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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS

Table of Contents

As filed with the Securities and Exchange Commission on April 3, 2012

Registration No. 333-          

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



Form S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933



USA COMPRESSION PARTNERS, LP
(Exact name of Registrant as Specified in Its Charter)

Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
  4922
(Primary Standard Industrial
Classification Code Number)
  75-2771546
(I.R.S. Employer
Identification Number)

100 Congress Avenue, Suite 450
Austin, Texas 78701
(512) 473-2662

(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)

J. Gregory Holloway
Vice President, General and Secretary
100 Congress Avenue, Suite 450
Austin, Texas 78701
(512) 473-2662

(Name, address, including zip code, and telephone number, including area code, of agent for service)



Copies to:

Sean T. Wheeler
Keith Benson

Latham & Watkins LLP
811 Main Street, Suite 3700
Houston, Texas 77002
(713) 546-5400



         Approximate date of commencement of proposed sale to the public: As soon as practicable after the Registration Statement becomes effective.

         If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box.    ý

         If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

         If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

         If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.    o

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

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

CALCULATION OF REGISTRATION FEE

 
Title of Each Class of
Securities to be Registered

  Proposed Maximum
Aggregate
Offering Price(1)

  Amount of
Registration Fee

 

Common Units representing limited partner interests

  $75,000,000   $8,595

 

(1)
Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).


Table of Contents

The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell nor does it seek an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to Completion, dated April 3, 2012


PROSPECTUS

          LOGO

USA COMPRESSION PARTNERS, LP

Distribution Reinvestment Plan
                   Common Units

         With this prospectus, we are offering participation in our Distribution Reinvestment Plan (the "Plan") to owners of our common units. We have appointed Wells Fargo Shareowner Services, a division of Wells Fargo Bank, N.A., as the administrator of the Plan. The Plan provides a simple and convenient means of investing in our common units.

         Plan Highlights:

         Your participation in the Plan is voluntary, and you may terminate your account at any time.

         You should read carefully this prospectus before deciding to participate in the Plan. You should read the documents we have referred you to in the "Where You Can Find More Information" section of this prospectus for information on us and for our financial statements.

         Our common units are approved for listing (subject to official notice of issuance) on the New York Stock Exchange under the ticker symbol "USAC".

         Investing in our common units involves risks. Limited partnerships are inherently different from corporations. You should carefully consider the risk factors described under "Risk Factors" beginning on page 2 of this prospectus before enrolling in the Plan.

         These risks include the following:

         Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is                        , 2012.


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        [GRAPHIC]


Table of Contents

TABLE OF CONTENTS

 
  Page  

Summary

    1  
   

Overview

    1  

Risk Factors

   
2
 
   

Risks Relating to the Plan

    2  
   

Risks Related to Our Business

    2  
   

Risks Inherent in an Investment in Us

    12  
   

Tax Risks to Common Unitholders

    19  

The Plan

   
24
 
   

Plan Overview

    24  

Commonly Asked Questions

   
24
 

Use of Proceeds

   
31
 

Our Cash Distribution Policy and Restrictions on Distributions

   
32
 
   

General

    32  
   

Our Minimum Quarterly Distribution

    33  

Provisions of our Partnership Agreement Relating to Cash Distributions

   
35
 
   

Distributions of Available Cash

    35  
   

Operating Surplus and Capital Surplus

    36  
   

Capital Expenditures

    38  
   

Subordination Period

    39  
   

Distributions of Available Cash From Operating Surplus During the Subordination Period

    40  
   

Distributions of Available Cash From Operating Surplus After the Subordination Period

    41  
   

General Partner Interest and Incentive Distribution Rights

    41  
   

Percentage Allocations of Available Cash From Operating Surplus

    42  
   

General Partner's Right to Reset Incentive Distribution Levels

    42  
   

Distributions From Capital Surplus

    45  
   

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

    45  
   

Distributions of Cash Upon Liquidation

    46  

Selected Historical Financial and Operating Data

   
48
 

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

   
53
 
   

Overview

    53  
   

General Trends and Outlook

    53  
   

Factors That Affect Our Future Results

    54  
   

How We Evaluate Our Operations

    55  
   

Accounting Terminology and Principals

    57  
   

Operating Highlights

    58  
   

Financial Results of Operations

    61  
   

Effects of Inflation

    65  
   

Liquidity and Capital Resources

    65  
   

Off Balance Sheet Arrangements

    69  
   

Critical Accounting Policies and Estimates

    69  
   

Recent Accounting Pronouncements

    71  

Business

   
72
 
   

Overview

    72  
   

Business Strategies

    73  
   

Competitive Strengths

    74  
   

Our Operations

    75  

Management of USA Compression Partners, LP

   
84
 
   

Directors and Executive Officers

    85  

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  Page  
   

Reimbursement of Expenses of Our General Partner

    87  
   

Compensation Discussion and Analysis

    87  
   

Summary Compensation Table

    93  
   

Grants of Plan-Based Awards

    95  
   

Outstanding Equity Awards at December 31, 2011

    96  
   

Units Vested

    96  
   

Pension Benefits for 2011

    96  
   

Nonqualified Deferred Compensation

    97  
   

Potential Payments upon Termination or Change-in-Control

    97  
   

Director Compensation

    98  
   

2012 Long-Term Incentive Plan

    98  

Security Ownership of Certain Beneficial Owners and Management

   
101
 

Certain Relationships and Related Party Transactions

   
102
 
   

Distributions and Payments to Our General Partner and its Affiliates

    102  
   

Agreements Governing the Transactions

    103  
   

Relationship with Penn Virginia Resource Partners

    103  
   

Procedures for Review, Approval and Ratification of Related-Person Transactions

    104  

Conflicts of Interest and Fiduciary Duties

   
105
 
   

Conflicts of Interest

    105  
   

Fiduciary Duties

    110  

Description of the Common Units

   
113
 
   

The Units

    113  
   

Transfer Agent and Registrar

    113  
   

Transfer of Common Units

    113  

The Partnership Agreement

   
115
 
   

Organization and Duration

    115  
   

Purpose

    115  
   

Cash Distributions

    115  
   

Capital Contributions

    115  
   

Voting Rights

    116  
   

Applicable Law; Forum, Venue and Jurisdiction

    117  
   

Limited Liability

    118  
   

Issuance of Additional Partnership Interests

    119  
   

Amendment of the Partnership Agreement

    120  
   

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

    122  
   

Dissolution

    122  
   

Liquidation and Distribution of Proceeds

    123  
   

Withdrawal or Removal of Our General Partner

    123  
   

Registration Rights

    124  
   

Transfer of General Partner Interest

    125  
   

Transfer of Ownership Interests in the General Partner

    125  
   

Transfer of Incentive Distribution Rights

    125  
   

Change of Management Provisions

    125  
   

Limited Call Right

    126  
   

Non-Citizen Assignees; Redemption

    126  
   

Non-Taxpaying Assignees; Redemption

    126  
   

Meetings; Voting

    127  
   

Status as Limited Partner

    127  
   

Indemnification

    128  
   

Reimbursement of Expenses

    128  
   

Books and Reports

    128  
   

Right to Inspect Our Books and Records

    129  

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  Page  

Material Federal Income Tax Consequences

    130  
   

Partnership Status

    130  
   

Limited Partner Status

    132  
   

Tax Consequences of Unit Ownership

    132  
   

Tax Treatment of Operations

    138  
   

Disposition of Common Units

    140  
   

Uniformity of Units

    142  
   

Tax-Exempt Organizations and Other Investors

    143  
   

Administrative Matters

    144  
   

Recent Legislative Developments

    146  
   

State, Local, Foreign and Other Tax Considerations

    146  

Investment in USA Compression Partners, LP by Employee Benefit Plans

   
148
 

Plan of Distribution

   
150
 

Validity of the Common Units

   
150
 

Experts

   
150
 

Where You Can Find More Information

   
150
 

Forward-Looking Statements

   
151
 

Index to Financial Statements

   
F-1
 

Appendix A—Glossary of Terms

       

        You should rely only on the information contained in this prospectus, any free writing prospectus prepared by or on behalf of us or any other information to which we have referred you in connection with this offering. We have not authorized any other person to provide you with information different from that contained in this prospectus. Neither the delivery of this prospectus nor the sale of common units means that information contained in this prospectus is correct after the date of this prospectus. This prospectus is not an offer to sell or the solicitation of an offer to buy the common units in any circumstances under which the offer or solicitation is unlawful.

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SUMMARY

        This summary provides a brief overview of information contained elsewhere in this prospectus. This summary does not contain all of the information that you should consider before investing in our common units. You should read the entire prospectus carefully, including the historical financial statements and the notes to those financial statements included in this prospectus. You should read "Risk Factors" for more information about important risks that you should consider carefully before buying our common units. We include a glossary of some of the terms used in this prospectus as Appendix A.

        References in this prospectus to "USA Compression," "we," "our," "us," "the Partnership" or like terms refer to USA Compression Partners, LP and its wholly owned subsidiaries, including USA Compression Partners, LLC ("USAC Operating"). References to "USA Compression Holdings" refer to USA Compression Holdings, LLC, the owner of USA Compression GP, LLC, our general partner. References to "Riverstone" refer to Riverstone/Carlyle Global Energy and Power Fund IV, L.P., and affiliated entities, including Riverstone Holdings LLC.

Overview

        We are a growth-oriented Delaware limited partnership and, based on management's significant experience in the industry, we believe we are one of the largest independent providers of compression services in the U.S. in terms of available compression unit horsepower. We employ a customer-focused business philosophy in partnering with our diverse customer base, which is comprised of producers, processors, gatherers and transporters of natural gas. Natural gas compression, a mechanical process whereby natural gas is compressed to a smaller volume resulting in a higher pressure, is an essential part of the production and transportation of natural gas. As part of our services, we engineer, design, operate, service and repair our compression units and maintain related support inventory and equipment. The compression units in our modern fleet are designed to be easily adaptable to fit our customers' dynamic compression requirements. By focusing on the needs of our customers and by providing them with reliable and flexible compression services, we are able to develop long-term relationships, which lead to more stable cash flows for our unitholders. We have been providing compression services since 1998.

        We focus primarily on large-horsepower infrastructure applications. We utilize a modern fleet, with an average age of our compression units of four years. Our standard new-build compression unit is generally configured for multiple compression stages, allowing us to operate our units across a broad range of operating conditions. This flexibility allows us to enter into longer-term contracts and reduces the redeployment risk of our horsepower in the field. Our modern and standardized fleet, decentralized field-level operating structure and technical proficiency in predictive and preventive maintenance and overhaul operations have enabled us to achieve average service run times consistently above the levels required by our customers.

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RISK FACTORS

        Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in the compression services business. You should consider carefully the following risk factors together with all of the other information included in this prospectus in evaluating an investment in our common units.

        If any of the following risks were to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we may be unable to pay the minimum quarterly distribution to our unitholders, the trading price of our common units could decline and you could lose all or part of your investment.


Risks Relating to the Plan

        You will not know the price of the common units you are purchasing under the Plan at the time you authorize the investment or elect to have your distributions reinvested. The price of our common units may fluctuate between the time you decide to purchase common units under the Plan and the time of actual purchase. As a result, you may purchase common units at a price higher than the price you anticipated.

        If you instruct the administrator to sell common units under the Plan, you will not be able to direct the time or price at which your common units are sold. The price of our common units may decline between the time you decide to sell common units and the time of actual sale.

        If you decide to withdraw from the Plan and you request a certificate for common units credited to you under the Plan from the administrator, the market price of our common units may decline between the time you decide to withdraw and the time you receive the certificate.


Risks Related to Our Business

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 pay our minimum quarterly distributions to holders of our common units and subordinated units.

        In order to pay our minimum quarterly distribution of $            per unit per quarter, or $            per unit per year, we will require available cash of approximately $             million per quarter, or approximately $             million per year, based on the number of common units, subordinated units and general partner units to be outstanding immediately after completion of our initial public offering. Under our cash distribution policy, the amount of cash we can distribute to our unitholders principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

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

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        For a description of additional restrictions and factors that may affect our ability to make cash distributions, please read "Our Cash Distribution Policy and Restrictions on Distributions."

A long-term reduction in the demand for, or production of, natural gas or crude oil in the locations where we operate could adversely affect the demand for our services or the prices we charge for our services, which could result in a decrease in our revenues and cash available for distribution to our unitholders.

        The demand for our compression services depends upon the continued demand for, and production of, natural gas and crude oil. Demand may be affected by, among other factors, natural gas prices, crude oil prices, weather, availability of alternative energy sources, governmental regulation and general demand for energy. Any prolonged, substantial reduction in the demand for natural gas or crude oil would, in all likelihood, depress the level of production activity and result in a decline in the demand for our compression services, which would reduce our cash available for distribution. Lower natural gas prices or crude oil prices over the long-term could result in a decline in the production of natural gas or crude oil, respectively, resulting in reduced demand for our compression services. Additionally, production from unconventional natural gas sources, such as tight sands, shales and coalbeds, constitute an increasing percentage of our compression services business. Such sources can be less economically feasible to produce in low natural gas price environments, in part due to costs related to compression requirements, and a reduction in demand for natural gas or natural gas lift for crude oil may cause such sources of natural gas to be uneconomic to drill and produce, which could in turn negatively impact the demand for our services. In addition, governmental regulation and tax policy may impact the demand for natural gas or impact the economic feasibility of development of new natural gas fields or production of existing fields.

We have several key customers. The loss of any of these customers would result in a decrease in our revenues and cash available for distribution to our unitholders.

        We provide compression services under contracts with several key customers. The loss of one of these key customers may have a greater effect on our financial results than for a company with a more diverse customer base. Our largest customer for the years ended December 31, 2010 and 2011 was Southwestern Energy Company and its subsidiaries, or Southwestern. Southwestern accounted for 18.7% and 15.9% of our revenue for the years ended December 31, 2010, and 2011. Our ten largest customers accounted for 53% of our revenues for each of the years ended December 31, 2010, and 2011. The loss of all or even a portion of the compression services we provide to our key customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

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

        During times when the natural gas or oil markets weaken, our customers are more likely to experience financial difficulties and the lack of availability of debt or equity financing, which could

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result in a reduction in our customers' spending for our services. For example, our customers could seek to preserve capital by using lower cost providers, not renewing month-to-month contracts or determining not to enter into any new compression service contracts. Reduced demand for our services could adversely affect our business, results of operations, financial condition and cash flows. In addition, in the event of the financial failure of a customer, we could experience a loss of all or a portion of our outstanding accounts receivable associated with that customer.

We face significant competition that may cause us to lose market share and reduce our ability to make distributions to our unitholders.

        The compression business is highly competitive. Some of our competitors have a broader geographic scope, as well as greater financial and other resources than we do. 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 and our customers. 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 be unable to compete effectively. Some of these competitors may expand or construct newer, more powerful or more flexible compression fleets that would create additional competition for us. Additionally, there are lower barriers to entry for customers as competitors seeking to purchase individual compression units. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and reduce our ability to make cash distributions to our unitholders.

Our customers may choose to vertically integrate their operations by purchasing and operating their own compression fleet, or expanding the amount of compression units they currently own.

        Our customers that are significant producers, processors, gatherers and transporters of natural gas and crude oil may choose to vertically integrate their operations by purchasing and operating their own compression fleets in lieu of using our compression services. Currently, the availability of attractive financing terms from financial institutions and equipment manufacturers facilitates this possibility by making the purchase of individual compression units increasingly affordable to our customers. Such vertical integration or increases in vertical integration could result in decreased demand for our compression services, which may have a material adverse effect on our business, results of operations, financial condition and reduce our ability to make cash distributions to our unitholders.

We may be unable to grow our cash flows if we are unable to expand our business, which could limit our ability to increase distributions to our unitholders.

        A principal focus of our strategy is to continue to grow the per unit distribution on our units by expanding our business. Our future growth will depend upon a number of factors, some of which we cannot control. These factors include our ability to:

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        If we do not achieve our expected growth, we may not be able to achieve our estimated results and, as a result, we may not be able to pay the aggregate minimum quarterly distribution on our common units and subordinated units and general partner units, in which event the market price of our common units will likely decline materially.

We may be unable to grow successfully through future acquisitions, and we may not be able to integrate effectively the businesses we may acquire, which may impact our operations and limit our ability to increase distributions to our unitholders.

        From time to time, we may choose to make business acquisitions to pursue market opportunities, increase our existing capabilities and expand into new areas of operations. While we have reviewed acquisition opportunities in the past and will continue to do so in the future, we have not actively pursued any acquisitions, and in the future we may not be able to identify attractive acquisition opportunities or successfully acquire identified targets. In addition, we may not be successful in integrating any future acquisitions into our existing operations, which may result in unforeseen operational difficulties or diminished financial performance or require a disproportionate amount of our management's attention. Even if we are successful in integrating future acquisitions into our existing operations, we may not derive the benefits, such as operational or administrative synergies, that we expected from such acquisitions, which may result in the commitment of our capital resources without the expected returns on such capital. Furthermore, competition for acquisition opportunities may escalate, increasing our cost of making acquisitions or causing us to refrain from making acquisitions. Our inability to make acquisitions, or to integrate successfully future acquisitions into our existing operations, may adversely impact our operations and limit our ability to increase distributions to our unitholders.

Our ability to grow in the future is dependent on our ability to access external expansion capital.

        We will distribute all of our available cash after expenses and prudent operating reserves to our unitholders. We expect that we will rely primarily upon external financing sources, including borrowings under our revolving credit facility and the issuance of debt and equity securities, to fund expansion capital expenditures. However, we may not be able to obtain equity or debt financing on terms favorable to us, or at all. To the extent we are unable to efficiently finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, 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 other expansion 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. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of borrowings or other debt by us to finance our growth strategy would result in interest expense, which in turn would affect the available cash that we have to distribute to our unitholders.

Our ability to manage and grow our business effectively may be adversely affected if we lose management or operational personnel.

        We depend on the continuing efforts of our executive officers. The departure of any of our executive officers, and in particular, Eric D. Long, President and Chief Executive Officer of our general partner, could have a significant negative effect on our business, operating results, financial condition and on our ability to compete effectively in the marketplace.

        Additionally, our ability to hire, train and retain qualified personnel will continue to be important and will become more challenging as we grow and if energy industry market conditions continue to be positive. When general industry conditions are good, the competition for experienced operational and

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field technicians increases as other energy and manufacturing companies' needs for the same personnel increases. Our ability to grow or even to continue our current level of service to our current customers will be adversely impacted if we are unable to successfully hire, train and retain these important personnel.

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

        The substantial majority of the components for our natural gas compression equipment are supplied by Caterpillar (for engines), Air-X-Changers and Air Cooled Exchangers (for coolers), and Ariel Corporation (for compressor frames and cylinders). Our reliance on these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply of required components in a timely manner. We also rely primarily on two vendors, A G Equipment Company and Standard Equipment Corp., to package and assemble our compression units. We do not have long-term contracts with these suppliers or packagers, and a partial or complete loss of any of these sources could have a negative impact on our results of operations and could damage our customer relationships. Some of these suppliers manufacture the components we purchase in a single facility, and any damage to that facility could lead to significant delays in delivery of completed units. In addition, since we expect any increase in component prices for compression equipment or packaging costs will be passed on to us, a significant increase in their pricing could have a negative impact on our results of operations.

We are subject to substantial environmental regulation, and changes in these regulations could increase our costs or liabilities.

        We are subject to stringent and complex federal, state and local laws and regulations, including laws and regulations regarding the discharge of materials into the environment, emission controls and other environmental protection and occupational health and safety concerns. 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 or 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 conduct operations in a wide variety of locations across the continental U.S. These operations require U.S. federal, state or local environmental permits or other authorizations. We may need to apply for or amend facility permits or licenses from time to time with respect to storm water discharges, waste handling, or air emissions relating to equipment operations, which subjects us to new or revised permitting conditions that may be onerous or costly to comply with. Additionally, the operation of compression units may 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 wide variety of locations 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

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certain requirements existing in various permits or other authorizations. We could be subject to penalties for any noncompliance 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 compression services or inactive compression unit 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 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.

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

        On August 20, 2010, the U.S. Environmental Protection Agency, or the EPA, published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocating internal combustion engines. All engines subject to these regulations are required to comply by October 2013. The rule will require us to undertake certain expenditures and activities, including purchasing and installing emissions control equipment on a portion of our engines located at major sources of hazardous air pollutants and on all our engines over a certain size regardless of location, following prescribed maintenance practices for engines (which are consistent with our existing practices), and implementing additional emissions testing and monitoring. On January 5, 2011, the EPA approved a request by industry groups for reconsideration of the monitoring issues and on March 9, 2011, the EPA issued a new proposed rule and a direct final rule effective on May 9, 2011 to clarify compliance requirements related to operation and maintenance procedures for continuous parametric monitoring systems. We do not believe the costs associated with achieving compliance with these standards by the October 2013 compliance date will be material.

        On June 28, 2011, the EPA issued a final rule modifying existing regulations under the CAA that established new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines. The final rule will require us to undertake certain expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment on some of our natural gas compression fleet. Compliance with the final rule is not required until at least 2013. We are currently evaluating the impact that this final rule will have on our operations.

        On July 28, 2011, the EPA proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA's proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds ("VOCs") and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The proposed rules also would establish specific new requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. The EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on the rules by April 3, 2012. If finalized, these rules could require a number of modifications to our operations including the installation of new equipment to control emissions from our compressors. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

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

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

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

        Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases, or GHGs. In recent years, the U.S. Congress has considered legislation to reduce emissions of GHGs. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues. In addition, almost half of the states have begun to address GHG emissions, primarily through the planned development of emission inventories or regional GHG cap and trade programs. Depending on the particular program, we could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations.

        Independent of Congress, the EPA is beginning to adopt regulations controlling GHG emissions under its existing Clean Air Act authority. For example, on December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. In 2009, the EPA adopted rules regarding regulation of GHG emissions from motor vehicles. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions in the United States beginning in 2011 for emissions occurring in 2010 from specified large GHG emission sources. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule for petroleum and natural gas facilities, including natural gas transmission compression facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year. The rule, which went into effect on December 30, 2010, requires reporting of GHG emissions by such regulated facilities to the EPA by September 2012 for emissions during 2011 and annually thereafter. In 2010, the EPA also issued a final rule, known as the "Tailoring Rule," that makes certain large stationary sources and modification projects subject to permitting requirements for GHG emissions under the Clean Air Act. This new permitting program may affect some of our customers' largest new or modified facilities going forward. Several of the EPA's GHG rules are being challenged in court and, depending on the outcome of these proceedings, such rules may be modified or rescinded or the EPA could develop new rules.

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        Although it is not currently possible to predict how any such proposed or future GHG legislation or regulation by Congress, the states or multi-state regions will impact our business, any legislation or regulation of GHG emissions that may be imposed in areas in which we conduct business could result in increased compliance costs, additional operating restrictions or reduced demand for our services, and could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which could adversely impact our revenue.

        A portion of our customers' natural gas production is from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. Legislation to amend the Safe Drinking Water Act, or SDWA, to repeal the exemption for hydraulic fracturing from the definition of "underground injection" and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the Safe Drinking Water Act. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a multi-year study of the potential environmental impacts of hydraulic fracturing, the results of which are anticipated to be available by the end of 2012. EPA also has recently announced that it believes hydraulic fracturing using fluids containing diesel fuel can be regulated under the SDWA notwithstanding the SDWA's general exemption for hydraulic fracturing. Several states have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. We cannot predict whether any such legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of natural gas that move through our gathering systems, which would materially adversely affect our revenue and results of operations.

We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.

        Our operations are subject to inherent risks such as equipment defects, malfunction and failures, and natural disasters that can result in uncontrollable flows of gas or well fluids, fires and explosions. These risks could expose us to substantial liability for personal injury, death, property damage, pollution and other environmental damages. Our insurance may be inadequate to cover our liabilities. Further, insurance covering the risks we 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 adversely affected. Please read "Our Operations—Environmental and Safety Regulations" for a description of how we are subject to federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of human health and environment.

Our debt levels may limit our flexibility in obtaining additional financing, pursuing other business opportunities and paying distributions.

        We have a $500 million revolving credit facility that matures on October 5, 2015. In addition, we have the option to increase the amount of available borrowings under the revolving credit facility by $50 million, subject to receipt of lender commitments and satisfaction of other conditions.

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        Our ability to incur additional debt is subject to limitations in our revolving credit facility. Our level of debt could have important consequences to us, including the following:

        Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service our debt under the revolving credit facility will depend on market interest rates, since we anticipate that the interest rates applicable to our borrowings will fluctuate with movements in interest rate markets. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt, or seeking additional equity capital. We may be unable to effect any of these actions on satisfactory terms, or at all.

Restrictions in our revolving credit facility may limit our ability to make distributions to our unitholders and may limit our ability to capitalize on acquisition and other business opportunities.

        The operating and financial restrictions and covenants in our revolving credit facility and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. For example, our revolving credit facility restricts or limits our ability to:

        Furthermore, our revolving credit facility contains certain operating and financial covenants. Our ability to comply with the covenants and restrictions contained in the revolving credit facility may be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our revolving credit facility, a significant portion of our indebtedness may become immediately due and payable, our lenders' commitment to make further loans to us may terminate, and we will be prohibited from making distributions to our unitholders. We might not have, or be able to obtain, sufficient funds to make these

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accelerated payments. Any subsequent replacement of our revolving credit facility or any new indebtedness could have similar or greater restrictions. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Description of Revolving Credit Facility."

An impairment of goodwill or other intangible assets could reduce our earnings.

        We have recorded approximately $157.1 million of goodwill and $84.6 million of other intangible assets as of December 31, 2011. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. GAAP requires us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Any event that causes a reduction in demand for our services could result in a reduction of our estimates of future cash flows and growth rates in our business. These events could cause us to record impairments of goodwill or other intangible assets. If we determine that any of our goodwill or other intangible assets are impaired, we will be required to take an immediate charge to earnings with a corresponding reduction of partners' capital resulting in an increase in balance sheet leverage as measured by debt to total capitalization. There was no impairment recorded for goodwill or other intangible assets for the years ended December 31, 2010 or 2011.

Terrorist attacks, the threat of terrorist attacks, hostilities in the Middle East, or other sustained military campaigns may adversely impact our results of operations.

        The long-term impact of terrorist attacks, such as the attacks that occurred on September 11, 2001, and the magnitude of the threat of future terrorist attacks on the energy industry in general and on us in particular are not known at this time. Uncertainty surrounding hostilities in the Middle East or other sustained military campaigns may affect our operations in unpredictable ways, including disruptions of natural gas supplies and markets for natural gas and natural gas liquids and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurance markets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital.

If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.

        Prior to our initial public offering, we were not required to file reports with the SEC. Upon the completion of our initial public offering, we became subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. We prepare our consolidated financial statements in accordance with GAAP, but our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future. Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm's, conclusions about the effectiveness of our internal controls. Ineffective internal controls will subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

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Risks Inherent in an Investment in Us

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

        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 have no right on an annual or ongoing basis to elect our general partner or its board of directors. USA Compression Holdings is the sole member of our general partner and has the right to appoint our general partner's entire board of directors, including our independent directors. 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. 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 limiting the unitholders' ability to influence the manner or direction of management.

USA Compression Holdings owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including USA Compression Holdings, have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of us and our common unitholders.

        USA Compression Holdings, which is principally owned and controlled by Riverstone, owns and controls our general partner and will appoint all of the officers and directors of our general partner, some of whom will also be officers and directors of USA Compression Holdings. Although our general partner has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner in a manner that is beneficial to its owners. Conflicts of interest will arise between USA Compression Holdings, Riverstone and 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 USA Compression Holdings and the other owners of USA Compression Holdings over our interests and the interests of our common unitholders. These conflicts include the following situations, among others:

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        Please read "Conflicts of Interest and Fiduciary Duties."

Our general partner intends to limit its liability regarding our obligations.

        Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner's fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

        We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

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        In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion 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. There are no limitations in our partnership agreement or our revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

Our partnership agreement limits our general partner's fiduciary duties to holders of our common and subordinated units.

        Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. 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, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

        By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisions discussed above. Please read "Conflicts of Interest and Fiduciary Duties—Fiduciary Duties."

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without USA Compression Holdings' consent.

        The unitholders initially will be unable to remove our general partner 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 662/3% of all outstanding common and subordinated units voting together as a single class is required to remove our general partner. As of                    , USA Compression Holdings owns an aggregate of            % of our outstanding common and subordinated units. Also, if our general partner is removed without cause during the subordination period and no units held by the holders of the subordinated units or their affiliates are voted in favor of that removal, all subordinated units held by our general partner and its affiliates will automatically be converted into common units. If no units held by any holder of subordinated units or its affiliates are voted in favor of that removal, all subordinated units will convert automatically into common units and any existing arrearages on the common units will be extinguished. A removal of our general partner under these circumstances would adversely affect our common units by prematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable for actual

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fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business.

Our partnership agreement 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 restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:

        In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the board of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in subclauses (c) and (d) above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

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Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of its board of directors or the holders of our common units. This could result in lower distributions to holders of our common units.

        Our general partner has the right, at any time when there are no subordinated units outstanding and it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

        If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and general partner units. The number of common units to be issued to our general partner will equal the number of common units which would have entitled the holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner's general partner interest in us (currently 2.0%) will be maintained at the percentage that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels. Please read "Provisions of our Partnership Agreement Relating to Cash Distributions—General Partner's Right to Reset Incentive Distribution Levels."

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

        Unitholders' voting rights are further restricted by a provision of our partnership agreement 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, their direct transferees and their indirect transferees approved by our general partner (which approval may be granted in its sole discretion) and persons who acquired such units with the prior approval of our general partner, cannot vote on any matter.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

        Our general partner 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 USA Compression Holdings to transfer all or a portion of its ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.

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An increase in interest rates may cause the market price of our common units to decline.

        Like all equity investments, an investment in our common units is subject to certain risks. In exchange for accepting these risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return by purchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments generally, including yield-based equity investments such as publicly traded partnership interests. Reduced demand for our common units resulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline.

We may issue additional units without your approval, which would dilute your 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 by us of additional common units or other equity securities of equal or senior rank will have the following effects:

USA Compression Holdings may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

        USA Compression Holdings holds an aggregate of                    common units and                    subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. Additionally, we have agreed to provide USA Compression Holdings with certain registration rights. Please read "The Partnership Agreement—Registration Rights." The sale of these 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.

Our general partner has a call right that may require you to sell your 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, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return or a negative return on your investment. You may also incur a tax liability upon a sale of your units. USA Compression Holdings owns an aggregate of approximately         % of our outstanding common units. At the end of the subordination period (which could occur as early as December 31, 2012), assuming no additional issuances of common units (other than upon the conversion of the subordinated units), USA Compression Holdings will own an aggregate of approximately        % of our outstanding common units. For additional information about this right, please read "The Partnership Agreement—Limited Call Right."

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Your 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. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:

        For a discussion of the implications of the limitations of liability on a unitholder, please read "The Partnership Agreement—Limited Liability."

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 (the "Delaware Act"), we may not make a distribution to you 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 an 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 both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

The price of our common units may fluctuate significantly, and you could lose all or part of your investment.

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

        If the above factors or other factors cause the market price of our units to fluctuate, the value of the units purchased in this offering may decline and you could lose some or all of your investment.

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The New York Stock Exchange, or NYSE, does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

        Our common units are approved for listing (subject to official notice of issuance) on the NYSE. Because we will be a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner's board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read "Management of USA Compression Partners, LP."

We will incur increased costs as a result of being a publicly traded partnership.

        As a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, the Sarbanes-Oxley Act of 2002 and related rules subsequently implemented by the SEC and the NYSE have required changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs beyond historical levels and to make activities more time-consuming and costly. For example, as a result of being a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded partnership reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and result in our general partner possibly having to accept reduced policy limits and coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers. However, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.


Tax Risks to Common Unitholders

        In addition to reading the following risk factors, please read "Material Federal Income Tax Consequences" for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service, or IRS, were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.

        The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

        Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are or will be so treated, a change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

        If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed

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upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

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

        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. For example, we are required to pay Texas franchise tax each year at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. Imposition of any similar taxes by any other state may substantially reduce the cash available for distribution to our unitholders and, therefore, 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 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.

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 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, judicial interpretations of the U.S. federal income tax laws may have a direct or indirect impact on our status as a partnership and, in some instances, a court's conclusions may heighten the risk of a challenge regarding our status as a partnership. Moreover, members of the U.S. Congress have recently considered substantive changes to the existing federal income tax laws that would have affected the tax treatment of certain publicly traded partnerships. 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 be applied retroactively and 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 entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

Our unitholders' share of our income is taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

        Because a unitholder is treated as a partner to whom we allocate taxable income that could be different in amount than the cash we distribute, a unitholder's allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if it receives no cash distributions from us. Our 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.

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If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

        We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take, and the IRS's positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take. A court may not agree with some or all of our counsel's conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

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

        If our unitholders sell common units, they will recognize a gain or loss for federal income tax purposes 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 a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale of common units, 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, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss" for a further discussion of the foregoing.

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 (known as 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 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 at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor before investing in our common units.

We will treat each purchaser of 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.

        Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt 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 you. Our counsel is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit

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adjustments to your tax returns. Please read "Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election" for a further discussion of the effect of the depreciation and amortization positions we will adopt.

We prorate our items of income, gain, loss and deduction for federal income tax purposes 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, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

        We will prorate our items of income, gain, loss and deduction for federal income tax purposes 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, and, accordingly, our counsel is unable to opine as to the validity of this method. Recently, however, the U.S. Treasury Department issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees."

A unitholder whose common units are loaned to a "short seller" to effect a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

        Because a unitholder whose common units are loaned to a "short seller" to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our counsel has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units; therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

We will adopt certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

        When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and our general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible

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assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

        A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable 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 federal income tax purposes.

        We will be considered to have technically terminated for 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 interest will be counted only once. Our technical 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 (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could 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 fiscal 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. A technical termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for such 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 IRS has recently announced a publicly traded partnership technical termination relief program whereby a publicly traded partnership that technically terminated may request publicly traded partnership technical termination relief which, if granted by the IRS, among other things would permit the partnership to provide only one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Constructive Termination" for a discussion of the consequences of our termination for federal income tax purposes.

As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

        In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We initially expect to conduct business in seventeen states. Many of these states currently impose a personal income tax on individuals. Many of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to file all foreign, federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units.

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THE PLAN

Plan Overview

        The Plan offers a simple and convenient way for owners of our common units to invest all or a portion of their cash distributions in our common units. The Plan is designed for long-term investors who wish to invest and build their common unit ownership over time. Unlike an individual brokerage account, the timing of purchases is subject to the provisions of the Plan. The principal terms and conditions of the Plan are summarized in this prospectus under "Commonly Asked Questions" below.

        We have appointed Wells Fargo Shareowner Services, a division of Wells Fargo Bank, N.A., or "the Administrator," to administer the Plan, and certain administrative support will be provided to the Administrator by its designated affiliates. Together, the Administrator and its affiliates will purchase and hold common units for Plan participants, keep records, send statements and perform other duties required by the Plan.

        Only registered holders of our common units can participate directly in the Plan. If you are a beneficial owner of common units in a brokerage account and wish to reinvest your distributions, you can make arrangements with your broker or nominee to participate in the Plan on your behalf, or you can request that your common units become registered in your name.

        Please read this entire prospectus for a more detailed description of the Plan. If you are a registered holder of our common units and would like to participate in the Plan, you can enroll online by following the enrollment procedures specified on the Administrator's website at www.shareowneronline.com or by completing and signing an authorization form and returning it to the Administrator. Authorization forms may be obtained at any time by written request, by contacting the Administrator at the address and telephone number provided in Question 6, or via the Internet at the Administrator's website at www.shareowneronline.com.


COMMONLY ASKED QUESTIONS

1.     How can I participate in the Plan?

        If you are a current holder of record, or registered holder, of our common units, you may participate directly in the Plan. If you own common units that are registered in someone else's name (for example, a bank, broker or trustee), the Plan allows you to participate through such person, should they elect to participate, without having to withdraw your common units from such bank, broker or trustee. If your broker or bank elects not to participate in the Plan on your behalf, you can participate by withdrawing your common units from such bank or broker and registering your common units in your name.

2.     How do I get started?

        If you are a registered holder of our common units, once you have read this prospectus, you can get started by enrolling in the Plan online by following the enrollment procedures specified on the Administrator's website at www.shareowneronline.com or by completing and signing an authorization form (see Question 6) and returning it to the Administrator. Your participation will begin promptly after your authorization is received. Once you have enrolled, your participation continues automatically, as long as you wish. If you own common units that are registered in someone else's name (for example a bank, broker or trustee), then you should contact such person to arrange for them to participate in the Plan on your behalf.

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3.     How are distributions reinvested?

        By enrolling in the Plan, you direct the Administrator to apply distributions to the purchase of additional common units in accordance with the terms and conditions of the Plan. You may elect to reinvest all or a portion of your distributions in additional common units. The Administrator will invest distributions in whole and fractional common units on the quarterly distribution payment date (the investment date). No interest will be paid on funds held by the Administrator pending investment.

        If the Administrator receives your authorization form on or before the record date for the payment of the next distribution, the amount of the distribution that you elect to be reinvested will be invested in additional common units for your Plan account. If the authorization form is received in the period after any distribution record date, that distribution will be paid in cash and your initial distribution reinvestment will commence with the following distribution.

        You may change your distribution reinvestment election at any time online via www.shareowneronline.com, by telephone or by notifying the Administrator in writing. To be effective with respect to a particular distribution, any such change must be received by the Administrator on or before the record date for that distribution.

4.     When are distributions reinvested?

        The investment date will be the distribution payment date for each quarter (generally, on or around the 15th calendar day of February, May, August and November). The record date for eligibility to receive distributions generally will be approximately one week before the date upon which distributions are paid. In the unlikely event that, due to unusual market conditions, the Administrator is unable to invest the funds within 30 days of the distribution payment date, the Administrator will return the funds to you by check or by automatic deposit to a bank account that you designate. No interest will be paid on funds held by the Administrator pending investment.

5.     What is the source and price of common units purchased under the Plan?

        We have the sole discretion to determine whether common units purchased under the Plan will come from our authorized but unissued common units or from common units purchased on the open market by the Administrator. We currently intend to use our authorized but unissued common units for all common units to be purchased under the Plan.

        The price for authorized but unissued common units purchased with reinvested distributions will be the average of the high and low trading prices of the common units on the New York Stock Exchange—Composite Transactions for the five trading days immediately preceding the investment date, less a discount ranging from 0% to 5%. The discount is initially set at         %; therefore, the initial purchase price for authorized but unissued common units purchased with reinvested distributions will be        % of such average trading price. (Note: If you participate in the Plan through your broker, you should consult with your broker to determine if your broker will charge you a service fee.)

        The purchase price for common units purchased with reinvested distributions on the open market will be the weighted average price of all common units purchased for the Plan for the respective investment date, less a discount ranging from 0% to 5%. (Note: If you participate in the Plan through your broker, you should consult with your broker to determine if your broker will charge you a service fee.)

        We will provide notice to you of any changes in the discount rate at least 30 days prior to the following record date.

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6.     Who is the Administrator of the Plan?

        Wells Fargo Shareowner Services, a division of Wells Fargo Bank, N.A., is the Administrator of the Plan. Certain administrative support will be provided to the Administrator by its designated affiliates.

        All correspondence regarding the Plan should be addressed to:

        Plan Requests should be mailed to:

        Certified/Overnight Mail:

        General Information:

        An automated voice response system is available 24 hours a day, 7 days a week. Customer Service Representatives are available from 7:00 a.m. to 7:00 p.m., Central Standard Time, Monday through Friday, by pressing "0" at any time during the automated menu.

        Internet:

        Please include a reference to USA Compression Partners, LP and this Plan in all correspondence.

7.     What are the transaction costs of participating in the Plan?

        Participants do not pay purchase commissions for units purchased by the Plan, regardless of whether the units are purchased from us or are purchased on the open market.

        If a participant requests to sell units through the Plan, the participant will pay any related administrative fees, brokerage commissions, and applicable taxes.

        At the present time there is no service charge for participating in the Plan. However, we can change the fee structure for the Plan at any time. We will notify participants of any fee changes prior to the changes becoming effective.

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        We will pay many of the administrative costs of the Plan. The participant pays the following fees indicated below:

Certificate Issuance   Company paid
Certificate Deposit   Company paid
Investment Fees    
  Distribution reinvestment service fee   Company paid
  Optional cash investment service fee   Company paid
  Automatic withdrawal service fee   Company paid
  Purchase commission   Company paid
Sales Fees    
  Service fee   $15.00 per transaction
  Sales commission   $0.12 per unit
  Direct deposit of net sales proceeds   $5.00 per transaction
Fee for Returned Checks or Rejected Automatic Bank Withdrawals   $35.00 per item
Prior Year Duplicate Statements   $25.00 per year

8.     How many common units will be purchased for my account?

        If you are a registered holder of our common units and are directly participating in the Plan, the number of common units, including fractional common units, purchased under the Plan will depend on the amount of your cash distribution you elect to reinvest and the price of the common units determined as provided above. Common units purchased under the Plan, including fractional common units, will be credited to your account. Both whole and fractional common units will be purchased. Fractional common units will be computed to three decimal places.

        If you are a beneficial owner and are participating in the Plan through your broker, you should contact your broker for the details of how the number of common units you purchase will be determined.

        This prospectus relates to            of our common units registered for sale under the Plan. We cannot assure you that there will be sufficient units subject to the Plan for all distributions you elect to have reinvested in the Plan. Any distributions received by the Administrator but not invested in our common units under the Plan will be returned to participants without interest.

9.     What are the tax consequences of purchasing common units under the Plan?

        For tax purposes, you will be treated as if you first received the full cash distribution on your common units that participate in the Plan and then purchased additional common units with the portion of such cash distributions that is subject to the Plan. As a result, your adjusted basis for tax purposes in your common units will be reduced by the full amount of the deemed cash distribution and then increased by the amount of the distributions reinvested in additional common units pursuant to the Plan. We intend to take the position that participants in the Plan do not recognize income upon the purchase of common units at a discounted purchase price under the Plan. There is a risk that the IRS could assert that you must recognize income in the amount of the discount if you purchase common units at a discounted purchase price under the Plan, or that we will determine in the future that it is necessary to allocate income to you in the amount of the discount in order to preserve the uniformity of our units.

        Purchasing common units pursuant to the Plan will not affect the tax obligations associated with the common units you currently own. Participation in the Plan will reduce the amount of cash distributions available to you to satisfy any tax obligations associated with owning common units. Please

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read "Material Federal Income Tax Consequences" for information relevant to holders of common units generally.

10.   How can I withdraw from the Plan?

        If you are a registered holder of our common units, you may discontinue the reinvestment of your distributions at any time by providing notice to the Administrator. In addition, you may change your distribution election online under the Administrator's account management service, as described above. To be effective for a particular distribution payment, the Administrator must receive notice three days prior to the record date for that distribution to be paid out in cash. In addition, you may request that all or part of your common units be sold. When your common units are sold through the Administrator, you will receive the proceeds less a service fee of $15.00 per transaction and any brokerage trading fees, currently $0.12 per unit.

        If you are a beneficial owner of our common units and you are participating in the Plan through your broker, you should direct your broker to discontinue participation in the Plan on your behalf.

        Generally, an owner of common units may again become a participant in the Plan. However, we reserve the right to reject the enrollment of a previous participant in the Plan on grounds of excessive joining and termination. This reservation is intended to minimize administrative expense and to encourage use of the Plan as a long-term investment service.

11.   How will my common units be held under the Plan?

        If you are a registered holder of our common units and you are directly participating in the Plan, the common units that you acquire under the Plan will be maintained in your Plan account in non-certificated form for safekeeping. Safekeeping protects your common units against physical loss, theft or accidental destruction and also provides a convenient way for you to keep track of your common units. Only common units held in safekeeping may be sold through the Plan.

        If you own common units in certificated form, you may deposit your certificates for those common units that you own and that are registered in your name for safekeeping under the Plan with the Administrator at no cost. The Administrator will credit the common units represented by the certificates to your account in "book-entry" form and will combine the common units with any whole and fractional units then held in your plan account. In addition to protecting against the loss, theft or destruction of your certificates, this service is convenient if and when you sell common units through the Plan. Because you bear the risk of loss in sending certificates to the Administrator, you should send certificates by registered mail, return receipt requested, and properly insured to the address specified in Question 6 above.

        No certificates will be issued to you for common units in the Plan unless you submit a written request to the Administrator or until your participation in the Plan is terminated. At any time, you may request the Administrator to send a certificate for some or all of the common units credited to your account. This request should be mailed to the Administrator at the address set forth in the answer to Question 6 or made via www.shareowneronline.com. There is no fee for this service. Any remaining whole common units and any fraction of a common unit will remain credited to your plan account. Certificates for fractional common units will not be issued under any circumstances.

        If you are a beneficial owner of our common units and you are participating in the Plan through your broker, the common units that are purchased on your behalf under the Plan will be maintained in your account with your broker.

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12.   How do I sell common units held under the Plan?

        If you are a registered holder of our common units and you are directly participating in the Plan, you can sell your Plan common units at any time by contacting the Administrator. Your sale request will be processed, and your common units will, subject to market conditions and other facts, generally be sold within 24 hours of receipt and processing of your request. Please note that the Administrator cannot and does not guarantee the actual sale date or price, nor can it stop or cancel any outstanding sale or issuance requests. All requests are final. The Administrator will mail a check to you (less applicable sales fees) on the settlement date, which is typically three trading days after your common units have been sold. Please allow an additional five to seven business days from the settlement date to receive your check.

        Alternatively, you may choose to withdraw your common units from your Plan account and sell them through a broker of your choice, in which case you would have to request that the Administrator electronically transfer your common units to the broker through the Direct Registration System. Or, you may request a certificate for your common units from the Administrator for delivery to your broker prior to such sale.

        If you are a beneficial owner of our common units and you are participating in the Plan through your broker, you should contact your broker to sell your common units.

13.   How will I keep track of my investments?

        If you are a registered holder of our common units and you are directly participating in the Plan, the Administrator will send you a transaction notice confirming the details of each transaction that you make and a quarterly statement of your account.

        If you are a beneficial owner of our common units and you are participating in the Plan through your broker, the details of the reinvestment transactions will be maintained by your broker. You should contact your broker to determine how this information will be provided to you.

14.   Can the Plan be suspended, modified or terminated?

        We reserve the right to suspend, modify or terminate the Plan at any time. Participants will be notified of any suspension, modification or termination of the Plan. If you are a registered holder of our common units and you are directly participating in the Plan, upon our termination of the Plan, a certificate will be issued to you for the number of whole common units in your account. Any fractional common unit in your Plan account will be converted to cash and remitted to you by check.

15.   What would be the effect of any unit splits, unit distributions or other distributions?

        Any common units we distribute as a distribution on common units (including fractional common units) that are credited to your account under the Plan, or upon any split of such common units, will be fully credited to your account. In the event of a rights offering, your entitlement will be based upon your total holdings, including those credited to your account under the Plan. Rights applicable to common units credited to your account under the Plan will be sold by the Administrator and the proceeds will be credited to your account under the Plan and applied to the purchase of common units on the next investment date.

        If you want to exercise, transfer or sell any portion of the rights applicable to the common units credited to your account under the Plan, you must request, at least two days prior to the record date for the issuance of any such rights, that a portion of the common units credited to your account be transferred from your account and registered in your name. Transaction processing may either be curtailed or suspended until the completion of any stock dividend, unit split or other corporate action.

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Responsibilities Under the Plan

        We, the Administrator and any agent will not be liable in administering the Plan for any act done in good faith, or for any omission to act in good faith with regards to purchasing and/or selling common units for participants and, including, without limitation, any claim of liability arising out of failure to terminate a participant's account upon that participant's death prior to the receipt of notice in writing of such death. Since we have delegated all responsibility for administering the Plan to the Administrator, we specifically disclaim any responsibility for any of its actions or inactions in connection with the administration of the Plan.

        You should recognize that neither we, the Administrator, nor any agent can assure you of a profit or protect you against an economic loss on common units purchased under the Plan.

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USE OF PROCEEDS

        We do not know either the number of common units that will be purchased under the Plan or the prices at which common units will be sold to participants. In connection with purchases of authorized but unissued common units under the Plan, our general partner is entitled, but not obligated, to make a capital contribution in order to maintain its percentage general partner interest in us, which is currently 2.0%. The net proceeds we realize from sales of our common units pursuant to the Plan, including our general partner's proportionate capital contribution, if any, will be used for general partnership purposes, including the repayment of debt and the purchase and maintenance of compression units.

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OUR CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

General

        Rationale for our cash distribution policy.    Our partnership agreement requires us to distribute all of our available cash quarterly. Our cash distribution policy reflects a judgment that our unitholders will be better served by our distributing rather than retaining our available cash. Generally, our available cash is our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case were we subject to federal income tax.

        Limitations on cash distributions and our ability to change our cash distribution policy.    There is no guarantee that our unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay the minimum quarterly distribution or any other distribution except as provided in our partnership agreement. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including the following:

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        Our ability to grow is dependent on our ability to access external expansion capital.    Our partnership agreement requires us to distribute all of our available cash to our unitholders. As a result, we expect that we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. To the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion 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. There are no limitations in our partnership agreement or our revolving credit facility on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.


Our Minimum Quarterly Distribution

        The board of directors of our general partner has established a minimum quarterly distribution of $          per unit per complete quarter, or $          per unit per year, to be paid no later than 45 days after the end of each fiscal quarter beginning with the quarter ending                  . This equates to an aggregate cash distribution of approximately $           million per quarter, or approximately $           million per year, based on the number of common and subordinated units and the 2.0% general partner interest to be outstanding as of            , 2012. Our ability to make cash distributions equal to the minimum quarterly distribution pursuant to this policy will be subject to the factors described above under the caption "—General—Limitations on Cash Distributions and Our Ability to Change Our Distribution Policy."

        Initially, our general partner will be entitled to 2.0% of all distributions that we make prior to our liquidation. In the future, our general partner's initial 2.0% interest in these distributions may be reduced if we issue additional units and our general partner does not contribute a proportionate amount of capital to us to maintain its initial 2.0% general partner interest.

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        The subordination period generally will end if we have earned and paid at least $            on each outstanding common unit and subordinated unit and the corresponding distribution on our general partner's 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or after December 31, 2014. If, in respect of any quarter, we have earned and paid at least $            (150.0% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and the corresponding distribution on our general partner's 2.0% interest and the related distribution on the incentive distributions rights for the four-quarter period immediately preceding that date, the subordination period will terminate automatically and all of the subordinated units will convert into an equal number of common units. Please read the "Provisions of our Partnership Agreement Relating to Cash Distributions—Subordination Period."

        If we do not pay the minimum quarterly distribution on our common units, our common unitholders will not be entitled to receive such payments in the future except during the subordination period. To the extent we have available cash in any future quarter during the subordination period in excess of the amount necessary to pay the minimum quarterly distribution to holders of our common units, we will use this excess available cash to pay any distribution arrearages related to prior quarters before any cash distribution is made to holders of subordinated units. Our subordinated units will not accrue arrearages for unpaid quarterly distributions or quarterly distributions less than the minimum quarterly distribution. Please read "Provisions of our Partnership Agreement Relating to Cash Distributions—Subordination Period."

        The requirement to distribute available cash quarterly, as provided in our partnership agreement, may not be modified or repealed without amending our partnership agreement. The actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business and the amount of reserves our general partner establishes in accordance with our partnership agreement as described above. We will pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about the 1st of each such month. If the distribution date does not fall on a business day, we will make the distribution on the business day immediately preceding the indicated distribution date. We will adjust the quarterly distribution for the period from the closing of our initial public offering on                            , 2012 through                                  .

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PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

        Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.


Distributions of Available Cash

        General.    Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending                     , we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the minimum quarterly distribution for the period from the closing of our initial public offering on            , 2012 through                    .

        Definition of available cash.    Available cash, for any quarter, consists of all cash on hand at the end of that quarter:

Working capital borrowings are borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months from sources other than additional working capital borrowings.

        Intent to distribute the minimum quarterly distribution.    We intend to distribute to the holders of common and subordinated units on a quarterly basis at least the minimum quarterly distribution of $          per unit, or $          on an annualized basis, to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner and its affiliates. However, there is no guarantee that we will pay the minimum quarterly distribution 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.

        General partner interest and incentive distribution rights.    Initially, our general partner will be entitled to 2.0% of all quarterly distributions that we make after inception and prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. Our general partner's initial 2.0% interest in our distributions may be reduced if we issue additional limited partner units in the future (other than the issuance of common units upon exercise by the underwriters of our initial public offering of their option to purchase additional common units, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest.

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        Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from operating surplus (as defined below) in excess of $          per unit per quarter. The maximum distribution of 50.0% includes distributions paid to our general partner on its 2.0% general partner interest and assumes that our general partner maintains its general partner interest at 2.0%. The maximum distribution of 50.0% does not include any distributions that our general partner may receive on limited partner units that it owns.


Operating Surplus and Capital Surplus

        General.    All cash distributed will be characterized as either "operating surplus" or "capital surplus." Our partnership agreement requires that we distribute available cash from operating surplus differently than available cash from capital surplus.

        Operating surplus.    Operating surplus for any period consists of:

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        As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by our operations. For example, it includes a basket of $             million that will enable us, if we choose, to distribute as operating surplus cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

        The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures, as described below, and thus reduce operating surplus when made. However, if a working capital borrowing is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will be excluded from operating expenditures because operating surplus will have been previously reduced by the deemed repayment.

        We define operating expenditures in the partnership agreement, and it generally means all of our cash expenditures, including, but not limited to, taxes, reimbursement of expenses to our general partner and its affiliates, payments made under interest rate hedge agreements or commodity hedge contracts (provided that (i) with respect to amounts paid in connection with the initial purchase of an interest rate hedge contract or a commodity hedge contract, such amounts will be amortized over the life of the applicable interest rate hedge contract or commodity hedge contract and (ii) payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its stipulated settlement or termination date will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract), officer compensation, repayment of working capital borrowings, debt service payments and maintenance capital expenditures, provided that operating expenditures will not include:

        Capital surplus.    Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, capital surplus would generally be generated by:

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        Characterization of cash distributions.    Our partnership agreement requires that we treat all available cash distributed as coming from operating surplus until the sum of all available cash distributed since the closing of our initial public offering equals the operating surplus from the closing of our initial public offering through the end of the quarter immediately preceding that distribution. Our partnership agreement requires that we treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. We do not anticipate that we will make any distributions from capital surplus.


Capital Expenditures

        Maintenance capital expenditures are those capital expenditures required to maintain our long-term operating capacity and/or operating income. Capital expenditures made solely for investment purposes will not be considered maintenance capital expenditures.

        Expansion capital expenditures are those capital expenditures that we expect will increase our operating capacity or operating income over the long term. Expansion capital expenditures will also include interest (and related fees) on debt incurred to finance all or any portion of the construction of such capital improvement in respect of the period that commences when we enter into a binding obligation to commence construction of a capital improvement and ending on the earlier to occur of the date any such capital improvement commences commercial service and the date that it is abandoned or disposed of. Capital expenditures made solely for investment purposes will not be considered expansion capital expenditures.

        Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely will consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of facilities that are in excess of the maintenance of our existing operating capacity or operating income, but which are not expected to expand, for more than the short term, our operating capacity or operating income.

        As described above, neither investment capital expenditures nor expansion capital expenditures will be included in operating expenditures, and thus will not reduce operating surplus. Because expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of the construction or improvement of a capital asset (such as gathering compressors) in respect of the period that begins when we enter into a binding obligation to commence construction of the capital asset and ending on the earlier to occur of the date the capital asset commences commercial service or the date that it is abandoned or disposed of, such interest payments are also not subtracted from operating surplus. Losses on disposition of an investment capital expenditure will reduce operating surplus when realized and cash receipts from an investment capital expenditure will be treated as a cash receipt for purposes of calculating operating surplus only to the extent the cash receipt is a return on principal.

        Capital expenditures that are made in part for maintenance capital purposes, investment capital purposes and/or expansion capital purposes will be allocated as maintenance capital expenditures, investment capital expenditures or expansion capital expenditure by our general partner.

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Subordination Period

        General.    Our partnership agreement provides that, during the subordination period (which we describe below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $      per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed "subordinated" because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the common units.

        Subordination period.    Except as described below, the subordination period will begin on the closing date of our initial public offering and expire on the first business day after the distribution to unitholders in respect of any quarter, beginning with the quarter ending December 31, 2014, if each of the following has occurred:

        Early termination of subordination period.    Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day after the distribution to unitholders in respect of any quarter, if each of the following has occurred:

        Expiration upon removal of the general partner.    In addition, if the unitholders remove our general partner other than for cause:

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        Expiration of the subordination period.    When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will then participate pro-rata with the other common units in distributions of available cash.

        Adjusted operating surplus.    Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus for any period consists of:


Distributions of Available Cash From Operating Surplus During the Subordination Period

        Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

        The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity interests.

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Distributions of Available Cash From Operating Surplus After the Subordination Period

        Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

        The preceding discussion is based on the assumptions that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity interests.


General Partner Interest and Incentive Distribution Rights

        Our partnership agreement provides that our general partner initially will be entitled to 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 2.0% general partner interest if we issue additional units. Our general partner's 2.0% interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future (other than the issuance of common units upon exercise by the underwriters of our initial public offering of their option to purchase additional common units, the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the incentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2.0% general partner interest. Our partnership agreement does not require that the general partner fund its capital contribution with cash and our general partner may fund its capital contribution by the contribution to us of common units or other property.

        Incentive distribution rights represent the right to receive an increasing percentage (13.0%, 23.0% and 48.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in the partnership agreement.

        The following discussion assumes that our general partner maintains its 2.0% general partner interest, that there are no arrearages on common units and that our general partner continues to own the incentive distribution rights.

        If for any quarter:

then, our partnership agreement requires that we distribute any additional available cash from operating surplus for that quarter among the unitholders and the general partner in the following manner:

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Percentage Allocations of Available Cash From Operating Surplus

        The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under "Marginal percentage interest in distributions" are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total quarterly distribution per unit." The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 2.0% general partner interest, assume our general partner has contributed any additional capital to maintain its 2.0% general partner interest and has not transferred its incentive distribution rights and there are no arrearages on common units.

 
   
  Marginal percentage interest
in distributions
 
 
  Total quarterly
distribution per unit
  Unitholders   General partner  

Minimum Quarterly Distribution

  $     98.0 %   2.0 %

First Target Distribution

  up to $     98.0 %   2.0 %

Second Target Distribution

  above $    up to $     85.0 %   15.0 %

Third Target Distribution

  above $    up to $     75.0 %   25.0 %

Thereafter

  above $     50.0 %   50.0 %


General Partner's Right to Reset Incentive Distribution Levels

        Our general partner, as the holder of our incentive distribution rights, or IDRs, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial cash target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments to our general partner would be set. Our general partner's right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the conflicts committee of our general partner, at any time when there are no subordinated units outstanding and we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the prior four consecutive fiscal quarters. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event are above the reset first target distribution described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

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        In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target cash distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units based on a predetermined formula described below that takes into account the "cash parity" value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters prior to the reset event as compared to the average cash distributions per common unit during this period. Our general partner will be issued the number of general partner units necessary to maintain its percentage general partner interest in us immediately prior to the reset election.

        The number of common units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the amount of cash distributed per common unit during each of these two quarters.

        Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the "reset minimum quarterly distribution") and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

        The following table illustrates the percentage allocation of available cash from operating surplus between the unitholders and our general partner at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the closing of our initial public offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $            .

 
   
  Marginal percentage interest
in distribution
   
 
   
  Quarterly distribution
per unit following

 
  Quarterly distribution
   
  General partner
 
  per unit prior to reset   Unitholders   hypothetical reset

Minimum Quarterly Distribution

  $     98.0 %   2.0 % $         

First Target Distribution

  up to $     98.0 %   2.0 % up to $    (1)

Second Target Distribution

  above $    up to $     85.0 %   15.0 % above $    (1) up to $    (2)

Third Target Distribution

  above $    up to $     75.0 %   25.0 % above $    (2) up to $    (3)

Thereafter

  above $     50.0 %   50.0 % above $    (3)

(1)
This amount is 115.0% of the hypothetical reset minimum quarterly distribution.

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(2)
This amount is 125.0% of the hypothetical reset minimum quarterly distribution.

(3)
This amount is 150.0% of the hypothetical reset minimum quarterly distribution.

        The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of IDRs, based on an average of the amounts distributed for a quarter for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be            common units outstanding, our general partner has maintained its 2.0% general partner interest, and the average distribution to each common unit would be $            for the two quarters prior to the reset.

 
   
   
  Cash distributions to general
partner prior to reset
   
 
 
   
  Cash
distributions
to common
unitholders
prior to reset
   
 
 
  Quarterly
distribution
per unit
prior to reset
   
 
 
  Common
Units
  2.0% general
partner
interest
  Incentive
distribution
rights
  Total   Total
distributions
 

Minimum Quarterly Distribution

  $   $     $   $     $   $     $    

First Target Distribution

  above $    up to $                                  

Second Target Distribution

  above $    up to $                                    

Third Target Distribution

  above $    up to $                                    

Thereafter

  above $                                    
                               

      $     $   $     $     $     $    
                               

        The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner, including in respect of IDRs, with respect to the quarter in which the reset occurs. The table reflects that as a result of the reset there would be            common units outstanding, our general partner's 2.0% interest has been maintained, and the average distribution to each common unit would be $            . The number of common units to be issued to our general partner upon the reset was calculated by dividing (i) the average of the amounts received by our general partner in respect of its IDRs for the two quarters prior to the reset as shown in the table above, or $            , by (ii) the average available cash distributed on each common unit for the two quarters prior to the reset as shown in the table above, or $            .

 
   
   
  Cash distributions to general
partner after reset
   
 
 
   
  Cash
distributions
to common
unitholders
prior to reset
   
 
 
  Quarterly
distribution
per unit
prior to reset
  Common
Units issued in
connection
with reset
  2.0% general
partner
interest
  Incentive
distribution
rights
  Total   Total
distributions
 

Minimum Quarterly Distribution

  $   $     $     $     $   $     $    

First Target Distribution

  up to $                          

Second Target Distribution

  above $    up to $                          

Third Target Distribution

  above $    up to $                          

Thereafter

  above $                                

      $     $     $     $     $     $    
                               

        Our general partner is entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the prior four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.

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Distributions From Capital Surplus

        How distributions from capital surplus will be made.    Our partnership agreement requires that we make distributions of available cash from capital surplus, if any, in the following manner:

        The preceding paragraph assumes that our general partner maintains its 2.0% general partner interest and that we do not issue additional classes of equity securities.

        Effect of a distribution from capital surplus.    Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price, which is a return of capital. Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the distribution had in relation to the fair market value of the common units prior to the announcement of the distribution. Because distributions of capital surplus will reduce the minimum quarterly distribution and target distribution levels after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the minimum quarterly distribution is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

        If we reduce the minimum quarterly distribution to zero, all future distributions will be made such that 50.0% will be paid to the holders of units and 50.0% to our general partner. The percentage interests shown for our general partner include its 2.0% general partner interest and assume our general partner has not transferred the incentive distribution rights.


Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

        In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, our partnership agreement specifies that the following items will be proportionately adjusted:

        For example, if a two-for-one split of the units should occur, the minimum quarterly distribution, the target distribution levels and the initial unit price would each be reduced to 50.0% of its initial level. If we combine our common units into a lesser number of units or subdivide our common units into a greater number of units, we will combine or subdivide our subordinated units using the same ratio applied to the common units. Our partnership agreement provides that we do not make any adjustment by reason of the issuance of additional units for cash or property.

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        In addition, if as a result of a change in law or interpretation thereof, we or any of our subsidiaries is treated as an association taxable as a corporation or is otherwise subject to additional taxation as an entity for U.S. federal, state, local or non-U.S. income or withholding tax purposes, our general partner may, in its sole discretion, reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (after deducting our general partner's estimate of our additional aggregate liability for the quarter for such income and withholdings taxes payable by reason of such change in law or interpretation) and the denominator of which is the sum of (i) available cash for that quarter, plus (ii) our general partner's estimate of our additional aggregate liability for the quarter for such income and withholding taxes payable by reason of such change in law or interpretation thereof. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in distributions with respect to subsequent quarters.


Distributions of Cash Upon Liquidation

        General.    If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

        The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be cash available for distribution to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of our general partner.

        Manner of adjustments for gain.    The manner of the adjustment for gain is set forth in the partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to the partners in the following manner:

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        The percentage interests set forth above for our general partner include its 2.0% general partner interest and assume our general partner has not transferred the incentive distribution rights.

        If the liquidation occurs after the end of the subordination period, the distinction between common and subordinated units will disappear, so that clause (iii) of the second bullet point above and all of the third bullet point above will no longer be applicable.

        Manner of adjustments for losses.    If our liquidation occurs before the end of the subordination period, we will generally allocate any loss to our general partner and the unitholders in the following manner:

        If the liquidation occurs after the end of the subordination period, the distinction between common and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

        Adjustments to capital accounts.    Our partnership agreement requires that we make adjustments to capital accounts upon the issuance of additional units. In this regard, our partnership agreement specifies that we allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, our partnership agreement requires that we allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the general partner's capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

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SELECTED HISTORICAL FINANCIAL AND OPERATING DATA

        The following table presents our selected historical financial and operating data for the periods and as of the dates presented. The following table should be read together with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the historical financial statements and accompanying notes included elsewhere in this prospectus.

        The selected historical financial and operating data has been prepared on the following basis:

        We were acquired by USA Compression Holdings on December 23, 2010, which we refer to as the Holdings Acquisition. In connection with this acquisition, our assets and liabilities were adjusted to fair value on the closing date by application of "push-down" accounting. Due to these adjustments, our unaudited condensed consolidated financial statements are presented in two distinct periods to indicate the application of two different bases of accounting between the periods presented: (i) the periods prior to the acquisition date for accounting purposes, using a date of convenience of December 31, 2010, are identified as "Predecessor," and (ii) the periods from December 31, 2010 forward are identified as "Successor." Please read note 1 to our audited financial statements as of December 31, 2011 included elsewhere in this prospectus.

        The following table includes the non-GAAP financial measure of Adjusted EBITDA. We define Adjusted EBITDA as our net income before interest expense, income taxes, depreciation expense, impairment of compression equipment, share-based compensation expense, restructuring charges, management fees, expenses under our operating lease with Caterpillar and certain fees and expenses related to the Holdings Acquisition. For a reconciliation of Adjusted EBITDA to its most directly

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comparable financial measures calculated and presented in accordance with GAAP, please read "—Non-GAAP Financial Measures."

 
  Predecessor  

  Successor(1)  
 
  Year ended December 31,  

  Year
Ended
December 31,
2011
 
 
  2007   2008   2009    
  2010    
 
 
  (in thousands, except per unit and operating data)
 

Revenues:

                                       
 

Contract operations

  $ 67,339   $ 87,905   $ 93,178       $ 89,785       $ 93,896  
 

Parts and service

    2,296     2,918     2,050         2,243         4,824  
                               
 

Total revenues

    69,635     90,823     95,228         92,028         98,720  

Costs and expenses:

                                       
 

Cost of operations, exclusive of depreciation and amortization

    20,513     29,320     30,096         33,292         39,605  
 

Selling, general and administrative

    10,958     8,709     9,136         11,370         12,726  
 

Restructuring charges(2)

                            300  
 

Depreciation and amortization

    13,437     18,016     22,957         24,569         32,738  
 

(Gain) loss of sale of assets

    (3 )   (235 )   (74 )       (90 )       178  
 

Impairment of compression equipment

    1,028         1,677                  
                               
 

Total costs and expenses

    45,933     55,810     63,792         69,141         85,547  
                               

Operating income

    23,702     35,013     31,436         22,887         13,173  

Other income (expense):

                                       
 

Interest expense

    (16,468 )   (14,003 )   (10,043 )       (12,279 )       (12,970 )
 

Other

    43     20     25         26         21  
                               
 

Total other expense

    (16,425 )   (13,983 )   (10,018 )       (12,253 )       (12,949 )
                               

Income before income tax expense

    7,277     21,030     21,418         10,634         224  
                               

Income tax expense(3)

    155     119     190         155         155  
                               

Net income

  $ 7,122   $ 20,911   $ 21,228       $ 10,479       $ 69  
                               
 

Adjusted EBITDA

 
$

40,562
 
$

53,274
 
$

56,917
     
$

51,987
     
$

51,285
 

Net income per limited partner unit:

                                       
 

Common unit

                                       
 

Subordinated unit

                                       

Other Financial Data:

                                       
 

Capital expenditures

  $ 63,010   $ 92,708   $ 29,580       $ 18,886       $ 133,264  
 

Cash flows provided by (used in):

                                       
   

Operating activities

    26,441     40,699     42,945         38,572         33,782  
   

Investing activities

    (62,642 )   (88,102 )   (26,763 )       (18,768 )       (140,444 )
   

Financing activities

    37,591     46,364     (16,545 )       (19,804 )       106,662  

Operating Data (at period end, except averages)—unaudited

                                       
 

Fleet horsepower(4)

    453,508     542,899     582,530         609,730         722,201  
 

Total available horsepower(5)

    476,698     568,359     582,530         612,410         809,418  
 

Revenue generating horsepower(6)

    405,807     496,606     502,177         533,692         649,285  
 

Average revenue generating horsepower(7)

    370,826     455,673     489,243         516,703         570,900  
 

Revenue generating compression units

    613     763     749         795         888  
 

Average horsepower per revenue generating compression unit(8)

    665     651     655         667         692  
 

Horsepower utilization(9):

                                       
   

At period end

    93.7 %   95.2 %   92.0 %       91.8 %       95.7 %
   

Average for the period(10)

    93.9 %   95.9 %   92.7 %       92.6 %       92.3 %

 


 

Predecessor

 

 


 

Successor(1)

 

Balance Sheet Data (at period end):

                                       
 

Working capital(11)

  $ (2,794 ) $ (7,656 ) $ (4,678 )     $ (3,984 )     $ (11,295 )
 

Total assets

    276,983     349,645     352,757         614,718         727,876  
 

Long-term debt

    229,861     276,537     260,470         255,491         363,773  
 

Partners' capital

    32,795     49,685     72,626         338,954         339,023  

(1)
Reflects the push-down of the purchase accounting for the Holdings Acquisition.

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(2)
During the year ended December 31, 2011, we incurred $0.3 million of restructuring charges for severance and retention benefits related to the termination of certain administrative employees. These charges are reflected as restructuring charges in our consolidated statement of operations. We expect to pay these restructuring charges in 2012.

(3)
This represents the Texas franchise tax (applicable to income apportioned to Texas) which, in accordance with ASC 740, is classified as income tax for reporting purposes.

(4)
Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes any units on order). As of December 31, 2011, we had 171,245 of additional new compression unit horsepower on order, of which 61,134 horsepower is expected to be delivered between January 2012 and March 2012, 82,443 horsepower is expected to be delivered between April 2012 and June 2012, and 27,668 horsepower is expected to be delivered between July 2012 and September 2012.

(5)
Total available horsepower is revenue generating horsepower under contract for which we are billing a customer, horsepower in our fleet that is under contract but is not yet generating revenue, horsepower not yet in our fleet that is under contract not yet generating revenue that is subject to a purchase order and idle horsepower. Total available horsepower excludes new horsepower on order for which we do not have a compression services contract.

(6)
Revenue generating horsepower is horsepower under contract for which we are billing a customer.

(7)
Calculated as the average of the month-end revenue generating horsepower for each of the months in the period.

(8)
Calculated as the average of the month-end horsepower per revenue generating compression unit for each of the months in the period.

(9)
Horsepower utilization is calculated as (i)(a) revenue generating horsepower plus (b) horsepower in our fleet that is under contract, but is not yet generating revenue plus (c) horsepower not yet in our fleet that is under contract not yet generating revenue and that is subject to a purchase order, divided by (ii) total available horsepower less idle horsepower that is under repair. Horsepower utilization based on revenue generating horsepower and fleet horsepower at each applicable period end was 89.5%, 91.5%, 86.2%, 87.5% and 89.9% for the years ended December 31, 2007, 2008, 2009, 2010 and 2011, respectively.

(10)
Calculated as the average utilization for the months in the period based on utilization at the end of each month in the period.

(11)
Working capital is defined as current assets minus current liabilities.


Non-GAAP Financial Measures

        We include in this prospectus the non-GAAP financial measure of Adjusted EBITDA. We view Adjusted EBITDA as one of our primary management tools, and we track this item on a monthly basis both as an absolute amount and as a percentage of revenue compared to the prior month, year-to-date and prior year and to budget. We define Adjusted EBITDA as our net income before interest expense, income taxes, depreciation expense, impairment of compression equipment, share-based compensation expense, restructuring charges, management fees, expenses under our operating lease with Caterpillar and certain fees and expenses related to the Holdings Acquisition. Adjusted EBITDA is used as a supplemental financial measure by our management and external users of our financial statements, such as investors and commercial banks, to assess:

        We believe that Adjusted EBITDA provides useful information to investors because, when viewed with our GAAP results and the accompanying reconciliations, it provides a more complete understanding of our performance than GAAP results alone. We also believe that external users of our financial statements benefit from having access to the same financial measures that management uses in evaluating the results of our business.

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        Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance and liquidity. Moreover, our Adjusted EBITDA as presented may not be comparable to similarly titled measures of other companies.

        Adjusted EBITDA does not include interest expense, income taxes, depreciation expense, impairment of compression equipment, share-based compensation expense, restructuring charges, management fees, expenses under our operating lease with Caterpillar and certain fees and expenses related to the Holdings Acquisition. Because we borrow money under our revolving credit facility and have historically utilized operating leases to finance our operations, interest expense and operating lease expense are necessary elements of our costs. Because we use capital assets, depreciation and impairment of compression equipment is also a necessary element of our costs. Expense related to share-based compensation expense related to equity awards to employees is also necessary to operate our business. Therefore, measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income and net cash provided by operating activities determined under GAAP, as well as Adjusted EBITDA, to evaluate our financial performance and our liquidity. Our Adjusted EBITDA excludes some, but not all, items that affect net income and net cash provided by operating activities, and these measures may vary among companies. Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating this knowledge into management's decision-making processes.

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        The following table reconciles Adjusted EBITDA to net income and net cash provided by operating activities, its most directly comparable GAAP financial measures, for each of the periods presented:

 
  Historical  
 
  Predecessor    
  Successor  
 
 


 
 
  Year ended December 31,   Year
Ended
December 31,
2011
 
 
  2007   2008   2009   2010    
 
 
  (in thousands)
 

Net income

  $ 7,122   $ 20,911   $ 21,228   $ 10,479       $ 69  
 

Interest expense

   
16,468
   
14,003
   
10,043
   
12,279
       
12,970
 
 

Depreciation and amortization

    13,437     18,016     22,957     24,569         32,738  
 

Income taxes

    155     119     190     155         155  
 

Impairment of compression equipment(1)

    1,028         1,677              
 

Share-based compensation expense

    2,352     225     269     382          
 

Equipment operating lease expense(2)

            553     2,285         4,053  
 

Riverstone management fee(3)

                            1,000  
 

Restructuring charges(4)

                            300  
 

Fees and expenses related to the Holdings Acquisition(5)

                1,838          
                           

Adjusted EBITDA

  $ 40,562   $ 53,274   $ 56,917   $ 51,987       $ 51,285  
                           
 

Interest expense

    (16,468 )   (14,003 )   (10,043 )   (12,279 )       (12,970 )
 

Income tax expense

    (155 )   (119 )   (190 )   (155 )       (155 )
 

Equipment operating lease expense

            (553 )   (2,285 )       (4,053 )
 

Riverstone management fee

                            (1,000 )
 

Restructuring charges

                            (300 )
 

Fees and expenses related to the Holdings Acquisition

                (1,838 )        
 

Other

    1,666     201     288     3,362         (920 )
 

Changes in operating assets and liabilities:

                                   
   

Accounts receivable and advance to employee

    (563 )   (2,458 )   1,865     (336 )       (976 )
   

Inventory

    (216 )   (155 )   (3,680 )   503         1,974  
   

Prepaids

    (358 )   (1,165 )   608     (18 )       (219 )
   

Other non-current assets

    (2 )   (3 )   (4 )   1         (2,601 )
   

Accounts payable

    211     1,960     (857 )   (825 )       1,987  
   

Accrued liabilities and deferred revenue

    1,764     3,167     (1,406 )   455         1,730  
                           

Net cash provided by operating activities

  $ 26,441   $ 40,699   $ 42,945   $ 38,572       $ 33,782  
                           

(1)
Represents non-cash charges incurred to write-down long-lived assets with recorded values that are not expected to be recovered through future cash flows.

(2)
Represents expenses for the respective periods under the operating lease facility with Caterpillar, from whom we historically leased compression units and other equipment. On December 15, 2011, we purchased all the compression units that were previously leased from Caterpillar for $43 million and terminated all the lease schedules and covenants under the facility. As such, we believe it is useful to investors to view our results excluding these lease payments.

(3)
Represents management fees paid to Riverstone for services performed during 2011. As we expect these fees will not be paid by us after December 31, 2011, we believe it is useful to investors to view our results excluding these fees.

(4)
During the year ended December 31, 2011, we incurred $0.3 million of restructuring charges for severance and retention benefits related to the termination of certain administrative employees. These charges are reflected as restructuring charges in our consolidated statement of operations. We expect to pay these restructuring charges in 2012. We believe that it is useful to investors to view our results excluding this non-core expense.

(5)
Represents one-time fees and expenses related to the Holdings Acquisition. These fees and expenses are not related to our operations, and we do not expect to incur similar fees or expenses in the future as a publicly traded partnership.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        You should read the following discussion of our historical financial condition and results of operations in conjunction with the audited and unaudited financial statements and related notes included elsewhere in this prospectus. Among other things, those financial statements include more detailed information regarding the basis of presentation for the following information.


Overview

        We are a growth-oriented Delaware limited partnership and, based on management's significant experience in the industry, we believe that we are one of the largest independent providers of compression services in the U.S. in terms of total compression unit horsepower. We have been providing compression services since 1998. We currently operate in a number of U.S. natural gas shale plays, including the Fayetteville, Marcellus, Woodford, Barnett, Eagle Ford and Haynesville shales. We believe compression services for shale production will increase in the future. According to the Annual Energy Outlook 2012 Early Release Overview prepared by the EIA, natural gas production from shale formations will increase from 23% of total U.S. natural gas production in 2010 to 49% of total U.S. natural gas production in 2035. We also provide compression services in more mature conventional basins that will require increasing amounts of compression as they age and pressures decline.

        We operate in a single business segment, the compression service business. We provide our customers with compression services to maximize their natural gas and crude oil production, throughput and cash flow. We provide domestic compression services to major oil companies and independent producers, processors, gatherers and transporters of natural gas using our modern, flexible fleet of compression units, which have been designed to be rapidly deployed and redeployed throughout the country. As part of our services, we engineer, design, operate, service and repair our compression units and maintain related support inventory and equipment.

        We generally provide our compression services primarily under long-term, fixed fee contracts. Our contracts have initial contract terms of up to five years. We typically continue to provide compression services to our customers beyond their initial contract terms, either through renewals or on a month-to-month basis. Our customers are typically required to pay our monthly fee even during periods of limited or disrupted natural gas flows, which enhances the stability and predictability of our cash flows. We are not directly exposed to natural gas price risk because we do not take title to the natural gas we compress and because the natural gas used as fuel for our compression units is supplied by our customers without cost to us. Our indirect exposure to short-term volatility in natural gas and crude oil commodity prices is mitigated by the long-term nature of our contracts. As of December 31, 2011, we estimate that over 90% of our revenue generating horsepower was deployed in large-volume gathering systems, processing facilities and transportation applications.


General Trends and Outlook

        From 2006 through 2008, the compression industry in the U.S. experienced a period of significant strength. Our average annual horsepower utilization rates ranged from 94% to 97% during these years, and our average revenue per revenue generating horsepower per month increased from $14.18 in 2006 to $16.24 in 2008. During 2009 and the first half of 2010, the industry experienced pricing pressure as a result of reduced commodity prices and energy activity, an excess supply of gas compression equipment in the industry and the rationalization of compression equipment by producers, processors, gatherers and transporters of natural gas that has included replacing outsourced compression services with customer-owned equipment and downsizing compression units. Average monthly revenue per revenue generating horsepower declined to $16.05 in 2009, $14.70 in 2010 and $14.07 in 2011, although our utilization rates remained high at 93% for 2009 and 2010 and 92% for 2011. Pricing for the

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compression industry in the U.S. began to stabilize in mid-2010 and improved slightly during the second half of 2010 and remained stable in 2011.

        We anticipate that our average monthly revenue per revenue generating horsepower will continue to decline slightly, as market rates in 2009 and early 2010 were lower than market rates prior to 2009, and as older contracts at higher rates expire, a larger percentage of our contracts are at the lower rates prevalent since 2009. During 2009 and early 2010, we elected to sign shorter term contracts wherever practical to limit our long-term exposure to the lower rates prevalent at the time. Rates improved in the second half of 2010 and remained relatively stable through 2011. However, we expect to experience pricing pressure in 2012 across the horsepower ranges of our fleet (other than our largest horsepower units). Over the long term, we expect that continued improved pricing will ultimately improve our average monthly revenue per revenue generating horsepower as contracts that we entered into in 2009 and early 2010 expire and we enter into new contracts at higher rates. We intend to grow the number of large-horsepower units in our fleet. While large-horsepower units in general allow us to generate higher gross operating margins than lower-horsepower units, they also generate lower average monthly revenue per revenue generating horsepower.

        Our ability to increase our revenues is dependent in large part on our ability to add new revenue generating compression units to our fleet and increase the utilization of idle compression units. During 2010, we began to see an increase in overall natural gas activity in the U.S. and experienced an increase in demand for our compression services. Our revenue generating horsepower increased approximately 22% as of December 31, 2011 as compared to December 31, 2010. Average revenue generating horsepower increased approximately 11% from the year ending December 31, 2010 to the year ending December 31, 2011. We believe the activity levels in the U.S. will continue to increase, particularly in shale plays. We anticipate this activity will result in higher demand for our compression services, which we believe should result in increasing revenues. However, the expected increase in overall natural gas activity and demand for our compression services may not occur for a variety of reasons. See "Forward-looking Statements."


Factors That Affect Our Future Results

        We provide compression services to major oil companies and independent producers, processors, gatherers and transporters of natural gas, and operate in a number of U.S. natural gas shale plays, including the Fayetteville, Marcellus, Woodford, Barnett, Eagle Ford and Haynesville shales. Our customers use our services primarily in large-volume gathering systems, processing facilities and transportation applications. Regardless of the application for which our services are provided, our customers rely upon the availability of the equipment used to provide compression services and our expertise to help generate the maximum throughput of product, reduce fuel costs and reduce emissions. While we are currently focused on our existing service areas, our customers have natural gas compression demands in other areas of the U.S. in conjunction with their field development projects. We continually consider expansion of our areas of operation in the U.S. based upon the level of customer demand. Our modern, flexible fleet of compression units, which have been designed to be rapidly deployed and redeployed throughout the country, provides us with continuing opportunities to expand into other areas with both new and existing customers. From April 2008 through December 2011, we redeployed approximately 49,000 horsepower of our compression units from our Central operating region to our Northeast operating region, which includes the Marcellus shale, to meet increasing customer demand in that geographic area. Many of our customers have access to low-cost capital made available by banks and equipment manufacturers and have elected to access this capital to add compression units to their owned compression fleets. Additional purchases of compression equipment by our customers may result in reduced demand for our compression services by these customers, which could materially reduce our results of operations and ability to make cash distributions to our unitholders.

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        We believe that as a clean alternative to other fuels, natural gas will continue to be a fuel of choice for many years to come for many industries and consumers. The EIA forecasts in its Annual Energy Outlook 2012 Early Release Overview that natural gas consumption in the U.S. will increase by approximately 10% from 2010 to 2035. We believe this long-term increasing demand for natural gas will create increasing demand for compression services, for both natural gas fields as they age and for the development of new natural gas fields. Additionally, the shift to production of natural gas from shale, tight gas and coal bed formations that often have lower producing pressures than conventional reservoirs, results in a further increase in compression needs. In the short-term, changes in natural gas pricing, based primarily upon the supply of natural gas, will affect the development activities of natural gas producers based upon the costs associated with finding and producing natural gas in the particular natural gas and oil fields in which they are active. Although short-term declines in natural gas prices have a short-term negative effect on the development activity in natural gas fields, periods of lower development activity tend to place emphasis on improving production efficiency. As a result of our commitment to providing a high level of availability of the equipment used to provide compression services, we believe our service run times position us to satisfy the needs of our customers.

        In determining the amount of cash available for distribution, the board of directors of our general partner will determine the amount of cash reserves to set aside for our operations, including reserves for future working capital, maintenance capital expenditures, expansion capital expenditures and other matters, which will impact the amount of cash we are able to distribute to our unitholders. However, we expect that we will rely primarily upon external financing sources, including borrowings under our revolving credit facility and issuances of debt and equity securities, rather than cash reserves, to fund our expansion capital expenditures. To the extent we are unable to finance growth externally and are unwilling to establish cash reserves to fund future expansions, our cash available for distribution will not significantly increase. In addition, 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 expansion 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. There are no limitations in our partnership agreement or in the terms of our revolving credit facility on our ability to issue additional units, including units ranking senior to the common units.


How We Evaluate Our Operations

        One of our measures of operational performance is the amount of revenue generating horsepower we are able to install monthly, quarterly and annually. Revenue generating horsepower growth is the primary driver for our revenue growth and it is also the base measure for evaluating our efficiency of capital deployed. Revenue generating horsepower is horsepower under contract for which we are billing a customer.

        Each month we identify idle compression units in our compression fleet and analyze their availability for redeployment. The primary reason for tracking and analyzing idle horsepower is to facilitate redeployment and therefore increase our contract operations revenue and efficiency of capital deployed. Our horsepower utilization is calculated as (i)(a) revenue generating horsepower plus (b) horsepower in our fleet that is under contract, but is not yet generating revenue plus (c) horsepower not yet in our fleet that is under contract not yet generating revenue and that is subject

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to a purchase order, divided by (ii) total available horsepower less idle horsepower that is under repair. Fleet horsepower utilization is calculated as (i) revenue generating horsepower divided by (ii) fleet horsepower.

        We use cost of operations as a performance measure for each of our operating areas and the managers in charge of those operating areas. We track the items in cost of operations down to the compression unit level, and are able to compare operating costs to the budget we have for the type of horsepower and the area in which it is located. We use these comparisons to identify, research and address trends and variances. We also track our cost of operations on a company-wide basis, using month-to-month, year-to-date and year-to-year comparisons, and as compared to budget. This analysis is useful in identifying company-wide cost trends and allows us to take corrective actions as required.

        We view Adjusted EBITDA as one of our primary management tools, and we track this item on a monthly basis both as an absolute amount and as a percentage of revenue compared to the prior month, year-to-date and prior year and to budget. We define Adjusted EBITDA as our net income before interest expense, income taxes, depreciation expense, impairment of compression equipment, share-based compensation expense, restructuring charges, management fees, expenses under our operating lease with Caterpillar and certain fees and expenses related to the Holdings Acquisition. Adjusted EBITDA is used as a supplemental financial measure by our management and external users of our financial statements, such as investors and commercial banks, to assess:

        We believe that Adjusted EBITDA provides useful information to investors because, when viewed with our GAAP results and the accompanying reconciliations, it provides a more complete understanding of our performance than GAAP results alone. We also believe that external users of our financial statements benefit from having access to the same financial measures that management uses in evaluating the results of our business.

        Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance and liquidity. Moreover, our Adjusted EBITDA as presented may not be comparable to similarly titled measures of other companies.

        Adjusted EBITDA does not include interest expense, income taxes, depreciation expense, impairment of compression equipment, share-based compensation expense, restructuring charges, management fees, expenses under our operating lease with Caterpillar or certain fees and expenses related to the Holdings Acquisition. Because we borrow money under our revolving credit facility and have historically utilized operating leases to finance our operations, interest expense and operating lease expense are necessary elements of our costs. Because we use capital assets, depreciation and impairment of compression equipment is also a necessary element of our costs. Expense related to

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share-based compensation expense related to equity awards to employees is also necessary to operate our business. Therefore, measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income and net cash provided by operating activities determined under GAAP, as well as Adjusted EBITDA, to evaluate our financial performance and our liquidity. Our Adjusted EBITDA excludes some, but not all, items that affect net income, operating income and net cash provided by operating activities, and these measures may vary among companies. Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating this knowledge into management's decision-making processes.

        Gross operating margin (defined as revenue less cost of operations, exclusive of depreciation and amortization expense) is a key measure for our business. Gross operating margin is impacted primarily by the pricing trends for our service operations and our cost of operations including labor rates for our service technicians, volume and per unit costs for our lubricant oils, quantity and pricing for our routine preventative maintenance to our compression units and property tax rates on our compression units. For a reconciliation of gross operating margin, a non-GAAP financial measure, to operating income, its most directly comparable financial measure calculated and presented in accordance with GAAP, see "—Operating Highlights."

Accounting Terminology and Principles

        Our discussion and analysis uses the following accounting terminology and principles:

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Operating Highlights

        The following table summarizes certain horsepower and horsepower utilization percentages for the periods presented.

 
  Predecessor    
  Successor    
 
 
  Year Ended December 31,   Percent
Change
   
  Year Ended
December 31,
  Percent
Change
 
Operating Data (unaudited):
  2009   2010   2010    
  2011   2011  

Fleet horsepower(1)

    582,530     609,730     4.7 %       722,201     18.4 %

Total available horsepower(2)

    582,530     612,410     5.1 %       809,418     32.2 %

Revenue generating horsepower(3)

    502,177     533,692     6.3 %       649,285     21.7 %

Average revenue generating horsepower(4)

    489,243     516,703     5.6 %       570,900     10.5 %

Revenue generating compression units

    749     795     6.1 %       888     11.7 %

Average horsepower per revenue generating compression unit(5)

    655     667     1.8 %       692     3.7 %

Horsepower utilization(6):

                                   
 

At period end

    92.0 %   91.8 %   (0.2 )%       95.7 %   4.2 %
 

Average for the period(7)

    92.7 %   92.6 %   (0.1 )%       92.3 %   (0.3 )%

(1)
Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order). As of December 31, 2011, we had 171,245 of additional new compression unit horsepower on order, of which 61,134 horsepower is expected to be delivered between January 2012 and March 2012, 82,443 horsepower is expected to be delivered between April 2012 and June 2012, and 27,668 horsepower is expected to be delivered between July 2012 and September 2012.

(2)
Total available horsepower is revenue generating horsepower under contract for which we are billing a customer, horsepower in our fleet that is under contract but is not yet generating revenue, horsepower not yet in our fleet that is under contract not yet generating revenue and that is subject to a purchase order and idle horsepower. Total available horsepower excludes new horsepower on order for which we do not have a compression services contract.

(3)
Revenue generating horsepower is horsepower under contract for which we are billing a customer.

(4)
Calculated as the average of the month-end horsepower per revenue generating horsepower for each of the months in the period.

(5)
Calculated as the average of the month-end horsepower per revenue generating compression unit for each of the months in the period.

(6)
Horsepower utilization is calculated as (i)(a) revenue generating horsepower plus (b) horsepower in our fleet that is under contract, but is not yet generating revenue plus (c) horsepower not yet in our fleet that is under contract not yet generating revenue and that is subject to a purchase order, divided by (ii) total available horsepower less idle horsepower that is under repair. Horsepower utilization based on revenue generating horsepower and fleet horsepower at each applicable period end was 86.2%, 87.5% and 89.9% for the years ended December 31, 2009, 2010 and 2011, respectively.

(7)
Calculated as the average utilization for the months in the period based on utilization at the end of each month in the period.

        The increase in fleet horsepower as of December 31, 2011 compared to December 31, 2010 is attributable to the compression units added to our fleet to meet the incremental demand by new and current customers. Revenue generating horsepower increased by 21.7% from December 31, 2010 to

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December 31, 2011. The average horsepower per revenue generating compression unit, increased from 667 to 692 between 2010 and 2011.

 
  Predecessor    
  Successor    
 
 
  Year Ended December 31,   Percent
Change
   
  Year Ended
December 31,
  Percent
Change
 
Other Financial Data:
  2009   2010   2010    
  2011   2011  

Gross Operating Margin(1)

  $ 65,132   $ 58,736     (9.8 )%     $ 59,115     0.6 %

Adjusted EBITDA(2)

  $ 56,917   $ 51,987     (8.7 )%     $ 51,285     (1.4 )%

Gross operating margin percentage(3)

    68.4 %   63.8 %   (6.7 )%       59.9 %   (6.1 )%

Adjusted EBITDA percentage(3)

    59.8 %   56.5 %   (5.5 )%       51.9 %   (8.1 )%

(1)
Gross operating margin is a non-GAAP financial measure. We calculate gross operating margin as revenue less cost of operations, exclusive of depreciation and amortization expense. We believe that gross operating margin is useful as a supplemental measure of our operating profitability. Gross operating margin should not be considered an alternative to, or more meaningful than, operating income or any other measure of financial performance presented in accordance with GAAP. Moreover, gross operating margin as presented may not be comparable to similarly titled measures of other companies. Because we capitalize assets, depreciation and amortization of equipment is a necessary element of our costs. To compensate for the limitations of gross operating margin as a measure of our performance, we believe that it is important to consider operating income determined under GAAP, as well as gross operating margin, to evaluate our operating profitability.


The following table reconciles gross operating margin to operating income, its most directly comparable GAAP financial measure, for each of the periods presented:

   
  Predecessor    
  Successor  
   
  Year Ended December 31,    
  Year Ended
December 31,
 
   
  2009   2010    
  2011  
   
  (in thousands)
   
   
 
 

Revenues:

                       
   

Contract operations

  $ 93,178   $ 89,785       $ 93,896  
   

Parts and service

    2,050     2,243         4,824  
                     
     

Total revenues

    95,228     92,028         98,720  
 

Cost of operations, exclusive of depreciation and amortization

    30,096     33,292         39,605  
                     
     

Gross operating margin

    65,132     58,736         59,115  
 

Other operating and administrative costs and expenses:

                       
   

Selling, general and administrative

    9,136     11,370         12,726  
   

Restructuring charges

                300  
   

Depreciation and amortization

    22,957     24,569         32,738  
   

(Gain) loss on sale of assets

    (74 )   (90 )       178  
   

Impairment of compression equipment

    1,677              
                     
     

Total other operating and administrative costs and expenses

    33,696     35,849         45,942  
                     
 

Operating income

  $ 31,436   $ 22,887       $ 13,173  
                     
(2)
For a reconciliation of Adjusted EBITDA, a non-GAAP financial measure, to net income and cash flows from operating activities, its most directly comparable GAAP financial measures, see "Selected Historical Financial and Operating Data—Non-GAAP Financial Measures."

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(3)
Gross operating margin percentage and Adjusted EBITDA percentage are calculated as a percentage of revenue.

        Gross operating margin declined from 68% in 2009 to 64% in 2010. The decline in gross operating margin resulted from pricing pressure for compression services that began in 2009. While pricing for these services stabilized in mid-2010, compression units that were placed under service contracts during 2009 and 2010 were contracted at lower market rates. In addition, expenses related to our operating lease with Caterpillar were $2.3 million in 2010, or 2.5% of revenue, and $0.6 million in 2009, or 0.6% of revenue.

        Gross operating margin declined from 64% in 2010 to 60% in 2011. The decline in gross operating margin is primarily attributable to continued cost increases for providing our compression services. Increased expenses related to the addition of new compression units in 2011 under our operating lease with Caterpillar, which were $2.3 million in 2010, or 2.5% of revenue, as compared to $4.1 million in 2011, or 4.1% of revenue. On December 15, 2011, we purchased all the compression units we previously leased from Caterpillar for $43 million and terminated all the lease schedules and covenants under the facility. In addition, expenses related to fluids increased from $4.3 million in 2010, or 4.7% of revenue, to $5.1 million in 2011, or 5.2% of revenue. This increase is due to a 21.4% increase in fluids supplier pricing during 2011 as compared to 2010, offset by a 1.3% decrease in gallons used in 2011. Other significant increases in expenses include (1) maintenance expenses increased by $0.3 million, or 0.1% of revenue, (2) truck fleet fuel expenses increased by $0.4 million, or 0.3% of revenue, (3) supplies and equipment expenses increased by $0.2 million, or 0.2% of revenue, and (4) operating personnel salaries and benefits expense increased $0.4 million, each of which are attributable to the increase in the size of our fleet horsepower. Additionally, a portion of retail service revenue, including billings for trucking and crane services increased $1.1 million during 2011, including $1.0 million recognized during the fourth quarter of 2011, due to the deployment and redeployment of compression units. These ancillary trucking and crane services, all of which are billed to customers, result in 0% gross operating margin.

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Financial Results of Operations

Year ended December 31, 2011 compared to the year ended December 31, 2010

        The following table summarizes our results of operations for the periods presented:

 
  Predecessor    
  Successor    
 
 
  Year ended
December 31,
   
 
 
  Percent
Change
 
 
  2010    
  2011  
 
  (in thousands)
   
 

Revenues:

                       
 

Contract operations

  $ 89,785       $ 93,896     4.6 %
 

Parts and service

    2,243         4,824     115.1 %
                   
 

Total revenues

    92,028         98,720     7.3 %

Costs and expenses:

                       
 

Cost of operations, exclusive of depreciation and amortization

    33,292         39,605     19.0 %
 

Selling, general and administrative

    11,370         12,726     11.9 %
 

Restructuring charges

            300        
 

Depreciation and amortization

    24,569         32,738     33.2 %
 

(Gain) loss on sale of assets

    (90 )       178        
                   
 

Total costs and expenses

    69,141         85,547     23.7 %
                   

Operating income

    22,887         13,173     (42.4 )%

Other income (expense):

                       
 

Interest expense

    (12,279 )       (12,970 )   5.6 %
 

Other

    26         21     (19.2 )%
                   
 

Total other expense

    (12,253 )       (12,949 )   5.7 %
                   

Income before income tax expense

    10,634         224     (97.9 )%

Income tax expense

    155         155     0.0 %
                   

Net income

  $ 10,479       $ 69     (99.3 )%
                   

        Contract operations revenue.    Contract operations revenue was $93.9 million for the year ended December 31, 2011 compared to $89.8 million in 2010, an increase of 4.6%. Average revenue generating horsepower increased from 516,703 for the year ended December 31, 2010 to 570,900 for the year ended December 31, 2011, an increase of 10.5%. Average revenue per revenue generating horsepower per month declined from $14.70 for the year ended December 31, 2010 to $14.07 for the year ended December 31, 2011, a decrease of 4.3%. The decline in average revenue per revenue generating horsepower per month relates primarily to the 3.7% increase in the estimated average horsepower per revenue generating compression unit, which was 667 and 692 at December 31, 2010 and 2011, respectively. While pricing for these services stabilized in mid-2010, compression units that were placed under service contracts during 2009 and 2010 were contracted at lower market rates. There were 888 revenue generating compression units at December 31, 2011 compared to 795 at December 31, 2010, an 11.7% increase. Revenue generating horsepower was 649,285 at December 31, 2011 compared to 533,692 at December 31, 2010, a 21.7% increase.

        Parts and service revenue.    Parts and service revenue was $4.8 million for the year ended December 31, 2011 compared to $2.2 million in 2010, or a 115.1% increase. Retail parts revenue increased $1.5 million during 2011 after our customers curtailed this work with us in 2010. A portion of retail service revenue, including billings for trucking and crane services increased $1.1 million during 2011, including $1.0 million recognized during the fourth quarter of 2011, due to the deployment and

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redeployment of compression units. These ancillary trucking and crane services, all of which are billed to customers, result in 0% gross operating margin.

        Cost of operations, exclusive of depreciation and amortization.    Cost of operations was $39.6 million for the year ended December 31, 2011 compared to $33.3 million for the year ended December 31, 2010, an increase of 19.0%. Approximately $1.8 million of this increase was related to higher expense levels under our operating lease facility with Caterpillar due to the addition of new compression units over the applicable periods. The amount drawn under this operating lease facility immediately prior to the termination of these lease schedules on December 15, 2011 was $39.9 million as compared to $28.9 million as of December 31, 2010. Approximately $0.8 million of the increase in cost of operations was related to higher lubrication oil expenses. Lubrication oil expenses increased due to a 21.4% increase in the average supplier price per gallon, offset by a 1.3% decrease in gallons consumed. Freight costs, all of which was billed to customers, increased $1.1 million due to the redeployment of compression units during the year ended December 31, 2011, as discussed above. Retail parts expense increased $1.1 million due to the sale of six spare engines. Other significant increases include (1) maintenance expenses increased by $0.3 million, (2) truck fleet fuel expenses increased by $0.4 million, (3) supplies and equipment expenses increased by $0.2 million and (4) operating personnel salaries and benefits expense increased $0.4 million, all of which are attributable to the increase in the size of our fleet. The cost of operations was 40.2% of revenue for the year ended December 31, 2011 as compared to 36.2% for the year ended December 31, 2010.

        Selling, general and administrative expense.    Selling, general and administrative expense was $12.7 million for the year ended December 31, 2011 compared to $11.4 million for the year ended December 31, 2010, an increase of 11.9%. Selling, general and administrative expense represented 12.9% and 12.4% of revenue for the year ended December 31, 2011 and 2010, respectively. Approximately $1.0 million of the increase in selling, general and administrative expense relates to a fee for management services provided by an affiliate of our general partner, which we expect will not be paid by us after December 31, 2011. The selling, general and administrative employee headcount was 51 at December 31, 2011, a 30.8% employee increase from December 31, 2010, resulting in $0.7 million increase in salary and benefit expenses. The selling, general and administrative employee headcount increased to support continued growth of the business.

        Restructuring charges.    During the year ended December 31, 2011, we incurred $0.3 million of restructuring charges for severance and retention benefits related to the termination of certain administrative employees. These charges are reflected as restructuring charges in our consolidated statement of operations for the year ended December 31, 2011. We expect to pay these restructuring charges in 2012.

        Depreciation and amortization expense.    Depreciation and amortization expense was $32.7 million for the year ended December 31, 2011 compared to $24.6 million for the year ended December 31, 2010, an increase of 33.2%. The push-down accounting treatment for the Holdings Acquisition resulted in the recognition of identified intangibles for customer relationships and the USA Compression trade name as of December 31, 2010 and the amortization of these identified intangibles over their useful lives began on January 1, 2011, of which $3.0 million was recognized for the year ended December 31, 2011. The remaining increase is related to an increase in property, plant and equipment over these periods.

        Interest expense.    Interest expense was $13.0 million for the year ended December 31, 2011 compared to $12.3 million for the year ended December 31, 2010, an increase of 5.6%. Included in interest expense is amortization of deferred loan costs of $1.5 million and $3.4 million for the years ended December 31, 2011 and 2010, respectively. Interest expense for both periods was related to borrowings under our revolving credit facility. Average borrowings outstanding under our revolving credit facility were $275.1 million for the year ended December 31, 2011 compared to $249.1 million

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for the year ended December 31, 2010. Our revolving credit facility had an interest rate of 3.02% and 3.76% at December 31, 2011 and 2010, respectively, and an average interest rate of 3.71% and 2.06%, excluding the effects from the interest rate swap instruments discussed below, for the year then ended, respectively, with the higher interest rate at December 31, 2011 due to the amendment of our revolving credit facility in December 2010. The November 2011 amendment to our credit facility increased the overall commitments under the facility from $400 million to $500 million and reduced our applicable margin for LIBOR loans from a range of 300 to 375 basis points above LIBOR to a range of 200 to 275 basis points above LIBOR, depending on our leverage ratio. The composite fixed interest rate for $140 million of notional coverage under three interest rate swap instruments was 2.52% at December 31, 2011 and 2010 plus the applicable margin of 2.75% and 3.50% at December 31, 2011 and December 31, 2010, respectively. As of December 31, 2010, we no longer designate our swap agreements as cash flow hedges. As a result, amounts paid or received from the interest rate swaps are charged or credited to interest expense. For the year ended December 31, 2011, we recorded a fair value gain of $2.6 million with respect to these swaps as a reduction in interest expense.

        Income tax expense.    We accrued approximately $155,000 in franchise tax for the years ended December 31, 2011 and 2010, as a result of the Texas franchise tax.

Year ended December 31, 2010 compared to the year ended December 31, 2009

        The following table summarizes our results of operations for the periods presented:

 
  Predecessor    
 
 
  Year Ended December 31,    
 
 
  Percent
Change
 
 
  2009   2010  
 
  (in thousands)
   
 

Revenues:

                   
 

Contract operations

  $ 93,178   $ 89,785     (3.6 )%
 

Parts and service

    2,050     2,243     9.4 %
               
 

Total revenues

    95,228     92,028     (3.4 )%

Costs and expenses:

                   
 

Cost of operations, exclusive of depreciation and amortization

    30,096     33,292     10.6 %
 

Selling, general and administrative

    9,136     11,370     24.5 %
 

Depreciation and amortization

    22,957     24,569     7.0 %
 

(Gain) loss on sale of assets

    (74 )   (90 )   21.6 %
 

Impairment of compression equipment

    1,677            
               
 

Total costs and expenses

    63,792     69,141     8.4 %
               

Operating income

    31,436     22,887     (27.2 )%

Other income (expense):

                   
 

Interest expense

    (10,043 )   (12,279 )   22.3 %
 

Other

    25     26     4.0 %
               
 

Total other expense

    (10,018 )   (12,253 )   22.3 %
               

Income before income tax expense

    21,418     10,634     (50.4 )%

Income tax expense

    190     155     (18.4 )%
               

Net income

  $ 21,228   $ 10,479     (50.6 )%
               

        Contract operations revenue.    Contract operations revenue was $89.8 million for the year ended December 31, 2010 compared to $93.2 million for the year ended December 31, 2009, a decrease of 3.6%. Average revenue generating horsepower increased from 489,243 for the year ended

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December 31, 2009, to 516,703 for the year ended December 31, 2010, an increase of 5.6% increase. Average revenue per revenue generating horsepower per month declined from $16.05 for the year ended December 31, 2009, to $14.70 for the year ended December 31, 2010, a decrease of 8.4%. The decline in revenue per revenue generating horsepower per month relates to general pricing pressure for compression revenue that began in 2009. While pricing for these services stabilized in mid-2010, compression units that were placed under service contracts during 2009 and 2010 were placed at lower market rates. There were 795 revenue generating compression units at December 31, 2010 compared to 749 at December 31, 2009, a 6.1% increase. Revenue generating horsepower was 533,692 at December 31, 2010 compared to 502,177 at December 31, 2009, a 6.3% increase.

        Parts and service revenue.    Parts and service revenue was $2.2 million for the year ended December 31, 2010 compared to $2.1 million for the year ended December 31, 2009, a 9.4% increase.

        Cost of operations, exclusive of depreciation and amortization.    Cost of operations was $33.3 million for the year ended December 31, 2010 compared to $30.1 million for the year ended December 31, 2009, an increase of 10.6%. Approximately $1.7 million of this increase was related to higher expense levels under our operating lease facility with Caterpillar. The amount drawn under this operating lease facility was $28.9 million as of December 31, 2010 as compared to $14.9 million as of December 31, 2009. Indirect operating expenses increased approximately $1.1 million for 2010 as compared to 2009 including field warehouse supplies, property taxes and our service technician vehicle fleet due to the increase in our compression unit fleet horsepower. The cost of operations was 36.2% of revenue for the year ended December 31, 2010 as compared to 31.6% for the year ended December 31, 2009.

        Selling, general and administrative expense.    Selling, general and administrative expense was $11.4 million for the year ended December 31, 2010 compared to $9.1 million for the year ended December 31, 2009, an increase of 24.5%. Selling, general and administrative expense represented 12.4% and 9.6% of revenue for the years ended December 31, 2010 and 2009, respectively. The selling, general and administrative employee headcount was 39 employees at December 31, 2010, level with the headcount at December 31, 2009. Selling, general and administrative expenses in 2010 included $1.8 million related to legal fees incurred by us in connection with the Holdings Acquisition.

        Depreciation and amortization expense.    Depreciation and amortization expense was $24.6 million for the year ended December 31, 2010 compared to $23.0 million for the year ended December 31, 2009, an increase of 7.0%, which resulted from an increase in property, plant and equipment in 2009 and 2010 and a change in the estimated useful lives of our vehicles in July 2009.

        Interest expense.    Interest expense was $12.3 million for the year ended December 31, 2010, compared to $10.0 million for the year ended December 31, 2009, an increase of 22.3%. Included in interest expense is amortization of deferred loan costs of $3.5 million and $0.4 million for the years ended December 31, 2010 and 2009, respectively. Interest expense for both periods was related to borrowings under our revolving credit facility. Average borrowings outstanding under our revolving credit facility were $249.1 million for the year ended December 31, 2010 compared to $270.3 million for the year ended December 31, 2009. Our revolving credit facility had an interest rate of 3.76% and 1.99% at December 31, 2010 and 2009, respectively, and an average interest rate of 2.06% in 2010 and 2.10% in 2009, excluding the effects from the interest rate swap instruments. The composite fixed interest rate for $140 million of notional coverage under three interest rate swap instruments was 2.52% at December 31, 2010 and 2009 plus the applicable margin of 1.75%.

        Income tax expense.    We accrued approximately $155,000 in franchise tax for the year ended December 31, 2010, and $190,000 for the year ended December 31, 2009, as a result of the Texas franchise tax.

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Effects of Inflation

        In 2011, 2010 and 2009, even though the price for lubrication oil, gasoline, insurance and the capital cost of engines steadily increased, these increases did not adversely impact our overall results of operations. We have the ability to manage the effects of these price increases through rate adjustments in new service contracts, as well as through Consumer Price Index adjustments in most existing customer contracts. The primary price increases experienced for the period from January 1, 2009 to December 31, 2011 were the following: the hourly labor rate for certain classes of our service technicians had a composite increase of 6.0%; the price of lubrication oil per gallon decreased approximately 6.1%, but gallons consumed has increased 2.0%; for similarly configured 3516 type compression units, our price increased 8.0% for new compression units purchased during the quarter ended December 31, 2011 as compared to new compression units purchased during the quarter ended March 31, 2009.

Liquidity and Capital Resources

        Historically, our sources of liquidity have been cash generated from operations and third-party financing. As of December 31, 2011, 2010 and 2009, total cash and cash equivalents was $3,000. Total liquidity, comprised of cash and availability of long-term borrowings, was $39.0 million at December 31, 2011 compared to $66.0 million and $44.6 million as of December 31, 2010 and 2009, respectively.

        We have a $500 million revolving credit facility that matures on October 5, 2015. Commitments under our revolving credit facility increased from $305 million to $400 million in December 2010 and from $400 million to $500 million on November 16, 2011. Availability under the revolving credit facility is determined by reference to the calculated borrowing base, up to the commitment amount, less the outstanding balance under the revolving credit facility. See "—Description of Revolving Credit Facility."

        On                        , 2012, we completed the sale of                    common units in our initial public offering. Net proceeds from the offering were approximately $         million, after deducting the underwriting discounts and commissions and estimated offering expenses. We used the net proceeds from the offering to repay $         million of indebtedness outstanding under our revolving credit facility. As of                        , 2012, after giving effect to the repayment of borrowings with net proceeds from the initial public offering, there was approximately $         million outstanding under the revolving credit facility. We will use the net proceeds from any exercise of the underwriters' option to purchase additional common units in the initial public offering to redeem from USA Compression Holdings a number of common units equal to the number of common units issued upon the exercise of the underwriters' option.

        The amount of available cash we need to pay the minimum quarterly distributions for four quarters on our common units, subordinated units and the 2.0% general partner interest outstanding immediately after our initial public offering is approximately $             million. The issuance of additional common units pursuant to our distribution reinvestment plan will increase the amount of available cash we will need to pay the minimum quarterly distribution on our common units, subordinated units and the 2.0% general partner interest.

        In addition to distributions on our equity interests, our primary short-term liquidity needs will be to fund general working capital requirements, while our long-term liquidity needs will primarily relate to expansion capital expenditures. We believe that cash from operations will be sufficient to meet our existing short-term liquidity needs for at least the next 12 months.

        Our long-term liquidity needs will generally be funded from cash from operations, borrowings under our revolving credit facility and other debt or equity financings. We cannot assure you that we will be able to raise additional funds on favorable terms. For more information, please read "—Capital Expenditures" below.

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        The following table summarizes our sources and uses of cash for the periods presented:

 
  Predecessor    
  Successor  
 
  Year Ended December 31,  
 
  2009   2010    
  2011  
 
  (in thousands)
 
 
   
   
   
   
 

Net cash provided by operating activities

  $ 42,945   $ 38,572       $ 33,782  

Net cash used in investing activities

    (26,763 )   (18,768 )       (140,444 )

Net cash provided (used) in financing activities

    (16,545 )   (19,804 )       106,662  

        Net cash provided by operating activities.    Net cash provided by operating activities decreased to $33.8 million for the year ended December 31, 2011, from $38.6 million in 2010. The decrease relates primarily to a lower income level, offset by $1.9 million of working capital generated for the year ended December 31, 2011.

        Net cash provided by operating activities decreased to $38.6 million for the year ended December 31, 2010, from $42.9 million for the year ended December 31, 2009. The decrease relates primarily to a lower income level in 2010, offset by the purchase of engines in 2009 totaling $3.3 million.

        Net cash used in investing activities.    Net cash used in investing activities increased to $140.4 million for the year ended December 31, 2011, from $18.8 million in 2010. The increase relates to capital expenditures of $133.3 million and a compression unit purchase deposit of $8.0 million, for the year ended December 31, 2011, offset by the collection of funds in this period of $0.8 million related to the sale of compression units, 6 engines, and trucks.

        Net cash used in investing activities decreased to $18.8 million for the year ended December 31, 2010, from $26.8 million for the year ended December 31, 2009. The decrease primarily relates to lower capital expenditures for compression equipment in 2010. Approximately $13.9 million and $14.9 million of compression equipment was funded under our operating lease facility with Caterpillar in 2010 and 2009, respectively.

        Net cash provided (used) in financing activities.    Net cash provided by financing activities was $106.7 million for the year ended December 31, 2011, compared to net cash used in financing activities of $19.8 million in 2010. The change is due to net repayments of borrowings under our revolving credit facility for the year ended December 31, 2010 versus net borrowings during 2011, due to higher levels of growth capital expenditures.

        Net cash used in financing activities increased to $19.8 million for the year ended December 31, 2010, from $16.5 million for the year ended December 31, 2009. The increase is a result of a lower level of net repayments of borrowings under our revolving credit facility of $4.4 million offset by financing costs of $8.1 million related to the upsizing and extending of our revolving credit facility on December 23, 2010 in connection with the Holdings Acquisition.

        The compression business is capital intensive, requiring significant investment to maintain, expand and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate that our capital requirements will continue to consist primarily of, the following:

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        We expect that our maintenance capital expenditure requirements will continue to increase as the overall size and age of our fleet increases. Our aggregate maintenance capital expenditures for the year ended December 31, 2011 were $9.0 million and we estimate that our aggregate maintenance capital expenditures for the year ending December 31, 2012 will be approximately $10.6 million.

        Given our growth objective, we anticipate that we will continue to make significant expansion capital expenditures. Our expansion capital expenditures were $124.3 million for the year ended December 31, 2011 and we estimate that our expansion capital expenditures will be approximately $148.3 million for the year ending December 31, 2012, consisting of the acquisition of new compression units and related equipment. On December 16, 2011, we entered into an agreement with one of our new compression equipment suppliers to reduce certain previously made progress payments by $8 million and received a credit. We will apply this $8 million credit to new compression unit purchases from this supplier in the first quarter of 2012.

        In addition to organic growth, we may also consider a variety of assets or businesses for potential acquisition. We expect to fund any future acquisitions primarily with capital from external financing sources and issuance of debt and equity securities, including our issuance of additional partnership units and future debt offerings given market conditions.

        We amended the revolving credit facility in December 2010 to increase the overall commitments under the facility to $400 million and extend the term until October 5, 2015. On November 16, 2011, we amended our revolving credit facility to increase the overall commitments under the facility from $400 million to $500 million and reduce our applicable margin for LIBOR loans from the previous range of 300 to 375 basis points above LIBOR to the new range of 200 to 275 basis points above LIBOR, depending on our leverage ratio. The terms of the revolving credit facility are discussed below. We have the option to increase the overall commitments under our revolving credit facility by $50 million, subject to receipt of lender commitments and satisfaction of other conditions.

        The revolving credit facility is available for our general partnership purposes, including working capital, capital expenditures, and distributions. As of                        , 2012, after giving effect to the repayment of borrowings with net proceeds from our initial public offering, there was approximately $         million outstanding under the revolving credit facility.

        Our obligations under the revolving credit facility are secured by substantially all of our assets and the assets of our subsidiaries, and are guaranteed by us and our subsidiaries.

        Availability under our revolving credit facility is subject to a monthly borrowing base calculation (or weekly if availability under the revolving credit facility falls below a specified threshold), which is equal to the sum of: (i) 85% of certain eligible trade accounts receivable held by us, (ii) a percentage of the net book value of our eligible compressors and (iii) 80% of our eligible work in progress, which consists of component costs, such as compressor engines, coolers and frames and other related costs, as well as newly assembled compression units that are awaiting installation. The revolving credit facility provides that we may borrow only up to the lesser of the level of our then current borrowing base and the capacity of the facility.

        We may prepay all advances at any time without penalty, subject to the reimbursement of lender breakage costs in the case of prepayment of LIBOR borrowings. Indebtedness under the revolving

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credit facility will bear annual interest at our election at a rate of prime or 200 to 275 basis points above LIBOR.

        The revolving credit facility prohibits us from making distributions of available cash if any event of default (as defined in the revolving credit facility) exists. The revolving credit facility requires us to comply with two primary financial covenants: (i) a compression unit horsepower based, six month look-back utilization covenant of 80% (i.e. idle equipment cannot exceed 20% of total available horsepower) and (ii) a fixed charge coverage ratio covenant, determined for any period of four consecutive fiscal quarters, of 1.0 to 1.0.

        In addition, the revolving credit facility contains various covenants that may limit, among other things, our ability to:

        If an event of default exists under our revolving credit facility, the lenders will be able to accelerate the maturity of the debt outstanding under the revolving credit facility and exercise other rights and remedies. Each of the following will be an event of default under our revolving credit facility:

        We are in compliance with all of the covenants under the revolving credit facility and, so long as we remain in compliance with the revolving credit facility, we will be permitted to make distributions of available cash.

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        Total Contractual Cash Obligations.    The following table summarizes our total contractual cash obligations as of December 31, 2011:

 
  Payments Due by Period  
Contractual Obligations
  Total   1 year   2 - 3 years   4 - 5 years   More than 5 years  
 
  (in thousands)
 

Long-term debt(1)

  $ 363,773   $   $   $ 363,773   $  

Interest on long-term debt obligations(2)

    41,197     10,986     21,972     8,239      

Equipment/capital purchases(3)

    136,100     136,100              
                       

Total contractual cash obligations

  $ 541,070   $ 147,086   $ 21,972   $ 372,012   $  
                       

(1)
Represents future principal repayments under our revolving credit facility.

(2)
Represents future interest payments under our revolving credit facility based on the interest rate at December 31, 2011 of 3.02%.

(3)
Represents commitments for new compression units that are being fabricated.

        We had approximately $             million outstanding under the revolving credit facility after the closing of our initial public offering. We anticipate subsequent borrowings under this revolving credit facility to fund interest payments, capital expenditures, including the acquisition of additional new compression units, and distributions.

Off Balance Sheet Arrangements

        We have not entered into any transactions, agreements or other contractual arrangements that would result in off-balance sheet liabilities.

Critical Accounting Policies and Estimates

        The discussion and analysis of our financial condition and results of operations is based upon our financial statements. These financial statements were prepared in conformity with U.S. GAAP. As such, we are required to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. We base our estimates on historical experience, available information and various other assumptions we believe to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates; however, actual results may differ from these estimates under different assumptions or conditions. The accounting policies that we believe require management's most difficult, subjective or complex judgments and are the most critical to its reporting of results of operations and financial position are as follows:

        Property and equipment are stated at cost. Depreciation for financial reporting purposes is computed on the straight-line basis using estimated useful lives. If the actual useful life of our property and equipment is less than the estimate used for purposes of computing depreciation expense, we could experience an acceleration in depreciation expense. Major overhauls and improvements that extend the life of an asset are capitalized. As of December 31, 2011, we had 1,001 compression units that were subject to depreciation. Given the large number of compression units being depreciated, the impact of a particular unit incurring an actual useful life that is less than the estimated useful life would not have a material impact on our results of operations.

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

        We perform an impairment test for goodwill annually or earlier if indicators of potential impairment exist. Our goodwill impairment test involves a comparison of the fair value of its reporting unit with its carrying value. The fair value is determined using discounted cash flows and other market-related valuation models. Certain estimates and judgments are required in the application of the fair value models. As of December 31, 2010, we performed an impairment analysis and determined that no impairment had occurred. If for any reason the fair value of our goodwill declines below the carrying value in the future, we may incur charges for the impairment. There was no impairment recorded for goodwill for the years ended December 31, 2010 and 2011.

        Long-lived assets, which include property and equipment, and intangible assets comprise a significant amount of our total assets. Long-lived assets to be held and used by us are reviewed to determine whether any events or changes in circumstances indicate the carrying amount of the asset may not be recoverable. For long-lived assets to be held and used, we base our evaluation on impairment indicators such as the nature of the assets, the future economic benefit of the assets, any historical or future profitability measurements and other external market conditions or factors that may be present. If such impairment indicators are present or other factors exist that indicate the carrying amount of the asset may not be recoverable, we determine whether an impairment has occurred through the use of an undiscounted cash flows analysis. If an impairment has occurred, we recognize a loss for the difference between the carrying amount and the estimated fair value of the asset. The fair value of the asset is measured using quoted market prices or, in the absence of quoted market prices, is based on an estimate of discounted cash flows. There was no impairment recorded for the years ended December 31, 2011 and 2010, and an impairment of $1.7 million was recorded for the year ended December 31, 2009.

        We maintain an allowance for bad debts based on specific customer collection issues and historical experience. On an ongoing basis, we conduct an evaluation of the financial strength of our customers based on payment history and specific identification and makes adjustments to the allowance as necessary. The allowance for doubtful accounts was $260,598 and $173,808 at December 31, 2011 and 2010, respectively.

        Revenue is recognized by us using the following criteria: (i) persuasive evidence of an arrangement, (ii) delivery has occurred or services have been rendered, (iii) the customer's price is fixed or determinable and (iv) collectability is reasonably assured.

        Revenues from compression services are recognized as earned under our fixed fee contracts. Compression services are billed monthly in advance of the service period and are recognized as deferred revenue on the balance sheet until earned.

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Recent Accounting Pronouncements

        In June 2009, the Financial Accounting Standards Board, or FASB, issued new guidance requiring an entity to perform an analysis to determine whether the entity's variable interest gives it a controlling financial interest in a variable interest entity. This analysis identifies the primary beneficiary of a variable interest entity as the entity that has both the power to direct the activities that most significantly impact the variable interest entity's economic performance and the obligation to absorb losses or the right to receive benefits from the variable interest entity. The new guidance also requires additional disclosures about a company's involvement in variable interest entities and any significant changes in risk exposure due to that involvement. The new guidance is effective for fiscal years beginning after November 15, 2009. Our adoption of this new guidance on January 1, 2010 did not have a material impact on our consolidated financial statements.

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

        In January 2010, FASB issued Accounting Standards Update 2010-06, Improving Disclosures about Fair Value Measurements, or ASU 2010-06, which amends FASB ASC Topic 820, Fair Value Measurements and Disclosures. ASU 2010-06 requires reporting entities to make new disclosures about recurring or nonrecurring fair-value measurements including significant transfers into and out of Level 1 and Level 2 fair-value measurements and information about purchases, sales, issuances, and settlements on a gross basis in the reconciliation of Level 3 fair-value measurements. ASU 2010-06 also clarifies existing fair-value measurement disclosure guidance about the level of disaggregation, inputs, and valuation techniques. We have evaluated ASU 2010-06 and determined that we are not currently impacted by the update.

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BUSINESS

Overview

        We are a growth-oriented Delaware limited partnership and, based on management's significant experience in the industry, we believe that we are one of the largest independent providers of compression services in the U.S. in terms of total compression unit horsepower. As of December 31, 2011, we had 722,201 horsepower in our fleet and 171,245 horsepower on order for delivery by September 30, 2012, of which 87,217 horsepower on order was committed under customer contracts. We employ a customer-focused business philosophy in partnering with our diverse customer base, which is comprised of producers, processors, gatherers and transporters of natural gas. Natural gas compression, a mechanical process whereby natural gas is compressed to a smaller volume, resulting in higher pressure, is an essential part of the production and transportation of natural gas. As part of our services, we engineer, design, operate, service and repair our compression units and maintain related support inventory and equipment. The compression units in our modern fleet are designed to be easily adaptable to fit our customers' dynamic compression requirements. By focusing on the needs of our customers and by providing them with reliable and flexible compression services, we are able to develop long-term relationships, which lead to more stable cash flows for our unitholders. From 2003 through 2011, our average horsepower utilization was over 90%. We have been providing compression services since 1998.

        We focus primarily on large-horsepower infrastructure applications. As of December 31, 2011, we estimate that over 90% of our revenue generating horsepower was deployed in large-volume gathering systems, processing facilities and transportation applications. We operate a modern fleet, with an average age of our compression units of less than five years. Our standard new-build compression unit is generally configured for multiple compression stages allowing us to operate our units across a broad range of operating conditions. This flexibility allows us to enter into longer-term contracts and reduces the redeployment risk of our horsepower in the field. Our modern and standardized fleet, decentralized field-level operating structure and technical proficiency in predictive and preventive maintenance and overhaul operations have enabled us to achieve average service run times consistently above the levels required by our customers.

        We generally provide our compression services to our customers under long-term, fixed-fee contracts, with initial contract terms of up to five years. We typically continue to provide compression services to our customers beyond their initial contract terms, either through contract renewals or on a month-to-month basis. Our customers are typically required to pay our monthly fee even during periods of limited or disrupted natural gas flows, which enhances the stability and predictability of our cash flows. We are not directly exposed to natural gas price risk because we do not take title to the natural gas we compress and because the natural gas used as fuel by our compression units is supplied by our customers without cost to us.

        We provide compression services in a number of shale plays, including the Fayetteville, Marcellus, Woodford, Barnett, Eagle Ford and Haynesville shales. We believe compression services for shale production will increase in the future. According to the Annual Energy Outlook 2012 Early Release Overview prepared by the EIA, natural gas production from shale formations will increase from 23% of total U.S. natural gas production in 2010 to 49% of total U.S. natural gas production in 2035. Not only are the production and transportation volumes in these and other shale plays increasing, but the geological and reservoir characteristics of these shales are also particularly attractive for compression services. The changes in production volume and pressure of shale plays over time result in a wider range of compression requirements than in conventional basins. We believe we are well-positioned to meet these changing operating conditions as a result of the flexibility our compression units. While our business focus is largely compression serving shale plays, we also provide compression services in more mature conventional basins. These conventional basins require increasing amounts of compression as

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they age and pressures decline, which we believe will provide an additional source of stable and growing cash flows for our unitholders.

        For the year ended December 31, 2011, our business generated revenues, net income and Adjusted EBITDA of $98.7 million, $0.1 million and $51.3 million, respectively. Please read "—Non-GAAP Financial Measures" for an explanation of Adjusted EBITDA, which is a non-GAAP financial measure, and a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented in accordance with GAAP.


Business Strategies

        Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing stability and growth of our business. We expect to achieve this objective by executing on the following strategies:

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Competitive Strengths

        We believe that we are well positioned to successfully execute our business strategies and achieve our principal business objective because of the following competitive strengths:

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Our Operations

        We provide compression services for a monthly service fee. As part of our services, we engineer, design, operate, service and repair our fleet of compression units and maintain related support inventory and equipment. We have consistently provided average service run times above the levels required by our customers. In general, our team of field service technicians service our compression fleet and do not service third-party owned equipment. We do not rent or lease our compressors to our customers and do not own any compression fabrication facilities.

        The fleet of compression units that we own and use to provide compression services consists of specially engineered compression units that utilize standardized components, principally engines manufactured by Caterpillar, Inc. and compressor frames and cylinders manufactured by Ariel Corporation. Our units can be rapidly and cost effectively modified for specific customer applications. Approximately 94% of our fleet horsepower at December 31, 2011 was purchased new and the average age of our compression units is less than five years. Our modern, standardized compressor fleet mainly consists of the Caterpillar 3508, 3512 and 3516 engine classes, which range from 630 to 1,340 horsepower per unit, and we are expanding our fleet to include the Caterpillar 3606 and 3608 engine class, which range from 1,775 to 2,352 horsepower per unit. These larger units, defined as 500 horsepower per unit or greater, represented approximately 84% of our fleet (including compression units on order) as of December 31, 2011. We believe the young age and overall composition of our compressor fleet results in fewer mechanical failures, lower fuel usage (a direct cost savings for our customers), and reduced environmental emissions.

        The following table provides a summary of our compression units by horsepower as of December 31, 2011 (including additional new compression unit horsepower on order for delivery between January 2012 and September 2012):

Unit Horsepower
  Fleet
Horsepower
  Horsepower
on Order(1)
  Total
Horsepower(2)
  Percentage of
Total
Horsepower
 

<500

    137,665     6,649     144,314     16.1 %

>500 <1,000

    102,664     14,940     117,604     13.2 %

>1,000

    481,872     149,656     631,528     70.7 %
                   

Total

    722,201     171,245     893,446     100.0 %
                   

(1)
61,134 of this horsepower is expected to be delivered between January 2012 and March 2012, 82,443 of this horsepower is expected to be delivered between April 2012 and June 2012 and 27,668 of this horsepower is expected to be delivered between July 2012 and September 2012.

(2)
Comprised of 1,162 compression units, including 145 new compression units on order.

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        The following table sets forth certain information regarding our compression fleet as of the dates and for the periods indicated:

 
  Predecessor   Successor  
 
  Year Ended
December 31,
   
 
 
  Year Ended
December 31, 2011
 
 
  2007   2008   2009   2010  

Operating Data (at period end, except averages)—unaudited

                               
 

Fleet horsepower(1)

    453,508     542,899     582,530     609,730     722,201  
 

Total available horsepower(2)

    476,698     568,359     582,530     612,410     809,418  
 

Revenue generating horsepower(3)

    405,807     496,606     502,177     533,692     649,285  
 

Average revenue generating horsepower(4)

    370,826     455,673     489,243     516,703     570,900  
 

Revenue generating compression units

    613     763     749     795     888  
 

Average horsepower per revenue generating compression unit(5)

    665     651     655     667     692  
 

Horsepower utilization(6)

                               
   

At period end

    93.7 %   95.2 %   92.0 %   91.8 %   95.7 %
   

Average for the period(7)

    93.9 %   95.9 %   92.7 %   92.6 %   92.3 %

(1)
Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order). As of December 31, 2011, we had 171,245 of additional new compression unit horsepower on order, of which 61,134 horsepower is expected to be delivered between January 2012 and March 2012, 82,443 horsepower is expected to be delivered between April 2012 and June 2012, and 27,668 horsepower is expected to be delivered between July 2012 and September 2012.

(2)
Total available horsepower includes revenue generating horsepower under contract for which we are billing a customer, horsepower in our fleet that is under contract but is not yet generating revenue, horsepower not yet in our fleet that is under contract not yet generating revenue that is subject to a purchase order and idle horsepower. Total available horsepower excludes new horsepower on order for which we do not have a compression services contract.

(3)
Revenue generating horsepower is horsepower under contract for which we are billing a customer.

(4)
Calculated as the average of the month-end revenue generating horsepower for each of the months in the period.

(5)
Calculated as the average of the month-end horsepower per revenue generating compression unit for each of the months in the period.

(6)
Horsepower utilization is calculated as (i)(a) revenue generating horsepower plus (b) horsepower in our fleet that is under contract, but is not yet generating revenue plus (c) horsepower not yet in our fleet that is under contract not yet generating revenue and will be fulfilled by horsepower subject to a purchase order divided by (ii) total available horsepower less idle horsepower that is under repair. Horsepower utilization based on revenue generating horsepower and fleet horsepower at each applicable period end was 89.5%, 91.5%, 86.2%, 87.5% and 89.9% for the years ended December 31, 2007, 2008, 2009, 2010 and 2011, respectively.

(7)
Calculated as the average utilization for the months in the period based on utilization at the end of each month in the period.

        A substantial majority of our compression units have electronic control systems that enable us, if specified by our customers, to monitor our units remotely by satellite or other means to supplement our technicians' on-site monitoring visits. Our compression units are designed to automatically shut down if operating conditions deviate from a pre-determined range. While we retain the care, custody, ongoing maintenance and control of our compression units, we allow our customers, subject to a defined protocol, to start, stop, accelerate and slow down compression units in response to field conditions.

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        We adhere to routine, preventive and scheduled maintenance cycles. Each of our compression units is subjected to rigorous sizing and diagnostic analyses, including lubricating oil analysis and engine exhaust emission analysis. We have proprietary field service automation capabilities that allow our service technicians to electronically record and track operating, technical, environmental and commercial information at the discrete unit level. These capabilities allow our field technicians to identify potential problems and act on them before such problems result in downtime.

        Generally, we expect each of our compression units to undergo a major overhaul between service deployment cycles once every eight to ten years for our larger horsepower units (500 horsepower or more) and on average every five years for smaller horsepower units. A major overhaul involves the periodic rebuilding of the unit to materially extend its economic useful life or to enhance the unit's ability to fulfill broader or more diversified compression applications. Because our compression fleet is comprised of units of varying horsepower that have been placed into service with staggered initial on-line dates, we expect that we will be able to schedule overhauls in a way to avoid excessive maintenance capital expenditures and minimize the revenue impact of downtime.

        We believe that our customers, by outsourcing their compression requirements, can increase their revenue by transporting or producing a higher volume of natural gas through decreased compression downtime and reduce their operating, maintenance and equipment costs by allowing us to manage efficiently their changing compression needs. We generally guarantee our customers availability ranging from 95% to 98%, depending on field level requirements.

        The following discussion describes the material terms generally common to our compression service contracts. We generally enter into a new contract with respect to each distinct application for which we will provide compression services.

        Term and termination.    Our contracts typically have an initial term between one and five years, after which the contract continues on a month-to-month basis until terminated by us or our customers upon notice as provided for in the applicable contract.

        Availability.    Our contracts often provide a guarantee of specified availability. We define availability as the percentage of time in a given period that our compression services are being provided or are capable of being provided. Availability is reduced by instances of "down-time" that are attributable to anything other than events of force majeure or acts or failures to act by the customer. "Down-time" under our contracts usually begins when our services stop being provided and when we receive notice of the problem. Down-time due to scheduled maintenance is also excluded from our availability commitment. As a consequence of our availability guarantee, we are incentivized to practice predictive and preventive maintenance on our fleet as well as promptly respond to a problem to meet our contractual commitments and ensure our customers the compression availability on which their business and our service relationship is based.

        Fees and expenses.    Our customers pay a fixed monthly fee for our services. We bill our customers 30 days in advance, and they are required to pay upon receipt of the invoice. We are not responsible for acts of force majeure, and our customers generally are required to pay our monthly fee even during periods of limited or disrupted throughput. We are generally responsible for the costs and expenses associated with operation and maintenance of our compression equipment, such as providing necessary lubricants, although certain fees and expenses are the responsibility of our customers under the terms of their contracts. For example, all fuel gas is provided by our customers without cost to us, and in many cases customers are required to provide all water and electricity, while lubricants in certain cases may be provided by the customer. We are also reimbursed by our customers for certain ancillary expenses such as trucking and crane, depending on the terms agreed to in the applicable contract, resulting in 0% gross operating margin.

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        Service standards and specifications.    We commit to provide compression services under service contracts that typically provide that we will supply all compression equipment, tools, parts, field service support and engineering. Our contracts do not govern the compression equipment we will use; instead, we determine what equipment is necessary to perform our contractual commitments.

        Title; Risk of loss.    We own or lease all compression equipment we use to provide compression services, and we normally bear the risk of loss or damage to our equipment and tools and injury or death to our personnel.

        Insurance.    Our contracts typically provide that both we and our customers are required to carry general liability, worker's compensation, employers' liability, automobile and excess liability insurance.

        Our marketing and client service functions are performed on a coordinated basis by our sales and field technicians. Salespeople and field technicians qualify, analyze and scope new compression applications as well as regularly visit our customers to ensure customer satisfaction, to determine a customer's current needs related to services currently being provided and to determine the customer's future compression services requirements. This ongoing communication allows us to quickly identify and respond to our customers' compression requirements. We currently focus on geographic areas where we can achieve economies of scale through high density operations.

        Our customers consist of more than 110 companies in the energy industry, including major integrated oil companies, public and private independent exploration and production companies and midstream companies. Our largest customer for the year ended December 31, 2010 and 2011 was Southwestern Energy Company and its subsidiaries, or Southwestern. Southwestern accounted for 18.7% of our revenue for the year ended December 31, 2010, and 15.9% of our revenue for the year ended December 31, 2011. Our ten largest customers accounted for 53% of our revenues for the year ended December 31, 2010, and the year ended December 31, 2011.

        The principal manufacturers of components for our natural gas compression equipment include Caterpillar (for engines), Air-X-Changers and Air Cooled Exchangers (for coolers), and Ariel Corporation (for compressor frames and cylinders). We also rely primarily on two vendors, A G Equipment Company and Standard Equipment Corp., to package and assemble our compression units. Although we rely primarily on these suppliers, we believe alternative sources for natural gas compression equipment are generally available if needed. However, relying on alternative sources may change the standardized nature of our fleet. We have not experienced any material supply problems to date, although lead-times for Caterpillar engines have in the past been in excess of one year due to increased demand and supply allocations imposed on equipment packagers and end-users by Caterpillar.

        The compression services business is highly competitive. Some of our competitors have a broader geographic scope, as well as greater financial and other resources than we do. On a regional basis, we experience competition from numerous smaller 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. Additionally, the current availability of attractive financing terms from financial institutions and equipment manufacturers makes the purchase of individual compression units increasingly affordable to our

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customers. We believe that we compete effectively on the basis of price, equipment availability, customer service, flexibility in meeting customer needs, quality and reliability of our compressors and related services.

        Our results of operations have not historically reflected any material seasonality, and we do not currently have reason to believe seasonal fluctuations will have a material impact in the foreseeable future.

        We believe that our insurance coverage is customary for the industry and adequate for our business. As is customary in the natural gas services industry, we review our safety equipment and procedures and carry insurance against most, but not all, risks of our business. Losses and liabilities not covered by insurance would increase our costs. The compression business can be hazardous, involving unforeseen circumstances such as uncontrollable flows of gas or well fluids, fires and explosions or environmental damage. To address the hazards inherent in our business, we maintain insurance coverage that includes physical damage coverage, third-party general liability insurance, employer's liability, environmental and pollution and other coverage, although coverage for environmental and pollution-related losses is subject to significant limitations. Under the terms of our standard compression services contract, we are responsible for the maintenance of insurance coverage on our compression equipment.

        We are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of human health, safety and the environment. These regulations include compliance obligations for air emissions, water quality, wastewater discharges and solid and hazardous waste disposal, as well as regulations designed for the protection of human health and safety and threatened or endangered species. 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. We are often obligated to obtain permits or approvals in our operations from various federal, state and local authorities, which permits and approvals can be denied or delayed, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue. Moreover, failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of remedial obligations, and the issuance of injunctions delaying or prohibiting operations. Private parties may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. While we believe that our operations are in substantial compliance with applicable environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, there is no assurance that this trend of compliance will continue in the future. In addition, the clear trend in environmental regulation is to place more restrictions on activities that may affect the environment, and thus, any changes in, or more stringent enforcement of, these laws and regulations that result in more stringent and costly pollution control equipment, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial position.

        We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. We cannot assure you, however, that future events, such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations or the development or discovery of new facts or conditions will not cause us to incur significant costs. The following is a discussion of

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material environmental and safety laws that relate to our operations. We believe that we are in substantial compliance with all of these environmental laws and regulations.

        Air emissions.    The CAA and comparable state laws regulate emissions of air pollutants from various industrial sources, including natural gas compressors, and also impose certain monitoring and reporting requirements. Such emissions are regulated by air emissions permits, which are applied for and obtained through the various state or federal regulatory agencies. Our standard natural gas compression contract typically provides that the customer is responsible for obtaining air emissions permits and assuming the environmental risks related to site operations. Increased obligations of operators to reduce air emissions of nitrogen oxides and other pollutants from internal combustion engines in transmission service have been enacted by governmental authorities. For example, 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, also known as Quad Z regulations. On January 5, 2011, the EPA approved a request by industry groups for reconsideration of the monitoring issues and on March 9, 2011, the EPA issued a new proposed rule and a direct final rule effective on May 9, 2011 to clarify compliance requirements related to operation and maintenance procedures for continuous parametric monitoring systems. The rule will require us to undertake certain expenditures and activities, likely including purchasing and installing emissions control equipment on compressor engines and generators. Compliance with the final rule is required by October 2013. We have budgeted approximately $2.0 million to meet these requirements before the October 2013 compliance date.

        On June 28, 2011, the EPA issued a final rule, effective August 29, 2011 modifying existing regulations under the CAA that established new source performance standards for manufacturers, owners and operators of new, modified and reconstructed stationary internal combustion engines, also known as Quad J regulations. The final rule may require us to undertake significant expenditures, including expenditures for purchasing, installing, monitoring and maintaining emissions control equipment. Compliance with the final rule is not required until at least 2013. We are currently evaluating the impact that this final rule will have on our operations.

        In March 2008, the EPA also promulgated a new, lower National Ambient Air Quality Standard, or NAAQS, for ground-level ozone, or NOx. While the EPA announced in September 2009 that it would reconsider the 2008 NAAQS for NOx, it withdrew the reconsideration on September 2, 2011. Under the CAA, the EPA will be required to review and potentially issue a new NAAQS for ground level NOx in 2013. Designation of new non-attainment areas for the revised ozone and NOx NAAQS may result in additional federal and state regulatory actions that could impact our customers' operations and increase the cost of additions to property, plant and equipment.

        On July 28, 2011, the EPA proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA's proposed rule package includes New Source Performance Standards to address emissions of sulfur dioxide and VOCs and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The proposed rules also would establish specific new requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. The EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on the rules by April 3, 2012. If finalized, these rules could require a number of modifications to our operations including the installation of new equipment to control emissions from our compressors. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business.

        In addition, the Texas Commission on Environmental Quality, or TCEQ, has finalized revisions to certain air permit programs that significantly increase the air permitting requirements for new and certain existing oil and gas production and gathering sites for 23 counties in the Barnett Shale

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

        There can be no assurance that future requirements compelling the installation of more sophisticated emission control equipment would not have a material adverse impact.

        Climate change.    Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases, or GHGs. In recent years, the U.S. Congress has considered legislation to reduce emissions of GHGs. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues. In addition, almost half of the states have begun to address GHG emissions, primarily through the planned development of emission inventories or regional GHG cap and trade programs. Depending on the particular program, we could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations.

        Independent of Congress, the U.S. Environmental Protection Agency, or the EPA, is beginning to adopt regulations controlling GHG emissions under its existing Clean Air Act authority. For example, on December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. These findings by the EPA allow the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. In 2009, the EPA adopted rules regarding regulation of GHG emissions from motor vehicles. In addition, on September 22, 2009, the EPA issued a final rule requiring the reporting of GHG emissions in the United States beginning in 2011 for emissions occurring in 2010 from specified large GHG emission sources. On November 30, 2010, the EPA published a final rule expanding its existing GHG emissions reporting rule for petroleum and natural gas facilities, including natural gas transmission compression facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year. The rule, which went into effect on December 30, 2010, requires reporting of GHG emissions by such regulated facilities to the EPA by September 2012 for emissions during 2011 and annually thereafter. In 2010, the EPA also issued a final rule, known as the "Tailoring Rule," that makes certain large stationary sources and modification projects subject to permitting requirements for GHG emissions under the Clean Air Act. Several of the EPA's GHG rules are being challenged in court and, depending on the outcome of these proceedings, such rules may be modified or rescinded or the EPA could develop new rules.

        Although it is not currently possible to predict how any such proposed or future greenhouse gas legislation or regulation by Congress, the states or multi-state regions will impact our business, any legislation or regulation of greenhouse gas emissions that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions or reduced demand for our services, and could have a material adverse effect on our business, financial condition, and results of operations.

        Water discharge.    The Clean Water Act, or CWA, and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is

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prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. The CWA also requires the development and implementation of spill prevention, control, and countermeasures, including the construction and maintenance of containment berms and similar structures, if required, to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak at such facilities. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. Our compression operations do not generate process wastewaters that are discharged to waters of the U.S. In any event, our customers assume responsibility under our standard natural gas compression contract for obtaining any discharge permits that may be required under the CWA.

        Safe drinking water act.    A portion of our customers' natural gas production is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of "underground injection" and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the Safe Drinking Water Act. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a multi-year study of the potential environmental impacts of hydraulic fracturing, the results of which are anticipated to be available by the end of 2012. EPA also has recently announced that it believes hydraulic fracturing using fluids containing diesel fuel can be regulated under the SDWA notwithstanding the SDWA's general exemption for hydraulic fracturing. Several states have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. We cannot predict whether any such legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation and permits were required through the adoption of new laws and regulations at the federal or state level, that could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of natural gas that move through our gathering systems which would materially adversely affect our revenue and results of operations.

        Solid waste.    The Resource Conservation and Recovery Act, or the RCRA, and comparable state laws control the management and disposal of hazardous and non-hazardous waste. These laws and regulations govern the generation, storage, treatment, transfer and disposal of wastes that we generate including, but not limited to, used oil, antifreeze, filters, sludges, paint, solvents, and sandblast materials. The EPA and various state agencies have limited the approved methods of disposal for these types of wastes.

        Site remediation.    The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, and comparable state laws impose strict, joint and several liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner and operator of a disposal site where a hazardous substance release occurred and any company that transported, disposed of, or arranged for the transport or disposal of hazardous substances released at the site. Under CERCLA, such persons may be liable for the costs of remediating 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 the neighboring landowners and other third parties to file claims for personal injury, property damage and recovery of

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response costs. While we generate materials in the course of our operations that may be regulated as hazardous substances, we have not received notification that we may be potentially responsible for cleanup costs under CERCLA at any site.

        While we do not currently own or lease any material facilities or properties for storage or maintenance of our inactive compression units, we may use third-party properties for such storage and possible maintenance and repair activities. In addition, our active compression units typically are placed on properties owned or leased by third-party customers and operated by us pursuant to terms set forth in the natural gas compression services contracts executed by those customers. Under most of our natural gas compression services contracts, our customers must contractually indemnify us for certain damages we may suffer as a result of the release into the environment of hazardous and toxic substances. We are not currently responsible for any remedial activities at any properties used by us; however, there is always the possibility that our future use of those properties may result in spills or releases of petroleum hydrocarbons, wastes, or other regulated substances into the environment that may cause us to become subject to remediation costs and liabilities under CERCLA, RCRA or other environmental laws. We cannot provide any assurance that the costs and liabilities associated with the future imposition of such remedial obligations upon us would not have a material adverse effect on our operations or financial position.

        Safety and health.    The Occupational Safety and Health Act, or OSHA, and comparable state laws strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and, as necessary, disclose information about hazardous materials used or produced in our operations to various federal, state and local agencies, as well as employees.

        We do not currently own or lease any material facilities or properties for storage or maintenance of our compression units. Our headquarters consists of 3,065 square feet of leased space located at 100 Congress Avenue, Suite 450, Austin, Texas 78701.

        We are managed and operated by the officers and directors of USA Compression GP, our general partner. As of December 31, 2011, we employed 214 people either directly or through USAC Operating. None of our employees are subject to collective bargaining agreements. We consider our employee relations to be good.

        From time to time we may be involved in litigation relating to claims arising out of our operations in the normal course of business. We are not currently a party to any legal proceedings that we believe would have a material adverse effect on our financial position, results of operations or cash flows.

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MANAGEMENT OF USA COMPRESSION PARTNERS, LP

        Our general partner, USA Compression GP, LLC, manages our operations and activities. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. As described in the Second Amended and Restated Limited Liability Company Agreement of USA Compression GP, LLC (the "GP Agreement"), USA Compression GP, LLC is member-managed. The sole member has delegated to the board of directors all power and authority related to management of the partnership to the fullest extent permitted by law and the GP Agreement. The GP Agreement provides that there shall be at least two and no more than nine directors, who will oversee our operations. The board of directors will elect one or more officers who will serve at the pleasure of the board. Unitholders will not be entitled to elect the directors of USA Compression GP, LLC or directly or indirectly participate in our management or operation.

        Upon the closing of our initial public offering, the board of directors of our general partner was comprised of five members, all of whom were designated by USA Compression Holdings and one of whom is independent as defined under the independence standards established by the New York Stock Exchange. In compliance with the rules of the New York Stock Exchange, a second independent director will be appointed to the board of directors of USA Compression GP, LLC within 90 days of listing and a third independent director will be appointed within twelve months of listing. The New York Stock Exchange does not require a listed limited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating committee.

        As set forth in the GP Agreement, USA Compression GP, LLC may, from time to time, have a conflicts committee to which the board of directors will appoint independent directors and which may be asked to review specific matters that the board believes may involve conflicts of interest between us, our limited partners and USA Compression Holdings. The conflicts committee will determine the resolution of the conflict of interest in any manner referred to it in good faith. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers, or employees of its affiliates, including USA Compression Holdings, and must meet the independence and experience standards established by the New York Stock Exchange and the Exchange Act to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. For a detailed discussion of the potential conflicts of interest we face and how they will be resolved, see "Conflicts of Interest and Fiduciary Duties—Conflicts of Interest."

        In addition, upon the closing of our initial public offering, USA Compression GP, LLC had an audit committee comprised of at least one director who meets the independence and experience standards established by the New York Stock Exchange and the Exchange Act. The audit committee assists the 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 the terms thereof, and pre-approve any non-audit services to be rendered 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 been given unrestricted access to the audit committee.

        Any person who is or was a member, partner, director, officer, affiliate, fiduciary or trustee of USA Compression GP, LLC, any person who is or was serving at the request of USA Compression GP, LLC or any affiliate of USA Compression GP, LLC as an officer, director, member, manager, partner, fiduciary or trustee of another person is entitled to indemnification under the GP Agreement for actions associated with such roles to the fullest extent permitted by law and the GP Agreement. The GP Agreement may be amended or restated at any time by the sole member.

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Directors and Executive Officers

        The following table shows information regarding the current directors and executive officers of USA Compression GP, LLC.

Name
  Age   Position with USA Compression GP, LLC

Eric D. Long

  53   President and Chief Executive Officer and Director

Joseph C. Tusa, Jr. 

  53   Vice President, Chief Financial Officer and Treasurer

J. Gregory Holloway

  54   Vice President, General Counsel and Secretary

David A. Smith

  49   Vice President and President, Northeast Region

Dennis J. Moody

  54   Vice President—Operations Services

Kevin M. Bourbonnais

  45   Vice President and Chief Operating Officer

William H. Shea, Jr. 

  57   Director

Andrew W. Ward

  45   Director

Olivia C. Wassenaar

  32   Director

        The directors of our general partner 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 the directors or executive officers of our general partner.

        Eric D. Long has served as our President and Chief Executive Officer since September 2002 and has served as a director of USA Compression GP, LLC since June 2011. Mr. Long co-founded USA Compression in 1998 and has over 30 years of experience in the oil and gas industry. From 1980 to 1987, Mr. Long served in a variety of technical and managerial roles for several major pipeline and oil and natural gas producing companies, including Bass Enterprises Production Co. and Texas Oil & Gas. Mr. Long then served in a variety of senior officer level operating positions with affiliates of Hanover Energy, Inc., a company primarily engaged in the business of gathering, compressing and transporting natural gas. In 1993, Mr. Long co-founded Global Compression Services, Inc., a compression services company. Mr. Long was formerly on the board of directors of the Wiser Oil Company, an NYSE listed company from May 2001 until it was sold to Forest Oil Corporation in May 2004. Mr. Long received his bachelor's degree, with honors, in Petroleum Engineering from Texas A&M University. He is a registered Professional Engineer in the state of Texas.

        As a result of his professional background, Mr. Long brings to us executive-level strategic, operational and financial skills. These skills, combined with his over 30 years of experience in the oil and natural gas industry, including in particular his experience in the compression services sector, make Mr. Long a valuable member of our board.

        Joseph C. Tusa, Jr. has served as our Vice President and Chief Financial Officer since joining us in January 2008. Mr. Tusa began his career with Arthur Andersen in Houston, Texas in its oil and gas exploration and production division. He then served as Chief Financial Officer of DSM Copolymer, Inc., a producer and global supplier of synthetic rubber. From 1997 to 2001, Mr. Tusa served as Senior Vice President of Business Operations for Metamor Worldwide, Inc., an IT services company that was listed on the NASDAQ exchange. From 2001 to December 2007, Mr. Tusa served as the Chief Financial Officer of Comsys IT Partners, Inc., an information technology staffing company and an affiliate of Metamor. Mr. Tusa received his BBA from Texas State University and his MBA from Louisiana State University. He is licensed as a Certified Public Accountant in the state of Texas.

        J. Gregory Holloway has served as our Vice President, General Counsel and Secretary since joining us in June 2011. From September 2005 through June 2011, Mr. Holloway was a partner at Thompson & Knight LLP in its Austin office. His areas of practice at the firm included corporate, securities and merger and acquisition law. Mr. Holloway received his B.A. from Rice University and his J.D., with honors, from the University of Texas School of Law.

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        David A. Smith has served as our President, Northeast Region since joining us in November 1998 and was appointed corporate Vice President in June 2011. Mr. Smith has approximately 20 years of experience in the natural gas compression industry, primarily in operations and sales. From 1985 to 1989, Mr. Smith was a sales manager for McKenzie Corporation, a marketing company. From 1989 to 1996, Mr. Smith held positions of General Manager and Regional Manager of Northeast Division with Compressor Systems Inc., a fabricator and supplier of compression services. Mr. Smith was the Regional Manager in the northeast for Global Compression Services, Inc., a compression services company, and served in that capacity from 1996 to 1998. Mr. Smith received an associates degree in Automotive and Diesel Technology from Rosedale Technical Institute.

        Dennis J. Moody has served as our Vice President—Operations Services since December 2011, as our General Manager, Central Region since December 2007 and previously served as sales manager since February 2002. Prior to this time, Mr. Moody served in positions of increasing responsibility since joining us in July 1999. Mr. Moody has over 30 years of experience with the operation, repair, sizing and sales of motor and electric driven compression equipment. From 1976 to 1979, Mr. Moody worked as an operator and repair mechanic and served on the overhaul crew at Mustang Fuel Corporation, an oil and gas company engaged in production, gathering, processing and marketing of natural gas. From 1979 to 1984, Mr. Moody managed the service, repair and parts distribution facilities for the drilling and industrial air compression distributors of Ingersoll-Rand and Sullair brand compressors in Oklahoma. From 1984 to July 1999, Mr. Moody served in an industrial and gas compression sales and sales support role at Bush Compression Industries, a fabricator of compression equipment.

        Kevin M. Bourbonnais has served as our Vice President and Chief Operating Officer since June 2011. Mr. Bourbonnais has approximately 12 years of experience in the natural gas compression industry, in operations, marketing, manufacturing, engineering and sales. Mr. Bourbonnais served in various roles for the Royal Bank of Canada from 1990 to 1999. In 1999, he moved to Weatherford Global Compression, which was acquired by a predecessor to Exterran Holdings, Inc. in 2001. Mr. Bourbonnais was named Senior Vice President, Manufacturing in 2003, Senior Vice President, Operations in March 2007, Regional Vice President, Western Division in August 2007 and Vice President, Marketing & Product Strategy in January 2010, in which role he served until June 2011. Mr. Bourbonnais received a BA and an MBA from the University of Calgary in 1989 and 2000, respectively.

        William H. Shea, Jr. has served as a director of USA Compression GP, LLC since June 2011. Mr. Shea served as the President and Chief Operating Officer of Buckeye GP LLC and its predecessor entities, or Buckeye, from July 1998 to September 2000, as President and Chief Executive Officer of Buckeye from September 2000 to July 2007, and Chairman from May 2004 to July 2007. From August 2006 to July 2007, Mr. Shea served as Chairman of MainLine Management LLC, the general partner of Buckeye GP Holdings, L.P., and as President and Chief Executive Officer of MainLine Management LLC from May 2004 to July 2007. Mr. Shea served as a director of Penn Virginia Corp. from July 2007 to May 2010, and as President, Chief Executive Officer and director of the general partner of Penn Virginia GP Holdings, L.P. from March 2010 to March 2011. Mr. Shea has served as a director and the Chief Executive Officer of the general partner of Penn Virginia Resource Partners, L.P., or Penn Virginia, since March 2010. Mr. Shea has also served as a director of Kayne Anderson Energy Total Return Fund, Inc., and Kayne Anderson MLP Investment Company since March 2008 and Niska Gas Storage Partners LLC since May 2010. Mr. Shea has an agreement with Riverstone, pursuant to which he has agreed to serve on the boards of certain Riverstone portfolio companies. Mr. Shea received his B.A. from Boston College and his M.B.A. from the University of Virginia.

        Mr. Shea's experiences as an executive with both Penn Virginia and Buckeye, energy companies that operate across a broad spectrum of sectors, including coal, natural gas gathering and processing and refined petroleum products transportation, have given him substantial knowledge about our

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industry. In addition, Mr. Shea has substantial experience overseeing the strategy and operations of publicly-traded partnerships. As a result of this experience and resulting skills set, we believe Mr. Shea is a valuable member of our board.

        Andrew W. Ward has served as a director of USA Compression GP, LLC since June 2011. Mr. Ward has served as a Principal of Riverstone from 2002 until 2004, as a Managing Director since January 2005 and as a Partner and Managing Director since July 2009, where he focuses on the firm's investment in the midstream sector of the energy industry. Mr. Ward served on the boards of directors of Buckeye and MainLine Management LLC from May 2004 to June 2006. Mr. Ward has also served on the board of directors of Gibson Energy Inc. since 2008 and Niska Gas Storage Partners LLC since May 2006. Mr. Ward received his AB from Dartmouth College and received his M.B.A from the UCLA Anderson School of Management.

        Mr. Ward's experience in evaluating the financial performance and operations of companies in our industry make him a valuable member of our board. In addition, Mr. Ward's work with Gibson Energy, Inc., Buckeye and Niska Gas Storage Partners LLC has given him both an understanding of the midstream sector of the energy business and of the unique issues related to operating publicly-traded limited partnerships.

        Olivia C. Wassenaar has served as a director of USA Compression GP, LLC since June 2011. Ms. Wassenaar was an Associate with Goldman, Sachs & Co. in the Global Natural Resources investment banking group from July 2007 to August 2008, where she focused on mergers, equity and debt financings and leveraged buyouts for energy, power and renewable energy companies. Ms. Wassenaar joined Riverstone in September 2008 as Vice President, and has served as a Principal since May 2010. In this capacity, she invests in and monitors investments in the midstream, exploration & production, and solar sectors of the energy industry. Ms. Wassenaar has also served on the board of directors of Northern Blizzard Resources Inc. since June 2011. Ms. Wassenaar received her A.B., magna cum laude, from Harvard College and earned an M.B.A. from the Wharton School of the University of Pennsylvania.

        Ms. Wassenaar's experience in evaluating financial and strategic options and the operations of companies in our industry and as an investment banker make her a valuable member of our board.


Reimbursement of Expenses of Our General Partner

        Our general partner does not receive any management fee or other compensation for its management of us. Our general partner and its affiliates are reimbursed for all expenses incurred on our behalf, including the compensation of employees of USA Compression GP, LLC or its affiliates that perform services on our behalf. These expenses include all expenses necessary or appropriate to the conduct of our business and that are allocable to us. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. There is no cap on the amount that may be paid or reimbursed to our general partner or its affiliates for compensation or expenses incurred on our behalf.


Compensation Discussion and Analysis

Executive Summary

        This Compensation Discussion and Analysis provides an overview and analysis of the executive compensation program for our named executive officers identified below. Our general partner intends to provide our named executive officers with compensation that is significantly performance based. The executive compensation program is designed to align executive pay with performance on both short and long-term bases, link executive pay to specific, measurable results intended to create value for

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unitholders and utilize compensation as a tool to assist our general partner in attracting and retaining the high-caliber executives that our general partner believes are critical to its long-term success.

        Compensation for our named executive officers consists primarily of the elements, and their corresponding objectives, identified in the following table.

Compensation Element
  Primary Objective

Base salary

  To recognize performance of job responsibilities and to attract and retain individuals with superior talent.

Annual performance-based compensation

  To promote near-term performance objectives and reward individual contributions to the achievement of those objectives.

Discretionary long-term equity incentive awards

  To emphasize long-term performance objectives, encourage the maximization of unitholder value and retain key executives by providing an opportunity to participate in the ownership of our partnership.

Severance benefits

 

To encourage the continued attention and dedication of key individuals and to focus the attention of key individuals when considering strategic alternatives.

Retirement savings (401(k)) plan

 

To provide an opportunity for tax-efficient savings.

Other elements of compensation and perquisites

 

To attract and retain talented executives in a cost-efficient manner by providing benefits with high perceived values at relatively low cost.

        To serve the foregoing objectives, our overall compensation program is generally designed to be adaptive rather than purely formulaic. For 2011, the non-employee members of the USA Compression Holdings Board of Managers had primary authority to determine and approve compensation decisions with respect to our named executive officers. In alignment with the objectives set forth above, the Board of Managers of USA Compression Holdings determined overall compensation, and its allocation among the elements described above, in reliance upon the judgment and general industry knowledge of its members obtained through years of service with comparably sized companies in our and similar industries. Going forward, our named executive officers will be employed and their compensation will be paid by our general partner, subject to reimbursement by us. The compensation of our named executive officers will be determined by the board of directors of our general partner in a manner and based on considerations that we currently expect will be similar to the considerations set forth in this Compensation Discussion and Analysis.

        For the year ended December 31, 2011, our named executive officers, or our NEOs, were:

Our compensation decisions for the NEOs in 2011 are discussed below in relation to each of the above-described elements of our compensation program. The below discussion is intended to be read in

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conjunction with the executive compensation tables and related disclosures that follow this Compensation Discussion and Analysis.


Compensation Overview

        The overall compensation program for our NEOs is structured to attract, motivate and retain highly qualified executive officers by paying them competitively, consistent with our success and their contribution to that success. Our general partner believes compensation should be structured to ensure that a significant portion of compensation opportunity will be related to factors that directly and indirectly influence unitholder value. Consistent with our performance-based philosophy, our NEOs receive a competitive base salary and significant incentive-based compensation, which includes variable awards under our annual incentive bonus programs based on financial and operational performance and each NEO's individual performance, as well as equity-based incentives, which are meant to align our NEOs' interests with our long-term performance.

        Total compensation for our NEOs has been allocated between cash and equity compensation, taking into consideration the balance between providing short-term incentives and long-term investment in our financial performance, to align the interests of management with the interests of unitholders. The variable annual incentive bonus awards and the equity-based awards are designed to ensure that total compensation reflects our overall success or failure and to motivate the NEOs and reward their performance, thereby maximizing total return to unitholders. In anticipation of our initial public offering, we intend to adopt a new long-term equity incentive plan, or the LTIP, and which is discussed in more detail under "2012 Long-Term Incentive Plan" below.


Determination of Compensation Awards

        In determining compensation levels for our NEOs, the Board of Managers of USA Compression Holdings has considered each NEO's unique position and responsibility and has relied upon the judgment and industry experience of its members, including their knowledge of competitive compensation levels in our industry. The Board of Managers of USA Compression Holdings believes that executive officer base salaries should be competitive with salaries for executive officers in similar positions and with similar responsibilities in our industry. In this regard, each executive officer's current and prior compensation, including compensation paid by the NEO's prior employer, is considered as a reference point against which determinations are made as to whether increases are appropriate to retain the NEO in light of competition or in order to provide continuing performance incentives. With respect to NEOs other than our Chief Executive Officer, compensation determinations have typically followed our Chief Executive Officer's recommendations.

        In making compensation determinations, the Board of Managers of USA Compression Holdings has not made regular use of benchmarking or of compensation consultants. Rather, in alignment with the considerations described above, the Board of Managers of USA Compression Holdings determined the total amount of compensation for our NEOs and the allocation of total compensation among each of our main components of compensation, generally in reliance upon the judgment and general industry knowledge of its members obtained through years of service with comparably sized companies in our industry and other similar industries, and, with respect to equity incentive awards granted to our NEOs in December 2010 in connection with the Holdings Acquisition, based on individual negotiations with our Chief Executive Officer on behalf of himself and our other NEOs. Going forward, compensation determinations will be made by the board of directors of our general partner, and we expect that the board of directors of our general partner will rely on the same considerations historically used by the Board of Managers of USA Compression Holdings.

        Our general partner currently has no formal policy with respect to requiring officers and directors to own our equity interests. However, we historically have encouraged substantial equity ownership by

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our NEOs and each of our NEOs made a substantial equity investment in USA Compression Holdings in connection with the Holdings Acquisition in December 2010. USA Compression Holdings has further provided for additional equity participation by NEOs by granting to such NEOs Class B Units in USA Compression Holdings at the time of the Holdings Acquisition. We believe that equity ownership by NEOs encourages retention and provides our NEOs with a strong incentive to increase unitholder value.


Base Compensation For 2011

        Base salaries for our NEOs have generally been set at a level deemed necessary to attract and retain individuals with superior talent. In determining the initial base salary for Mr. Bourbonnais, who joined us in June 2011, the Board of Managers of USA Compression Holdings considered Mr. Bourbonnais' level of experience in the industry, compensation level in his prior position and relative level of seniority and responsibility within our organization. Base salary increases are determined based upon the job responsibilities, demonstrated proficiency and performance of the executive officers and market conditions, each as assessed by the Board of Managers of USA Compression Holdings. No formulaic base salary increases are provided to the NEOs. Additionally, no changes to base salaries for our NEOs were made for the fiscal year ended December 31, 2011.

        The base salaries for our NEOs, including for our Chief Executive Officer, are set forth in the following table:

Name and Principal Position
  2011
Base Salary
($)
 

Eric D. Long

    400,000  
 

President and Chief Executive Officer

       

Joseph C. Tusa, Jr. 

    275,000  
 

Vice President, Chief Financial Officer and Treasurer

       

Kevin M. Bourbonnais

    275,000  
 

Vice President and Chief Operating Officer

       

David A. Smith

    250,000  
 

Vice President and President, Northeast Region

       

Dennis J. Moody

    145,000  
 

Vice President—Operations Services

       


Annual Performance-Based Compensation For 2011

        The compensation programs for our NEOs are structured to reward executive officers based on our performance and the individual executive's relative contribution to that performance. This allows executive officers to be eligible to receive incentive bonus compensation based on our operational and financial success and their individual performance for each year. The annual incentive bonuses for the year ended December 31, 2011 were determined by the Board of Managers of USA Compression Holdings.

        Our NEOs participate in a discretionary annual incentive bonus compensation program, under which incentive awards are determined annually, with reference to target bonus amounts that are set forth in the NEOs' employment agreements. For 2011, the target bonus amounts for each of our NEOs were as follows: Mr. Long: $300,000; Mr. Tusa: $110,000, Mr. Bourbonnais: $76,096 (prorated to reflect a partial employment year); Mr. Smith: $120,000; and Mr. Moody: $125,000. In making individual annual bonus decisions, the Board of Managers of USA Compression Holdings, following the recommendations of our Chief Executive Officer, does not rely on pre-determined performance goals or targets. Instead, determinations regarding annual bonus compensation awards are based on a

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subjective assessment of all reasonably available information, including the applicable NEO's performance, business impact, contributions and leadership.

        For 2011, our general partner's Board of Managers determined to provide each NEO with a 2011 annual bonus award at or above the NEO's target bonus, generally based on what it viewed as strong leadership and overall financial performance during a transitional year for our company as we operated under new ownership and prepared for our initial public offering. In addition, the Board of Managers sought to reward our NEOs for our operational results and increased sales activity during the second half of 2011, which we believe left us well positioned for growth in 2012. As a result of these considerations, Messrs. Long and Bourbonnais each received an annual incentive award equal to 100% of their target amounts (pro-rated for Mr. Bourbonnais' partial year of service) and Messrs. Smith and Moody each received 125% and 120% of their target amounts in recognition of their strong sales performance during the second half of 2011. Mr. Tusa received an award equal 136% of his target bonus in recognition of his extraordinary service and dedication in preparing us to become a publicly-traded company, which substantially expanded the scope of his duties in 2011.

        Awards in 2011 were:

Eric D. Long   $ 300,000  
Joseph C. Tusa, Jr.    $ 150,000  
Kevin M. Bourbonnais   $ 76,096 (1)
David A. Smith   $ 150,000  
Dennis J. Moody   $ 150,000  

(1)
Prorated to reflect a partial employment year.

        Mr. Smith also receives commissions in an amount up to $200,000 annually based on a percentage of qualifying sales. Based on sales performance in 2011, as in prior recent years, Mr. Smith earned the maximum potential amount of commissions available under this arrangement.


Discretionary Long-Term Equity Incentive Awards

        Prior to the Holdings Acquisition, our NEOs (other than Mr. Bourbonnais, who joined us after the Holdings Acquisition) historically received various forms of equity compensation, in the form of both capital and profits interests in us and our predecessor entities, and in connection with the Holdings Acquisition, each of our NEOs (other than Mr. Bourbonnais) re-invested a substantial portion of the cash proceeds received in respect of his prior equity interests in certain classes of capital or profit interest units in USA Compression Holdings.

        Our NEOs (other than Mr. Bourbonnais) were also granted Class B Units of USA Compression Holdings at the time of the Holdings Acquisition. In connection with the Holdings Acquisition in December 2010, the Board of Managers also reserved additional Class B Units for future grants to NEOs and other key employees. A portion of these Class B Units were awarded to Kevin Bourbonnais in connection with the commencement of his employment with us in June 2011.

        The Class B Units are profits interests that allow our NEOs to participate in the increase in value of USA Compression Holdings over and above an 8% annual and cumulative preferred return hurdle. The grants have time-based vesting requirements and are designed to not only compensate but also to motivate and retain the recipients by providing an opportunity for equity ownership by our NEOs. The grants to our NEOs also promote long-term compensation objectives and increase long-term unitholder value by providing our NEOs with meaningful incentives to increase unitholder value over time.

        Generally, the Class B Units have vesting schedules that are designed to encourage NEOs' continued employment or service with USA Compression Holdings or one of its affiliates, including us

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and our general partner. The Class B Units generally (i) vest twenty-five percent on the first anniversary of the date of grant (December 31, 2011 for grants made at the time of the Holdings Acquisition) and (ii) with respect to the remaining Class B Units, will vest in thirty-six monthly installments thereafter, subject to the NEO's continued employment on each applicable vesting date. See "—Potential Payments upon Termination or Change in Control" below for a description of the circumstances under which vesting of the Class B Units may be accelerated, including in connection with our initial public offering. In determining the amount of the Class B Unit grants for each NEO, the Board of Managers considered a number of factors, such as its view of the relative scope of the NEO's duties and responsibilities, individual performance history and the ability to contribute to the increase in equity value. The specific amount of the Class B Unit awards to each of our NEOs is set forth in the "—Grants of Plan Based Awards" table below.


Employment and Severance Arrangements

        The Board of Managers of USA Compression Holdings considers the maintenance of a sound management team to be essential to protecting and enhancing our best interests. To that end, it has recognized that the uncertainty that may exist among management with respect to their "at-will" employment may result in the departure or distraction of management personnel to the detriment of our partnership. Accordingly, the Board of Managers of USA Compression Holdings has determined that severance arrangements are appropriate to encourage the continued attention and dedication of our NEOs and to allow them to focus on the value to unitholders of strategic alternatives without concern for the impact on their continued employment. Each NEO currently has an employment agreement with USAC Operating which provides for severance benefits upon termination of employment. In connection with the consummation of our initial public offering, our general partner expects to enter into new employment agreements with each of our NEOs on terms that are substantially similar to these employment agreements. As described below, these agreements are substantially similar for each of the NEOs.

        Each NEO's employment agreement, dated as of December 23, 2010 or, with respect to Mr. Bourbonnais, June 13, 2011, has an initial four-year term and is extended automatically for successive twelve-month periods thereafter unless either party delivers written notice to the other within ninety days prior to the expiration of the then-current employment term. Upon termination of an NEO's employment either by us for convenience or due to the NEO's resignation for good reason, subject to the timely execution of a general release of claims, the NEO is entitled to receive (i) an amount equal to one times his annual base salary, payable in equal semi-monthly installments over one year following termination (or, if such termination occurs within two years following a change in control, in a lump sum within thirty days following the termination of employment) and (ii) continued coverage for twenty-four months (or, with respect to Mr. Long, thirty months) under our group medical plan in which the executive and any of his dependents were participating immediately prior to his termination. Continued coverage under our group medical plan is subsidized for the first twelve months following termination, and Mr. Long is entitled to reimbursement by us to the extent the cost of such coverage exceeds $1,200 per month for the remainder of the applicable period. Additionally, upon a termination of an NEO's employment by us for convenience, by the NEO for good reason, or due to the NEO's death or disability, the NEO is entitled to receive a pro-rata portion of any earned annual bonus for the year in which termination occurs (calculated with reference to the performance targets established by the Board of Managers of USA Compression Holdings for that year). During employment and for two years following termination, each NEO's employment agreement prohibits him from competing with certain of our businesses.

        As used in the NEOs' employment agreements, a termination for "convenience" means an involuntary termination for any reason, including a failure to renew the employment agreement at the end of an initial term or any renewal term, other than a termination for "cause." "Cause" is defined in

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the NEOs' employment agreements to mean (i) any material breach of the employment agreement or the Amended and Restated Limited Liability Company Agreement of USA Compression Holdings, or the Holdings Operating Agreement, by the executive, (ii) the executive's breach of any applicable duties of loyalty to us or any of our affiliates, gross negligence or misconduct, or a significant act or acts of personal dishonesty or deceit, taken by the executive, in the performance of the duties and services required of the executive that has a material adverse effect on us or any of our affiliates, (iii) conviction or indictment of the executive of, or a plea of nolo contendere by the executive to, a felony, (iv) the executive's willful and continued failure or refusal to perform substantially the executive's material obligations pursuant to the employment agreement or the Holdings Operating Agreement or follow any lawful and reasonable directive from the Board of Managers of USA Compression Holdings or, as applicable, the Chief Executive Officer, other than as a result of the executive's incapacity, or (v) a pattern of illegal conduct by the executive that is materially injurious to us or any of our affiliates or our or their reputation.

        "Good reason" is defined in the NEOs' employment agreements to mean (i) a material breach by us of the employment agreement, the Holdings Operating Agreement, or any other material agreement with the executive, (ii) any failure by us to pay to the executive the amounts or benefits to which he is entitled, other than an isolated and inadvertent failure not committed in bad faith, (iii) a material reduction in the executive's duties, reporting relationships or responsibilities, (iv) a material reduction by us in the facilities or perquisites available to the executive or in the executive's base salary, other than a reduction that is generally applicable to all similarly situated employees, or (v) the relocation of the geographic location of the executive's principal place of employment by more than fifty miles from the location of the executive's principal place of employment as of December 23, 2010 or, with respect to Mr. Bourbonnais, June 13, 2011. With respect to Mr. Long's employment agreement, "good reason" also means the failure to appoint and maintain Mr. Long in the office of President and Chief Executive Officer.


Benefit Plans and Perquisites

        We provide our executive officers, including our NEOs, with certain personal benefits and perquisites, which we do not consider to be a significant component of executive compensation but which we recognize are an important factor in attracting and retaining talented executives. Executive officers are eligible under the same plans as all other employees with respect to our medical, dental, vision, disability and life insurance plans and a defined contribution plan that is tax-qualified under Section 401(k) of the Internal Revenue Code and that we refer to as the 401(k) Plan. We also provide certain executive officers with an annual automobile allowance. We provide these supplemental benefits to our executive officers due to the relatively low cost of such benefits and the value they provide in assisting us in attracting and retaining talented executives. The value of personal benefits and perquisites we provide to each of our NEOs is set forth below in our "—Summary Compensation Table."


Summary Compensation Table

        The following table sets forth certain information with respect to the compensation paid to our NEOs for the years ended December 31, 2010 and 2011. For Mr. Bourbonnais, the amounts set forth in the table below reflect the portion of his compensation actually paid by us during fiscal year 2011,

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calculated by prorating each element of his annual compensation based on the length of time he was employed by us during such year.

Name and Principal Position
  Year   Salary ($)   Unit Awards
($)(1)
  Non-Equity Incentive Plan
Compensation ($)(3)
  All Other
Compensation ($)
  Total ($)  

Eric D. Long

    2011     400,961         300,000     26,461 (5)   727,422  
 

President and Chief

    2010     350,000     244,200 (2)   350,000     163,309 (6)   1,107,509  
 

Executive Officer

                                     

Joseph C. Tusa, Jr. 

   
2011
   
275,000
   
   
150,000
   
6,346

(7)
 
431,346
 
 

Vice President Chief

    2010     277,885         110,000     5,798 (8)   393,683  
 

Financial Officer and Treasurer

                                     

Kevin M. Bourbonnais

   
2011
   
153,365

(4)
 
   
76,096

(4)
 
2,730

(9)
 
232,191
 
 

Vice President and Chief

    2010                      
 

Operating Officer

                                     

David A. Smith

   
2011
   
250,000
   
   
350,000
   
17,060

(10)
 
617,060
 
 

Vice President and

    2010     250,000         320,000     17,060 (11)   587,060  
 

President, Northeast Region

                                     

Dennis J. Moody

   
2011
   
145,000
   
   
150,000
   
13,208

(12)
 
308,208
 
 

Vice President—Operations

    2010     145,000         125,000     11,967 (13)   281,967  
 

Services

                                     

(1)
On June 15, 2011, Mr. Bourbonnais, and on December 23, 2010, each of our other named executive officers, received awards of Class B Units in USA Compression Holdings in the amounts set forth below in the table under the heading "—Grants of Plan Based Awards." The Class B Units are intended to allow recipients to receive a percentage of profits generated by USA Compression Holdings over and above certain return hurdles, as described in more detail in the discussion under the heading "—Discretionary Long Term Equity Incentive Awards" above. In accordance with FASB ASC Topic 718, we recognized a grant date fair value of $0 with respect to these awards and will recognize no dollar amount with respect to the Class B Units for financial reporting purposes unless and until the fair value of the Class B Units exceeds the grant date fair value.

(2)
Amount shown reflects an estimate of the grant date fair value of the Class C Units in a predecessor entity granted to Mr. Long pursuant to the provisions of his prior employment agreement, as determined in accordance with FASB ASC Topic 718.

(3)
Represents the awards earned under annual incentive bonus programs and commission programs, as applicable, for the years ended December 31, 2010 and 2011. For a discussion of the determination of the 2011 bonus amounts, see "—Annual Performance-Based Compensation for 2011" above.

(4)
Prorated to reflect a partial year of employment during 2011.

(5)
Includes $18,000 of automobile allowance and $8,461 of employer contributions under the 401(k) plan.

(6)
Includes $18,000 of automobile allowance, $8,038 of employer contributions under the 401(k) plan and a tax reimbursement payment of $137,271 provided to Mr. Long in connection with the income and employment taxes incurred by him as a result of the equity award granted to him by the predecessor board in 2010, as described in more detail above under the heading "—Discretionary Long Term Equity Incentive Awards."

(7)
Includes $6,346 of employer contributions under the 401(k) plan.

(8)
Includes $5,798 of employer contributions under the 401(k) plan.

(9)
Includes $2,730 of employer contributions under the 401(k) plan.

(10)
Includes $9,960 of automobile allowance and $7,100 of employer contributions under the 401(k) plan.

(11)
Includes $9,960 of automobile allowance and $7,100 of employer contributions under the 401(k) plan.

(12)
Includes $8,600 of automobile allowance and $4,608 of employer contributions under the 401(k) plan.

(13)
Includes $8,600 of automobile allowance and $3,367 of employer contributions under the 401(k) plan.

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Grants of Plan-Based Awards

        The following table sets forth for each of our NEOs the target amount of non-equity incentive plan awards granted under our annual incentive bonus compensation program as well as the Class B Unit awards in USA Compression Holdings granted, in each case for the fiscal year ended December 31, 2011.