase in revenue and average operating horsepower was primarily due to the inclusion of the results from the assets acquired in the August 2014 MidCon Acquisition, the April 2014 MidCon Acquisition and the March 2013 Contract Operations Acquisition as well as from organic growth in operating horsepower. Average operating horsepower increased by 26% from approximately 2,155,000 during the year ended December 31, 2013 to approximately 2,710,000 during the year ended December 31, 2014. The increase in revenue during the year ended December 31, 2014 compared to the year ended December 31, 2013 was also attributable to higher rates in the current year. These increases in revenue were partially offset by an $11.2 million decrease in revenue due to the termination of two natural gas processing plant contracts during the second quarter of 2013.

 

Gross Margin.  The increases in gross margin and gross margin percentage during the year ended December 31, 2014 compared to the year ended December 31, 2013 were primarily due to the increases in revenue discussed above, partially offset by a $9.8 million decrease in gross margin due to the termination of two natural gas processing plant contracts during the second quarter of 2013.

 

Depreciation and Amortization.  The increase in depreciation and amortization expense during the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily due to additional depreciation expense on compression equipment additions, including the assets acquired in the August 2014 MidCon Acquisition, the April 2014 MidCon Acquisition and the March 2013 Contract Operations Acquisition, and additional amortization expense attributable to intangible assets acquired in the August 2014 MidCon Acquisition and the April 2014 MidCon Acquisition.

 

Long-Lived Asset Impairment.  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 110 idle compressor units, representing approximately 30,000 horsepower, previously used to provide services. As a result, we performed an impairment review and recorded a $10.1 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 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 $2.3 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 $0.4 million on these assets.

 

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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 110 idle compressor units, representing approximately 25,000 horsepower, previously used to provide services. As a result, we performed an impairment review and recorded a $5.4 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.

 

Restructuring Charges.  In January 2014, Exterran Holdings announced a plan to centralize its make-ready operations to improve the cost and efficiency of its shops and further enhance the competitiveness of our and Exterran Holdings’ combined U.S. compressor fleet. As part of this plan, Exterran Holdings examined both recent and anticipated changes in the U.S. market, including the throughput demand of its shops and the addition of new equipment to our and Exterran Holdings’ combined U.S. compressor fleet. To better align its costs and capabilities with the current market, Exterran Holdings determined to close several of its make-ready shops. The centralization of its make-ready operations was completed in the second quarter of 2014. During the year ended December 31, 2014, we incurred $0.7 million of restructuring charges comprised of an allocation of expenses, including termination benefits associated with the centralization of Exterran Holdings’ make-ready operations, from Exterran Holdings to us pursuant to the terms of the Omnibus Agreement based on revenue and horsepower. See Note 12 to the Financial Statements for further discussion of these charges.

 

SG&A — affiliates.  SG&A expenses are primarily comprised of an allocation of expenses, including costs for personnel support and related expenditures, from Exterran Holdings to us pursuant to the terms of the Omnibus Agreement. The increase in SG&A expense was primarily due to increased costs associated with the impact of the August 2014 MidCon Acquisition, the April 2014 MidCon Acquisition and the March 2013 Contract Operations Acquisition. SG&A expenses represented 14% and 13% of revenue during the years ended December 31, 2014 and 2013, respectively.

 

Interest Expense.  The increase in interest expense during the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily due to a higher average balance of long-term debt and an increase in the weighted average effective interest rate on our debt caused by the issuance of the 2014 Notes in April 2014 and the issuance of the 2013 Notes in March 2013.

 

Other (Income) Expense, Net.  Other (income) expense, net, during the year ended December 31, 2014 included $2.5 million of transaction costs associated with the August 2014 MidCon Acquisition and the April 2014 MidCon Acquisition and $2.5 million of gain on sale of property, plant and equipment. Other (income) expense, net, during the year ended December 31, 2013 included $10.1 million of gain on sale of property, plant and equipment, of which $6.8 million resulted from the exercise of purchase options by our customer on two natural gas processing plant contracts, and $0.8 million of transaction costs associated with the April 2014 MidCon Acquisition and the March 2013 Contract Operations Acquisition.

 

Provision for Income Taxes.  The decrease in our provision for income taxes during the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily due to a state tax benefit recognized in the current period for amendments to previously filed tax returns, partially offset by increased revenue subject to state-level taxation.

 

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

 

The following table summarizes our revenue, gross margin, gross margin percentage, expenses and net income (dollars in thousands):

 

 

 

Years Ended December 31,

 

 

 

2013

 

2012

 

Revenue

 

$

466,193

 

$

387,493

 

Gross margin(1)

 

264,148

 

204,333

 

Gross margin percentage(2)

 

57

%

53

%

Expenses:

 

 

 

 

 

Depreciation and amortization

 

$

103,711

 

$

88,298

 

Long-lived asset impairment

 

5,350

 

29,560

 

Selling, general and administrative — affiliates

 

61,971

 

49,889

 

Interest expense

 

37,068

 

25,167

 

Other (income) expense, net

 

(9,481

)

(35

)

Provision for income taxes

 

1,506

 

945

 

Net income

 

$

64,023

 

$

10,509

 

 

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(1)               Defined as revenue less cost of sales, excluding depreciation and amortization expense. For a reconciliation of gross margin to net income (loss), its most directly comparable financial measure calculated and presented in accordance with GAAP, please see Part II, Item 6 (“Selected Financial Data — Non-GAAP Financial Measures”) of this report.

 

(2)               Defined as gross margin divided by revenue.

 

Revenue.  The increase in revenue and average operating horsepower was primarily due to the inclusion of the results from the assets acquired in the March 2013 Contract Operations Acquisition and the March 2012 Contract Operations Acquisition, as well as from organic growth in operating horsepower. Average operating horsepower was approximately 2,155,000 and 1,883,000 during the years ended December 31, 2013 and 2012, respectively. The increase in revenue during the year ended December 31, 2013 compared to the year ended December 31, 2012 was also attributable to an increase in rates 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 $4.5 million decrease in revenue due to the termination of the contracts associated with those plants during the second quarter of 2013.

 

Gross Margin.  The increases in gross margin and gross margin percentage during the year ended December 31, 2013 compared to the year ended December 31, 2012 were primarily due to the increases in revenue discussed above, improved management of field operating expenses from the implementation of profitability improvement initiatives by Exterran Holdings and a $3.2 million decrease in intercompany lease expense on equipment leased from Exterran Holdings.

 

Depreciation and Amortization.  The increase in depreciation and amortization expense during the year ended December 31, 2013 compared to the year ended December 31, 2012 was primarily due to additional depreciation on compression equipment additions, including the assets acquired in the March 2013 Contract Operations Acquisition and the March 2012 Contract Operations Acquisition, partially offset by the impact of impairments recorded in 2012, which decreased depreciation and amortization expense during the year ended December 31, 2013.

 

Long-Lived Asset Impairment.  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 110 idle compressor units, representing approximately 25,000 horsepower, previously used to provide services. As a result, we performed an impairment review and recorded a $5.4 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 the year ended December 31, 2012, we evaluated the future deployment of our idle fleet and determined to retire and either sell or re-utilize the key components of approximately 260 idle compressor units, representing approximately 71,000 horsepower, previously used to provide services. As a result, we performed an impairment review and recorded a $22.2 million asset impairment to reduce the book value of each unit to its estimated fair value. The fair value of each unit was estimated based on either the expected net sale proceeds compared to other fleet units we recently sold and/or a review of other units recently offered for sale by third parties, or the estimated component value of the equipment we plan to use. The average age of the idle units we impaired during the second quarter of 2012 was 27 years.

 

In connection with our 2012 fleet review, we evaluated for impairment idle units that had been culled from our fleet in prior years and were available for sale. Based upon that review, we reduced the expected proceeds from disposition for most of the remaining units and increased the weighted average disposal period for the units from the assumptions used in prior periods. This resulted in an additional impairment of $7.4 million to reduce the book value of each unit to its estimated fair value.

 

SG&A — affiliates.  SG&A expenses are primarily comprised of an allocation of expenses, including costs for personnel support and related expenditures, from Exterran Holdings to us pursuant to the terms of the Omnibus Agreement. The increase in SG&A expense was primarily due to increased costs associated with the impact of the March 2013 Contract Operations Acquisition and the March 2012 Contract Operations Acquisition. SG&A expenses represented 13% of revenue for each of the years ended December 31, 2013 and 2012.

 

Interest Expense.  The increase in interest expense during the year ended December 31, 2013 compared to the year ended December 31, 2012 was primarily due to an increase in the weighted average effective interest rate on our debt and a higher average balance of long-term debt. The increase in the weighted average effective rate on our debt was primarily due to the issuance of the 2013 Notes in March 2013 and a charge of $0.7 million related to the write-off of unamortized deferred financing costs in conjunction with the March 2013 amendment to our Credit Agreement.

 

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Other (Income) Expense, Net.  Other (income) expense, net, included $10.1 million of gain on sale of property, plant and equipment, of which $6.8 million resulted from the exercise of purchase options by our customer on two natural gas processing plants during the year ended December 31, 2013. Other (income) expense, net, included $0.7 million of gain on sale of property, plant and equipment during the year ended December 31, 2012. Additionally, other (income) expense, net, during the years ended December 31, 2013 and 2012 included $0.8 million of transaction costs associated with April 2014 MidCon Acquisition and the March 2013 Contract Operations Acquisition and $0.7 million of transaction costs associated with the March 2012 Contract Operations Acquisition, respectively.

 

Provision for Income Taxes.  The increase in our provision for income taxes during the year ended December 31, 2013 compared to the year ended December 31, 2012 was primarily due to increased revenue subject to state-level taxation.

 

Liquidity and Capital Resources

 

The following tables summarize our sources and uses of cash during the years ended December 31, 2014 and 2013, and our cash and working capital as of the end of the periods presented (in thousands):

 

 

 

Years Ended December 31,

 

 

 

2014

 

2013

 

Net cash provided by (used in):

 

 

 

 

 

Operating activities

 

$

185,764

 

$

158,286

 

Investing activities

 

(772,407

)

(117,132

)

Financing activities

 

586,756

 

(41,114

)

Net change in cash and cash equivalents

 

$

113

 

$

40

 

 

 

 

December 31,

 

 

 

2014

 

2013

 

Cash and cash equivalents

 

$

295

 

$

182

 

Working capital

 

60,256

 

46,802

 

 

Operating Activities.  The increase in net cash provided by operating activities was primarily due to the increase in business levels resulting from the August 2014 MidCon Acquisition, the April 2014 MidCon Acquisition and the March 2013 Contract Operations Acquisition, which contributed to the increase in gross margin and SG&A expense during the year ended December 31, 2014 compared to the year ended December 31, 2013. This activity was partially offset by a $9.8 million decrease in gross margin due to the termination of two natural gas processing plant contracts during the second quarter of 2013 and higher interest payments during the year ended December 31, 2014 compared to the year ended December 31, 2013.

 

Investing Activities.  The increase in net cash used in investing activities during the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily attributable to $483.0 million paid for the August 2014 MidCon Acquisition and the April 2014 MidCon Acquisition during the year ended December 31, 2014, a $135.9 million increase in capital expenditures and a $55.1 million decrease in proceeds from sale of property, plant and equipment. These activities were partially offset by a decrease of $18.8 million in amounts due from affiliates during the year ended December 31, 2014 compared to the year ended December 31, 2013. Capital expenditures during the year ended December 31, 2014 were $304.0 million, consisting of $258.7 million for fleet growth capital and $45.3 million for compressor maintenance activities.

 

Financing Activities.  The increase in net cash provided by financing activities during the year ended December 31, 2014 compared to the year ended December 31, 2013 was primarily due to an increase of $464.3 million in net borrowings of long-term debt, $169.5 million of net proceeds received from a public offering of common units in April 2014 and a $21.6 million decrease in amounts due to affiliates, net, during the year ended December 31, 2013. These activities were partially offset by a $23.1 million increase in distributions to unitholders during the year ended December 31, 2014 compared to the year ended December 31, 2013.

 

Working Capital.  The increase in working capital at December 31, 2014 compared to December 31, 2013 was primarily due to an increase of $26.8 million in accounts receivable and a decrease of $2.3 million in accrued liabilities, partially offset by a decrease of $8.2 million in amounts due from affiliates and an increase of $5.9 million in accrued interest. The increase in accounts receivable was primarily driven by billings on contracts acquired in the August 2014 MidCon Acquisition and the April 2014 MidCon Acquisition. The increase in accrued interest was primarily due to the issuance of the 2014 Notes in April 2014.

 

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Capital Requirements.  The natural gas compression business is capital intensive, requiring significant investment to maintain and upgrade existing operations. Our capital spending is dependent on the demand for our services and the availability of the type of compression equipment required for us to render those services to our customers. Our capital requirements have consisted primarily of, and we anticipate will continue to consist of, the following:

 

·          growth capital expenditures, which are made to expand or to replace partially or fully depreciated assets or to expand the operating capacity or revenue generating capabilities of existing or new assets, whether through construction, acquisition or modification; and

 

·          maintenance capital expenditures, which are made to maintain the existing operating capacity of our assets and related cash flows further extending the useful lives of the assets.

 

Substantially all of our growth capital expenditures are related to the acquisition cost of new compressor units that we add to our fleet. In addition to the cost of new compressor units, 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 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 for which it previously was not suited. Maintenance capital expenditures are related to 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 for which the compressor unit was designed.

 

Growth capital expenditures were $258.7 million, $126.6 million and $119.4 million for the years ended December 31, 2014, 2013 and 2012, respectively. This increase in growth capital expenditures over the last three years has been driven primarily by increased demand for natural gas compression in certain shale plays and areas focused on the production of oil and natural gas liquids. This activity has increased the utilization of our compressor units that are more suitable to these plays. As a result, we have increased our capital expenditures in 2014 and 2013 to acquire new compressor units that are able to meet this demand. Based on current market conditions, we anticipate investing less capital in new fleet units in 2015 than we did in 2014.

 

Maintenance capital expenditures were $45.3 million, $41.4 million and $38.4 million in the years ended December 31, 2014, 2013 and 2012, respectively. The increase in maintenance capital expenditures is primarily related to the growth of our compressor unit fleet which has grown from 1.7 million of operating horsepower at the beginning of 2012 to 3.0 million of operating horsepower at the end of 2014. We intend to continue to grow our business both organically and through acquisitions. We completed an acquisition from Exterran Holdings in each year since our initial public offering in 2006 through 2013. Additionally, we completed the August 2014 MidCon Acquisition and April 2014 MidCon Acquisition during the year ended December 31, 2014. If we are successful in growing our business in the future, we would expect our maintenance capital expenditures to continue to increase.

 

Without giving effect to any equipment we may acquire pursuant to any future acquisitions, we currently plan to make approximately $200 million to $225 million in capital expenditures during 2015, including (1) approximately $145 million to $165 million on growth capital expenditures and (2) approximately $55 million to $60 million on equipment maintenance capital expenditures. Exterran Holdings manages its and our respective U.S. fleets as one pool of compression equipment from which we can each readily fulfill our respective customers’ service needs. When we or Exterran Holdings are advised of a contract operations services opportunity, Exterran Holdings reviews both our and its fleet for an available and appropriate compressor unit. The majority of the idle compression equipment required for servicing these contract operations services has been and is currently held by Exterran Holdings. The owner of the equipment being transferred is required to pay the costs associated with making the idle equipment suitable for the proposed customer and then has generally leased the equipment to the recipient of the equipment or exchanged the equipment for other equipment of the recipient. Because Exterran Holdings has owned the majority of such equipment, Exterran Holdings has generally had to bear a larger portion of the maintenance capital expenditures associated with making transferred equipment ready for service. For equipment that is then leased, the maintenance capital cost is a component of the lease rate that is paid under the lease. As we acquire more compression equipment, we expect that more of our equipment will be available to satisfy our or Exterran Holdings’ customer requirements. As a result, we expect that our maintenance capital expenditures will continue to increase and that our lease expense will decrease.

 

In addition, our capital requirements include funding distributions to our unitholders. We anticipate such distributions will be funded through cash provided by operating activities and borrowings under our senior secured credit facility and that we will be able to generate cash or borrow adequate amounts of cash under our senior secured credit facility to meet our needs over the next twelve months. Given our objective of long-term growth through acquisitions, growth capital expenditure projects and other internal growth projects, we anticipate that over time we will continue to invest capital to grow and acquire assets. We expect to actively consider a variety of assets for potential acquisitions and growth projects. We expect to fund these future capital expenditures with borrowings under our senior secured credit facility and the issuance of additional debt and equity securities, as appropriate, given market conditions. The timing of future capital expenditures will be based on the economic environment, including the availability of debt and equity capital.

 

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Termination of Cost Caps.  Under the Omnibus Agreement, our obligation to reimburse Exterran Holdings for any cost of sales that it incurred in the operation of our business and any cash SG&A expense allocated to us was capped (after taking into account any such costs we incurred and paid directly) through December 31, 2014. We have been in the past dependent on our cost caps to generate sufficient cash from operating surplus to enable us to make cash distributions approximating our current distribution rate. The benefit received by us from the caps on operating and SG&A costs provided by Exterran Holdings was $13.9 million, $25.2 million and $24.8 million during the years ended December 31, 2014, 2013 and 2012, respectively. These cost caps were in effect through December 31, 2014; however, effective January 1, 2015, the cost caps provisions of the Omnibus Agreement terminated. Their termination could reduce the amount of cash flow available to unitholders and, accordingly, could impair our ability to maintain or increase our distributions.

 

Our Ability to Grow Depends on Our Ability to Access External Growth Capital.  We expect that we will rely primarily upon external financing sources, including our senior secured credit facility and the issuance of debt and equity securities, rather than cash reserves established by our general partner, to fund our acquisitions and growth capital expenditures. Our ability to access the capital markets may be restricted at a time when we would like, or need, to do so, which could have an impact on our ability to grow.

 

We expect that we will distribute all of our available cash to our unitholders. Available cash is reduced by cash reserves established by our general partner to provide for the proper conduct of our business, including future capital expenditures. To the extent we are unable to finance growth externally and we are unwilling to establish cash reserves to fund future acquisitions, our cash distribution policy will significantly impair our ability to grow. Because we distribute all of our available cash, we may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level, which in turn may impact the available cash that we have to distribute for each unit. There are no limitations in our partnership agreement or in the terms of our senior secured credit facility on our ability to issue additional units, including units ranking senior to our common units.

 

Long-Term Debt.  In November 2010, we amended and restated our Credit Agreement to provide for a five-year $550.0 million senior secured credit facility, consisting of a $400.0 million revolving credit facility and a $150.0 million term loan facility. The revolving borrowing capacity under this facility increased to $550.0 million in March 2011 and to $750.0 million in March 2012. We amended our Credit Agreement in March 2013 to reduce the borrowing capacity under our revolving credit facility to $650.0 million and extend the maturity date of the term loan and revolving credit facilities to May 2018. As of December 31, 2014, we had undrawn and available capacity of $190.0 million under our revolving credit facility.

 

The revolving credit and term loan facilities bear interest at a base rate or LIBOR, at our option, plus an applicable margin. Depending on our leverage ratio, the applicable margin for the revolving and term loans varies (i) in the case of LIBOR loans, from 2.0% to 3.0% and (ii) in the case of base rate loans, from 1.0% to 2.0%. The base rate is the highest of the prime rate announced by Wells Fargo Bank, National Association, the Federal Funds Effective Rate plus 0.5% and one-month LIBOR plus 1.0%. At December 31, 2014, all amounts outstanding under these facilities were LIBOR loans and the applicable margin was 2.5%. The weighted average annual interest rate on the outstanding balance under these facilities at December 31, 2014 and 2013, excluding the effect of interest rate swaps, was 2.7% and 2.2%, respectively. During the years ended December 31, 2014 and 2013, the average daily debt balance under these facilities was $438.5 million and $450.2 million, respectively.

 

Borrowings under the Credit Agreement are secured by substantially all of the U.S. personal property assets of us and our Significant Domestic Subsidiaries (as defined in the Credit Agreement), including all of the membership interests of our Domestic Subsidiaries (as defined in the Credit Agreement). As of December 31, 2014, subject to certain conditions, at our request, and with the approval of the lenders, the aggregate commitments under the Credit Agreement could be increased by up to an additional $300 million. In February 2015, we executed an amendment to our Credit Agreement, which among other things, increases the borrowing capacity under the revolving credit facility by $250.0 million to $900.0 million.

 

The Credit Agreement contains various covenants with which we must comply, including, but not limited to, restrictions on the use of proceeds from borrowings and limitations on our 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 Credit Agreement also contains various covenants requiring mandatory prepayments from the net cash proceeds of certain asset transfers. We must maintain various consolidated financial ratios, including a ratio of EBITDA (as defined in the Credit Agreement) to Total Interest Expense (as defined in the Credit Agreement) of not less than 2.75 to 1.0, a ratio of Total Debt (as defined in the 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

 

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closes) and a ratio of Senior Secured Debt (as defined in the 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, our 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, we 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 on our assets, liabilities, financial condition, business or operations that, taken as a whole, impacts our ability to perform our obligations under the Credit Agreement, could lead to a default under that agreement. A default under one of our debt agreements would trigger cross-default provisions under 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 the Credit Agreement.

 

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

 

Prior to April 1, 2017, we may redeem all or a part of the 2013 Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, we may redeem up to 35% of the aggregate principal amount of the 2013 Notes prior to April 1, 2016 with the net proceeds of one or more equity offerings at a redemption price of 106.000% of the principal amount of the 2013 Notes, plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the 2013 Notes issued under the indenture remains outstanding after such redemption and the redemption occurs within 180 days of the date of the closing of such equity offering. On or after April 1, 2017, we may redeem all or a part of the 2013 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.000% for the twelve-month period beginning on April 1, 2017, 101.500% for the twelve-month period beginning on April 1, 2018 and 100.000% for the twelve-month period beginning on April 1, 2019 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date of the 2013 Notes.

 

In April 2014, we issued $350.0 million aggregate principal amount of the 2014 Notes. We received net proceeds of $337.4 million, after original issuance discount and issuance costs, from this offering, which we used to fund a portion of the April 2014 MidCon Acquisition and repay borrowings under our revolving credit facility. The 2014 Notes were issued at an original issuance discount of $5.7 million, which is being amortized using the effective interest method at an interest rate of 6.25% over their term. In February 2015, holders of the 2014 Notes exchanged their 2014 Notes for registered notes with the same terms.

 

Prior to April 1, 2018, we may redeem all or a part of the 2014 Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date. In addition, we may redeem up to 35% of the aggregate principal amount of the 2014 Notes prior to April 1, 2017 with the net proceeds of one or more equity offerings at a redemption price of 106.000% of the principal amount of the 2014 Notes, plus any accrued and unpaid interest to the date of redemption, if at least 65% of the aggregate principal amount of the 2014 Notes issued under the indenture remains outstanding after such redemption and the redemption occurs within 180 days of the date of the closing of such equity offering. On or after April 1, 2018, we may redeem all or a part of the 2014 Notes at redemption prices (expressed as percentages of principal amount) equal to 103.000% for the twelve-month period beginning on April 1, 2018, 101.500% for the twelve-month period beginning on April 1, 2019 and 100.000% for the twelve-month period beginning on April 1, 2020 and at any time thereafter, plus accrued and unpaid interest, if any, to the applicable redemption date of the 2014 Notes.

 

The 2013 Notes and the 2014 Notes are guaranteed on a senior unsecured basis by all of our existing subsidiaries (other than EXLP Finance Corp., which is a co-issuer of the 2013 Notes and the 2014 Notes) and certain of our future subsidiaries. The 2013 Notes and the 2014 Notes and the guarantees, respectively, are our and the guarantors’ general unsecured senior obligations, rank equally in right of payment with all of our and the guarantors’ other senior obligations, and are effectively subordinated to all of our and the guarantors’ existing and future secured debt to the extent of the value of the collateral securing such indebtedness. In addition, the 2013 Notes and the 2014 Notes and guarantees are effectively subordinated to all existing and future indebtedness and other liabilities of any future non-guarantor subsidiaries. All of our subsidiaries are 100% owned, directly or indirectly, by us and guarantees by our subsidiaries are full and unconditional (subject to customary release provisions as discussed in Note 6 to the Financial Statements) and constitute joint and several obligations. We have no assets or operations independent of our subsidiaries, and there are no significant restrictions upon our subsidiaries’ ability to distribute funds to us.

 

We have entered into interest rate swap agreements to offset changes in expected cash flows due to fluctuations in the interest rates associated with our variable rate debt. At December 31, 2014, we were a party to interest rate swaps with a notional value of $400.0 million, pursuant to which we make fixed payments and receive floating payments. Our interest rate swaps expire over varying

 

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dates, with interest rate swaps having a notional amount of $300.0 million expiring in May 2018 and the remaining interest rate swaps having a notional amount of $100.0 million expiring in May 2019. As of December 31, 2014, the weighted average effective fixed interest rate on our interest rate swaps was 1.6%. See Part II, Item 7A (“Quantitative and Qualitative Disclosures About Market Risk”) of this report for further discussion of our interest rate swap agreements.

 

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

 

Sales of Partnership Units.  In April 2014, we sold, pursuant to a public underwritten offering, 6,210,000 common units, including 810,000 common units pursuant to an over-allotment option. We received net proceeds of $169.5 million, after deducting underwriting discounts, commissions and offering expenses, which we used to fund a portion of the April 2014 MidCon Acquisition. In connection with this sale and as permitted under our partnership agreement, we issued and sold approximately 126,000 general partner units to our general partner so it could maintain its approximate 2.0% general partner interest in us. We received net proceeds of $3.6 million from the general partner contribution which we used to repay borrowings outstanding under our revolving credit facility.

 

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

 

On January 29, 2015, our board of directors approved a cash distribution of $0.5575 per limited partner unit, or approximately $35.3 million, including distributions to our general partner on its incentive distribution rights. The distribution covers the period from October 1, 2014 through December 31, 2014. The record date for this distribution was February 9, 2015 and payment was made on February 13, 2015.

 

Pursuant to the Omnibus Agreement, our obligation to reimburse Exterran Holdings for cost of sales and SG&A expenses was capped through December 31, 2014 (see Note 3 to the Financial Statements). Our cost of sales exceeded the cap provided in the Omnibus Agreement by $2.5 million, $12.4 million and $16.6 million during the years ended December 31, 2014, 2013, and 2012, respectively. Our SG&A expenses exceeded the cap provided in the Omnibus Agreement by $11.4 million, $12.8 million and $8.2 million during the years ended December 31, 2014, 2013 and 2012, respectively. Accordingly, our EBITDA, as further adjusted, and our distributable cash flow (please see Part II, Item 6 (“Selected Financial Data — Non-GAAP Financial Measures”) of this report for a discussion of EBITDA, as further adjusted, and distributable cash flow) would have been approximately $13.9 million, $25.2 million and $24.8 million lower during the years ended December 31, 2014, 2013 and 2012, respectively, without the benefit of the cost caps. As a result, without the benefit of the cost caps, our distributable cash flow coverage (distributable cash flow for the period divided by distributions declared to all unitholders for the period, including incentive distribution rights) would have been 1.20x, 1.13x and 1.02x during the years ended December 31, 2014, 2013 and 2012, respectively, rather than the actual distributable cash flow coverage (which includes the benefit of cost caps) of 1.30x, 1.36x and 1.29x during the years ended December 31, 2014, 2013, and 2012, respectively. The cost caps provided in the Omnibus Agreement were in effect through December 31, 2014; however, effective January 1, 2015, these provisions of the Omnibus Agreement terminated.

 

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 Part I, Item 3 (“Legal Proceedings”) and Note 15 (“Commitments and Contingencies”) to the Financial Statements included in this report 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 $10.2 million during the year ended December 31, 2014. 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

 

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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, including our cash available for distribution and accordingly, could impair our ability to maintain or increase our distributions. If we had not received the $10.2 million of benefit from the new methodology during the year ended December 31, 2014, our distributable cash flow coverage without the benefit of cost caps would have been 1.12x.

 

Contractual Obligations.  The following table summarizes our cash contractual obligations as of December 31, 2014 (in thousands):

 

 

 

Payments Due by Period

 

 

 

Total

 

2015

 

2016-2017

 

2018-2019

 

Thereafter

 

Long-term debt(1)

 

 

 

 

 

 

 

 

 

 

 

Revolving credit facility due May 2018

 

$

460,000

 

$

 

$

 

$

460,000

 

$

 

Term loan facility due May 2018

 

150,000

 

 

 

150,000

 

 

6% senior notes due April 2021(2)

 

350,000

 

 

 

 

350,000

 

6% senior notes due October 2022(3)

 

350,000

 

 

 

 

350,000

 

Total long-term debt

 

1,310,000

 

 

 

610,000

 

700,000

 

Estimated interest payments(4)

 

371,855

 

65,103

 

130,207

 

92,545

 

84,000

 

Total contractual obligations

 

$

1,681,855

 

$

65,103

 

$

130,207

 

$

702,545

 

$

784,000

 

 


(1)                  Amounts represent the expected cash payments for principal on our debt and do not include any deferred issuance costs or fair market valuations of our debt. For more information on our long-term debt, see Note 6 to the Financial Statements.

 

(2)                 Amounts represent the full face value of the 2013 Notes and are not reduced by the unamortized discount of $4.5 million as of December 31, 2014.

 

(3)                 Amounts represent the full face value of the 2014 Notes and are not reduced by the unamortized discount of $5.2 million as of December 31, 2014.

 

(4)                  Interest amounts calculated using interest rates in effect as of December 31, 2014, including the effect of our interest rate swaps.

 

At December 31, 2014, $1.7 million of unrecognized tax benefits have been recorded as liabilities in accordance with the accounting standard for income taxes related to uncertain tax positions, and we are uncertain as to if or when such amounts may be settled. We have not recorded any liability for penalties and interest related to these unrecognized tax benefits.

 

Off-Balance Sheet Arrangements

 

We have no material off-balance sheet arrangements.

 

Effects of Inflation

 

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

 

Critical Accounting Estimates

 

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

 

Allowances and Reserves

 

We maintain allowances for doubtful accounts for estimated losses resulting from the inability of our customers to make required payments. The determination of the collectibility of amounts due from our customers requires us to use estimates and make judgments regarding future events and trends, including monitoring our customers’ payment history and current creditworthiness to determine that collectibility is reasonably assured, as well as consideration of the overall business climate in which our customers operate.

 

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Inherently, these uncertainties require us to make judgments and estimates regarding our customers’ ability to pay amounts due to us in order to determine the appropriate amount of valuation allowances required for doubtful accounts. We review the adequacy of our allowance for doubtful accounts quarterly. We determine the allowance needed based on historical write-off experience and by evaluating significant balances aged greater than 90 days individually for collectibility. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. During the years ended December 31, 2014 and 2012, we recorded bad debt expense of $1.1 million and $0.5 million, respectively. During the year ended December 31, 2013, we recorded a bad debt benefit of approximately $25,000.

 

Depreciation

 

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

 

Business Combinations and Goodwill

 

Goodwill and intangible assets acquired in connection with business combinations represent the excess of consideration over the fair value of tangible net assets acquired. Certain assumptions and estimates are employed in determining the fair value of assets acquired and liabilities assumed.

 

The carrying value of goodwill is reviewed annually or earlier if indicators of potential impairment exist. A qualitative assessment is performed to determine whether it is more likely than not that the fair value of the reporting unit is impaired. If it is more likely than not, we perform a goodwill impairment test. We determine the fair value of our reporting unit using both the expected present value of future cash flows and a market approach. Each approach is weighted 50% in determining our calculated fair value. The present value of future cash flows is estimated using our most recent forecast and the weighted average cost of capital. The market approach uses a market multiple on the reporting unit’s earnings before interest expense, income tax provision, depreciation and amortization expense. Significant estimates for the reporting unit included in our impairment analysis are our cash flow forecasts, our estimate of the market’s weighted average cost of capital and market multiples. Changes in forecasts, cost of capital and market multiples could affect the estimated fair value of our reporting unit and result in a goodwill impairment charge in a future period.

 

Long-Lived Assets

 

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

 

Income Taxes

 

As a partnership, all income, gains, losses, expenses, deductions and tax credits we generate generally flow through to our unitholders. However, some states impose an entity-level income tax on partnerships, including us. Our provision for income taxes, deferred tax liabilities and reserves for unrecognized tax benefits reflect management’s best assessment of estimated current and future taxes to be paid. Significant judgments and estimates are required in determining our provision for income taxes.

 

Deferred income taxes arise from temporary differences between the financial statements and tax basis of assets and liabilities. Changes in tax laws and rates could affect recorded deferred tax liabilities in the future. Management is not aware of any such changes that would have a material effect on our financial position, results of operations or ability to make cash distributions to our unitholders. The calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in various states.

 

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The accounting standard for income taxes provides that a tax benefit from an uncertain tax position may be recognized when it is more likely than not that the position will be sustained upon examination, including resolutions of any related appeals or litigation processes, on the basis of the technical merits. In addition, guidance is provided on measurement, derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. We adjust these liabilities when our judgment changes as a result of the evaluation of new information not previously available. Because of the complexity of some of these uncertainties, the ultimate resolution may result in a payment that is materially different from our current estimate of the tax liabilities. These differences will be reflected as increases or decreases to income tax expense in the period in which new information is available.

 

Contingencies

 

The impact of an uncertain tax position taken or expected to be taken on an income tax return must be recognized in the financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authority. We regularly assess and, if required, establish accruals for income tax and non-income based tax contingencies pursuant to the applicable accounting standards that could result from assessments of additional tax by taxing jurisdictions where we operate. Tax contingencies are subject to a significant amount of judgment and are reviewed and adjusted on a quarterly basis in light of changing facts and circumstances considering the outcome expected by management. As of December 31, 2014 and 2013, we had recorded approximately $1.8 million and $5.3 million (including penalties and interest), respectively, of accruals for tax contingencies. Of these amounts, $1.7 million and $0.6 million, respectively, are accrued for income taxes and $0.1 million and $4.7 million, respectively, are accrued for non-income based taxes. If our actual experience differs from the assumptions and estimates used for recording the liabilities, adjustments may be required and would be recorded in the period in which the difference becomes known.

 

Self-Insurance

 

Exterran Holdings insures our property and operations and allocates certain insurance costs to us. Exterran Holdings is self-insured up to certain levels for general liability, vehicle liability, group medical and workers’ compensation claims. We regularly review estimates of reported and unreported claims and provide for losses based on claims filed and an estimate for significant claims incurred but not reported. Although we believe the insurance costs allocated to us are adequate, it is reasonably possible our estimates of these liabilities will change over the near term as circumstances develop. Exterran Holdings currently has minimal insurance on our offshore assets.

 

Recent Accounting Pronouncements

 

See Note 14 to the Financial Statements.

 

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

 

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

 

As of December 31, 2014, after taking into consideration interest rate swaps, we had $210.0 million of outstanding indebtedness that was effectively subject to floating interest rates. A 1% increase in the effective interest rate on our outstanding debt subject to floating interest rates at December 31, 2014 would result in an annual increase in our interest expense of approximately $2.1 million.

 

For further information regarding our use of interest rate swap agreements to manage our exposure to interest rate fluctuations on a portion of our debt obligations, see Note 9 to the Financial Statements.

 

Item 8.  Financial Statements and Supplementary Data

 

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

 

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

 

None.

 

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Item 9A.  Controls and Procedures

 

Management’s Evaluation of Disclosure Controls and Procedures

 

As of the end of the period covered by this report, our principal executive officer and principal financial officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)), which are designed to provide reasonable assurance that we are able to record, process, summarize and report the information required to be disclosed in our reports under the Exchange Act within the time periods specified in the rules and forms of the Securities and Exchange Commission. Based on the evaluation, as of December 31, 2014, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective to provide reasonable assurance that the information required to be disclosed in reports that we file or submit under the Exchange Act is accumulated and communicated to management, and made known to our principal executive officer and principal financial officer, on a timely basis to ensure that it is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

 

Management’s Annual Report on Internal Control Over Financial Reporting

 

As required by Exchange Act Rules 13a-15(c) and 15d-15(c), our management, including the Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining adequate internal control over financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness as to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Based on the results of management’s evaluation described above, management concluded that our internal control over financial reporting was effective as of December 31, 2014.

 

The effectiveness of internal control over financial reporting as of December 31, 2014 was audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in its report found within this report.

 

Changes in Internal Control over Financial Reporting

 

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

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Partners of

Exterran Partners, L.P.

Houston, Texas

 

We have audited the internal control over financial reporting of Exterran Partners, L.P. and subsidiaries (the “Partnership”) as of December 31, 2014, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit.

 

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

 

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that 1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; 2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and 3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

 

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

 

In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

 

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2014 of the Partnership and our report dated February 26, 2015 expressed an unqualified opinion on those financial statements and financial statement schedule.

 

/s/ DELOITTE & TOUCHE LLP

 

Houston, Texas

February 26, 2015

 

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Item 9B.  Other Information

 

Fifth Amendment to Third Amended and Restated Omnibus Agreement

 

On February 23, 2015, we entered into a Fifth Amendment to Third Amended and Restated Omnibus Agreement (the “Omnibus Amendment”) with Exterran Holdings, Exterran Energy Solutions, L.P., Exterran GP LLC (“GP LLC”), Exterran General Partner, L.P. (“GP”) and EXLP Operating LLC. The Omnibus Agreement governs several relationships between us and Exterran Holdings, including:

 

·                  Certain agreements not to compete between us and our affiliates, on the one hand, and Exterran Holdings and its affiliates, on the other hand;

 

·                  Exterran Holdings’ obligation to provide all operational staff, corporate staff and support services reasonably necessary to run our business and our obligation to reimburse Exterran Holdings for the provision of such services;

 

·                  The terms under which we, Exterran Holdings and our respective affiliates may transfer, exchange or lease compression equipment;

 

·                  The terms under which we may purchase newly-fabricated compression equipment from Exterran Holdings;

 

·                  Exterran Holdings’ grant to us of a license to use certain intellectual property, including our logo; and

 

·                  Exterran Holdings’ obligation to indemnify us for certain liabilities, and our obligation to indemnify Exterran Holdings for certain liabilities.

 

The Omnibus Agreement, as amended, is hereby incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2014 and Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2014.

 

The Omnibus Amendment amends the Omnibus Agreement to, among other things, extend the terms of certain non-competition and equipment transfer provisions such that they will now terminate on December 31, 2015.

 

Each of the parties to the Omnibus Agreement, other than Exterran Holdings, is a direct or indirect subsidiary of Exterran Holdings. As a result, certain individuals, including officers of Exterran Holdings and officers and directors of GP LLC, serve as officers and/or directors of more than one of such entities. Also, Exterran Holdings holds an approximate 35% limited partner interest in us through its subsidiaries and an approximate 2% general partner interest and incentive distribution rights in us through its indirect ownership of GP, our general partner.

 

The Omnibus Amendment is filed as Exhibit 10.12 to this report and incorporated herein by reference.

 

PART III

 

ITEM 10.  Directors, Executive Officers and Corporate Governance

 

Board of Directors

 

Because our general partner is a limited partnership, its general partner, Exterran GP LLC, conducts our business and operations. Exterran GP LLC’s board of directors and officers, which we refer to as our board of directors and our officers, make decisions on our behalf. Our general partner is not elected by our unitholders and is not subject to re-election on a regular basis in the future. Unitholders are not entitled to elect the directors of Exterran GP LLC or directly or indirectly participate in our management or operation. As a result, we do not hold annual unitholder meetings. Our general partner owes a fiduciary duty to our unitholders. Our general partner is liable, as our sole general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly non-recourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are non-recourse to it.

 

NASDAQ does not require a listed limited partnership like us to have a majority of independent directors on our board of directors or to establish a compensation committee or a nominating committee. We have seven directors, three of whom — James G. Crump, G. Stephen Finley and Edmund P. Segner, III — have been determined by the board to be “independent directors” within the meaning of applicable NASDAQ rules and Rule 10A-3 of the Exchange Act. In determining the independence of each director, we have adopted standards that incorporate the NASDAQ and Exchange Act standards.

 

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Our board of directors has standing audit, compensation and conflicts committees. Each committee’s written charter is available on our website at www.exterran.com and without charge to any unitholder upon written request to Investor Relations, 16666 Northchase Drive, Houston, Texas 77060.

 

Our board of directors met eight times during 2014. During 2014, each director attended at least 75% of the aggregate number of meetings of the board of directors and any committee of the board of directors on which such director served.

 

Our directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of our directors or executive officers, and there are no arrangements or understandings between any of the directors or executive officers and any other persons pursuant to which a director or officer was selected as such.

 

Audit Committee.  The audit committee, which met four times during 2014, consists of Messrs. Crump (chair), Finley and Segner. The board of directors has determined that each of Messrs. Crump, Finley and Segner is an “audit committee financial expert” as defined in Item 407(d)(5)(ii) of SEC Regulation S-K, and that each is “independent” within the meaning of the applicable NASDAQ and Exchange Act rules regulating audit committee independence. The audit committee assists our board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and terms and pre-approve any non-audit services to be performed by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has unrestricted access to the audit committee.

 

Compensation Committee.  The compensation committee, which met seven times during 2014 and took action by unanimous written consent on one occasion, consists of Messrs. Crump, Finley (chair) and Segner. The compensation committee discharges the board of directors’ responsibilities relating to compensation of our executives and independent directors, reviews and approves the manner in which Exterran Holdings allocates to us its compensation expense applicable to our executives and oversees the development and implementation of our compensation programs. The compensation committee also, in accordance with the SEC’s rules and regulations, produces the compensation discussion and analysis included in Item 11 (“Executive Compensation”) of this report.

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