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North American Construction GroupTable of Contents UNITED STATES SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549 Form 10-K (Mark One) xx ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF1934 For the fiscal year ended December 31, 2013 or oo TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGEACT OF 1934 For the transition period from to Commission file number: 001-35779 USA Compression Partners, LP(Exact Name of Registrant as Specified in its Charter) Delaware75-2771546(State or Other Jurisdiction of Incorporation or Organization)(I.R.S. Employer Identification No.) 100 Congress Avenue, Suite 450Austin, TX78701(Address of Principal Executive Offices)(Zip Code) (512) 473-2662(Registrant’s telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Title of each className of each exchange on which registeredCommon Units representing Limited Partner InterestsNew York Stock Exchange Securities registered pursuant to Section 12(g) of the Act:None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No x Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filingrequirements for the past 90 days. Yes x No o Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data Filerequired to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant wasrequired to submit and post such files). Yes x No o Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to thebest of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment tothis Form 10-K. 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. Seethe definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Large accelerated filer oAccelerated filer o Non-accelerated filer xSmaller reporting company o(Do not check if a smaller reporting company) Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x The aggregate market value of common units held by non-affiliates of the registrant (treating directors and executive officers of the registrant’s generalpartner and holders of 5% or more of the common units outstanding, for this purpose, as if they were affiliates of the registrant) as of June 28, 2013, the lastbusiness day of the registrant’s most recently completed second fiscal quarter was $258,535,875. This calculation does not reflect a determination that suchpersons are affiliates for any other purpose. As of February 18, 2014, there were 24,034,240 common units and 14,048,588 subordinated units outstanding. DOCUMENTS INCORPORATED BY REFERENCE: NONE Table of Contents Table of Contents PART I1 Item 1.Business1Item 1A.Risk Factors12Item 1B.Unresolved Staff Comments30Item 2.Properties30Item 3.Legal Proceedings30Item 4.Mine Safety Disclosures30 PART II30 Item 5.Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities30Item 6.Selected Financial Data33Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations37Item 7A.Quantitative and Qualitative Disclosures About Market Risk50Item 8.Financial Statements and Supplementary Data50Item 9.Changes in and Disagreements With Accountants on Accounting and Financial Disclosure50Item 9A.Controls and Procedures50Item 9B.Other Information51 PART III51 Item 10.Directors, Executive Officers and Corporate Governance51Item 11.Executive Compensation57Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters64Item 13.Certain Relationships and Related Transactions, and Director Independence67Item 14.Principal Accountant Fees and Services69 PART IV69 Item 15.Exhibits and Financial Statement Schedules69 i Table of Contents PART I DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS This report contains “forward-looking statements.” All statements other than statements of historical fact contained in this report are forward-lookingstatements, including, without limitation, statements regarding our plans, strategies, prospects and expectations concerning our business, results of operationsand financial condition. You can identify many of these statements by looking for words such as “believe,” “expect,” “intend,” “project,” “anticipate,”“estimate,” “continue” or similar words or the negative thereof. Known material factors that could cause our actual results to differ from those in these forward-looking statements are described below, in Part I, Item 1A(“Risk Factors”) and Part II, Item 7 (“Management’s Discussion and Analysis of Financial Condition and Results of Operations”) of this report. Importantfactors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things: · changes in general economic conditions; · competitive conditions in our industry; · changes in the long-term supply of and demand for crude oil and natural gas; · our ability to realize the anticipated benefits of acquisitions and to integrate the acquired assets with our existing fleet; · actions taken by our customers, competitors and third-party operators; · changes in the availability and cost of capital; · operating hazards, natural disasters, weather related delays, casualty losses and other matters beyond our control; · the effects of existing and future laws and governmental regulations; and · the effects of future litigation. All forward-looking statements included in this report are based on information available to us on the date of this report. Except as required by law, weundertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. Allsubsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by theforegoing cautionary statements. ITEM 1. Business References in this report to “USA Compression,” “we,” “our,” “us,” “the Partnership” or like terms refer to USA Compression Partners, LPand its wholly owned subsidiaries, including USA Compression Partners, LLC (“USAC Operating”) and USAC OpCo 2, LLC (“OpCo 2” andtogether with USAC Operating, the “Operating Subsidiaries”). References to “USA Compression Holdings” refer to USA Compression Holdings,LLC, the owner of USA Compression GP, LLC, our general partner. References to our “general partner” refer to USA Compression GP, LLC.References to USAC Management refer to USA Compression Management Services, LLC, a wholly owned subsidiary of 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. 1 Table of Contents 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 thelargest independent providers of compression services in the U.S. in terms of total compression unit horsepower. We have been providing compression servicessince 1998. As of December 31, 2013, we had 1,202,374 horsepower in our fleet and approximately 180,000 horsepower on order for expected deliveryprimarily in the first half of 2014. Our primary focus is to provide compression services to our customers in connection with infrastructure applications.Natural gas compression is a mechanical process whereby natural gas is compressed to a smaller volume, resulting in higher pressure. This process hasvarious applications, including both allowing for the transportation of the natural gas through the domestic pipeline system and enhancing crude oilproduction through artificial lift processes. As such, our compression services play a critical role in the production and transportation of both natural gas andcrude oil. We provide compression services in a number of shale plays throughout the U.S., including the Marcellus, Eagle Ford, Utica, Mississippi Lime, GraniteWash, Woodford, Barnett, Permian Basin, Haynesville and Fayetteville shales. Because the demand for our services is driven by production of natural gasand crude oil, we have focused our activities in areas of attractive growth, which are generally found in these shale and unconventional resource plays. Further, we believe production in these areas will increase in the future. According to the Annual Energy Outlook 2013 (the “2013 Outlook”) prepared by theEnergy Information Agency (“EIA”), natural gas production from shale formations is expected to increase from 34% of total U.S. natural gas production in2011 to 50% of total U.S. natural gas production in 2040. In addition, the EIA forecasts in its 2013 Outlook that total domestic crude oil production willincrease by 33% from 2011 to 2019, and more importantly, forecasts tight oil production to increase by 128% over the same time period. Not only are theproduction and transportation volumes in these and other shale plays increasing, the geological and reservoir characteristics are also particularly attractive forcompression services. The changes in production volume and pressure of shale plays over time result in a wider range of compression requirements than inconventional basins. We believe we are well-positioned to meet these changing operating conditions as a result of the flexibility of our compression units. Whileour business focuses largely on compression services in shale plays, we also provide compression services in more mature conventional basins, includingcrude oil wells targeted by horizontal drilling techniques. Wells in conventional basins typically require increasing amounts of compression as they age andpressures decline. In addition, the continued development of horizontal drilling, particularly in crude oil wells, has allowed producers to produce incrementalvolumes of crude oil on attractive economic terms. Our gas lift fleet, critical to producing oil from horizontal wells, serves this growing market demand. We operate a modern fleet of compression units, with an average age of approximately four years. We acquire our compression units from third-partyfabricators who build the units to our specifications, utilizing specific original equipment manufacturers and assembling the units in a manner that providesus the ability to meet certain operating condition thresholds. Our standard new-build compression units are generally configured for multiple compressionstages allowing us to operate our units across a broad range of operating conditions. As of December 31, 2013, we estimate that approximately 89% of ourrevenue generating horsepower was deployed in infrastructure applications, including large-volume gathering systems, processing facilities, transportationapplications and crude oil gas lift. The design flexibility of our units, particularly in midstream applications, allows us to enter into longer-term contractswhere appropriate and reduces the redeployment risk of our horsepower in the field. Our modern and standardized fleet, decentralized field level operatingstructure and technical proficiency in predictive and preventive maintenance and overhaul operations have enabled us to achieve average service run timesconsistently above the levels required by our customers. 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 theneeds of our customers and by providing them with reliable and flexible compression services in geographic areas of attractive growth, we are able to generatestable cash flows for our unitholders. From 2003 through 2013, our average horsepower utilization was over 90%, occurring throughout periods of volatilenatural gas prices. We provide compression services to our customers under fixed-fee contracts, with initial contract terms of up to five years for midstream applications andsix to twelve months for crude oil gas lift applications. We typically continue to provide compression services to our customers beyond their initial contractterms, either through contract renewals or on a month-to-month basis. We generally enter into take-or-pay contracts whereby our customers are required to payour monthly fee even during periods of limited or disrupted throughput, which enhances the stability and predictability of our cash flows. We are not directlyexposed to commodity 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 unitsis supplied by our customers without cost to us. 2 Table of Contents Business Strategies Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoingstability and growth of our business. We expect to achieve this objective by executing on the following strategies: · Capitalize on the increased need for natural gas compression in conventional and unconventional plays. We expect additional demand forcompression services to result from the continuing shift of natural gas production to domestic shale plays as well as the declining productionpressures of aging conventional basins. In addition, the continued development of horizontal drilling in crude oil production and the demand forartificial lift techniques represents an attractive growth area. Our fleet of modern, flexible compression units, which are capable of being rapidlydeployed and redeployed and many of which are designed to operate in multiple compression stages, will enable us to capitalize on these opportunitiesboth in emerging shale plays as well as conventional fields. · Continue to execute on attractive organic growth opportunities. Between 2003 and 2013, we grew the horsepower in our fleet of compressionunits and our compression revenues at a compound annual growth rate of 24%, primarily through organic growth. We believe organic growthopportunities will continue to be our most attractive source of near-term growth. We seek to achieve continued organic growth by (i) increasing ourbusiness with existing customers, (ii) obtaining new customers in our existing areas of operations and (iii) expanding our operations into newgeographic areas. · Partner with customers who have significant compression needs. We actively seek to identify customers with major acreage positions in activeand growing areas. We work with these customers to jointly develop long-term and adaptable solutions designed to optimize their lifecyclecompression costs. We believe this is important in determining the overall economics of producing, gathering and transporting natural gas. Ourproactive and collaborative approach positions us to serve as our customers’ compression provider of choice. · Pursue accretive acquisition opportunities. While our principal growth strategy will be to continue to grow organically, we may pursue accretiveacquisition opportunities, including the acquisition of complementary businesses, participation in joint ventures or purchase of compression unitsfrom existing or new customers in conjunction with providing compression services to them. We will consider opportunities that (i) are in our existinggeographic areas of operations or new, high-growth regions, (ii) meet internally established economic thresholds and (iii) may be financed onreasonable terms. · Maintain financial flexibility. We intend to maintain financial flexibility to be able to take advantage of growth opportunities. Historically, we haveutilized our cash flow from operations, borrowings under available debt facilities and operating leases to fund capital expenditures to expand ourcompression services business. This approach has allowed us to significantly grow our fleet and the amount of cash we generate, while maintainingour debt at levels we believe are manageable for our business. We believe our financial flexibility positions us to take advantage of future growthopportunities without incurring debt beyond appropriate levels. Our Operations Compression Services We provide compression services for a monthly service fee. As part of our services, we engineer, design, operate, service and repair our fleet ofcompression units and maintain related support inventory and equipment. We have consistently provided average service run times above the levels requiredby our customers. In general, our team of field service technicians service our compression fleet and do not service third party owned equipment. We seek toenter into service contracts with each of our customers. In connection with the S&R Acquisition (as defined below), we acquired contracts related to the activecompressors in the fleet that were styled as rentals. We are in the process of converting these agreements into service contracts. We do not own any compressionfabrication facilities. 3 Table of Contents Our Compression Fleet The fleet of compression units that we own and use to provide compression services consists of specially engineered compression units that utilizestandardized 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 97% of our fleet horsepower at December 31, 2013was purchased new and the average age of our compression units was approximately four years. Our modern, standardized compressor fleet primarilyconsists of the Caterpillar 3500 and 3600 engine classes, which range from 630 to 4,700 horsepower per unit. These larger horsepower units, defined as 400horsepower per unit or greater, represented approximately 81.2% of our total horsepower (including compression units on order) as of December 31, 2013. Inaddition, a portion of our fleet consists of smaller horsepower units ranging from 84 horsepower to 240 horsepower that are primarily used in our gas liftoperations. We believe the young age and overall composition of our compressor fleet results in fewer mechanical failures, lower fuel usage (a direct costsavings for our customers), and reduced environmental emissions. The following table provides a summary of our compression units by horsepower as of December 31, 2013 (including additional new compression unithorsepower on order for delivery between January 2014 and November 2014): Unit HorsepowerFleetHorsepowerHorsepower onOrder (1)TotalHorsepower (2)Percentage ofTotalHorsepower<400236,67723,042259,71918.8%>400 <1,000193,9646,720200,68414.5%>1,000771,733150,095921,82866.7%Total1,202,374179,8571,382,231100.0% (1) As of December 31, 2013, we had on order 179,857 horsepower, of which 149,092 horsepower is expected to be delivered between January 2014 andJune 2014, and 30,765 horsepower is expected to be delivered between July 2014 and November 2014. (2) Comprised of 2,461 compression units, including 266 new compression units on order. The following table sets forth certain information regarding our compression fleet as of the dates and for the periods indicated: SuccessorPredecessorYear EndedPercentYear EndedPercentYear EndedPercentDecember 31,ChangeDecember 31,ChangeDecember 31,ChangeOperating Data (unaudited):2013201220132011201220102011Fleet horsepower(1) 1,202,374919,12130.8%722,20127.3%609,73018.4%Total available horsepower(2) 1,278,829935,68136.7%809,41815.6%612,41032.2%Revenue generating horsepower(3)1,070,457794,32434.8%649,28522.3%533,69221.7%Average revenue generatinghorsepower(4) 902,168749,82120.3%570,90031.3%516,70310.5%Revenue generating compression units2,137978118.5%88810.1%79511.7%Average horsepower per revenuegenerating compression unit(5)720791(9.0)%69214.3%6673.7%Horsepower utilization(6):At period end94.1%92.8%1.4%95.7%(3.0)%91.8%4.2%Average for the period(7) 93.8%94.5%(0.7)%92.3%2.4%92.6%(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, 2013, we hadapproximately 180,000 horsepower on order with expected delivery primarily in the first half of 2014. (2) Total available horsepower is revenue generating horsepower under contract for which we are billing a customer, horsepower in our fleet that is undercontract 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 purchaseorder, and idle horsepower. Total available horsepower excludes new horsepower on order for which we do not have a compression services contract. 4 Table of Contents (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 generatingrevenue 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) totalavailable horsepower less idle horsepower that is under repair. Horsepower utilization based on revenue generating horsepower and fleet horsepower at eachapplicable period end was 89.0%, 86.4%, 89.9% and 87.5%, for the years ended December 31, 2013, 2012, 2011 and 2010, 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 growing number of our compression units have electronic control systems that enable us to monitor our units remotely by satellite or other means tosupplement our technicians’ on-site monitoring visits. Our compression units are designed to automatically shut down if operating conditions deviate from apre-determined range. While we retain the care, custody, ongoing maintenance and control of our compression units, we allow our customers, subject to adefined protocol, to start, stop, accelerate and slow down compression units in response to field conditions. We adhere to routine, preventive and scheduled maintenance cycles. Each of our compression units is subjected to rigorous sizing and diagnosticanalyses, including lubricating oil analysis and engine exhaust emission analysis. We have proprietary field service automation capabilities that allow ourservice technicians to electronically record and track operating, technical, environmental and commercial information at the discrete unit level. Thesecapabilities 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 ourlarger horsepower units (400 horsepower or greater) and on average every five years for smaller horsepower units. A major overhaul involves the periodicrebuilding 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 are able toschedule 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 achieve higher compression runtimes, which translates into increasedvolume of either natural gas or crude oil production and therefore increases revenues. Utilizing our compression services also allows our customers to reducetheir operating, maintenance and equipment costs by allowing us to efficiently manage their changing compression needs. In many of our service contracts, weguarantee our customers availability ranging from 95% to 98%, depending on field level requirements. For service contracts that do not have a statedavailability guarantee, we work with those customers to ensure that our compression services meet their operational needs. General Compression Service Contract Terms The following discussion describes the material terms generally common to our compression service contracts. We generally enter into a new contract withrespect 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 for midstream applications and between six and twelvemonths for gas lift applications. After the expiration of the applicable term the contract continues on a month-to-month or longer basis until terminated by us orour customers upon notice as provided for in the applicable contract. 5 Table of Contents Availability. Our contracts often provide a guarantee of specified availability. We define availability as the percentage of time in a given period that ourcompression services are being provided or are capable of being provided. Availability is reduced by instances of “down-time” that are attributable to anythingother 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 beingprovided and when we receive notice of the problem. Down-time due to scheduled maintenance is also excluded from our availability commitment. Our failureto meet a stated availability guarantee may result in a service fee credit to the customer. As a consequence of our availability guarantee, we are incentivized toperform predictive and preventive maintenance on our fleet as well as promptly respond to a problem to meet our contractual commitments and ensure ourcustomers 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, except for many of our gas liftcompression customers (which are billed at the beginning of the service month), and they are required to pay upon receipt of the invoice. We are not responsiblefor acts of force majeure, and our customers generally are required to pay our monthly fee even during periods of limited or disrupted throughput. We aregenerally responsible for the costs and expenses associated with operation and maintenance of our compression equipment, such as providing necessarylubricants, although certain fees and expenses are the responsibility of our customers under the terms of their contracts. For example, all fuel gas is providedby 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 beprovided by the customer. We are also reimbursed by our customers for certain ancillary expenses such as trucking and crane operation, depending on theterms agreed to in the applicable contract, resulting in no gross operating margin. Service standards and specifications. We commit to provide compression services under service contracts that typically provide that we will supply allcompression equipment, tools, parts, field service support and engineering. Our contracts do not govern the compression equipment we will use; instead, inconjunction with our customer, we determine what equipment is necessary to perform our contractual commitments. Title; Risk of loss. We own all compression equipment we use to provide compression services, and we normally bear the risk of loss or damage to ourequipment 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, workers’ compensation, employers’liability, automobile and excess liability insurance. Marketing and Sales Our marketing and client service functions are performed on a coordinated basis by our sales and field technicians. Salespeople and field techniciansqualify, analyze and scope new compression applications as well as regularly visit our customers to ensure customer satisfaction, to determine a customer’scurrent needs related to services currently being provided and to determine the customer’s future compression services requirements. This ongoingcommunication allows us to quickly identify and respond to our customers’ compression requirements. We currently focus on geographic areas where we canachieve economies of scale through high density operations. Customers Our customers consist of more than 250 companies in the energy industry, including major integrated oil companies, public and private independentexploration and production companies and midstream companies. Our largest customer for the years ended December 31, 2013 and 2012 was SouthwesternEnergy Corporation and its subsidiaries, or Southwestern Energy. Southwestern Energy accounted for 14.3% of our revenue for the year ended December 31,2013 and 14.5% of our revenue for the year ended December 31, 2012. Our ten largest customers accounted for 49% and 54% of our revenue for the yearsended December 31, 2013 and 2012, respectively. Suppliers and Service Providers The principal manufacturers of components for our natural gas compression equipment include Caterpillar, Inc., or Caterpillar, Cummins Inc., orCummins, and Arrow Engine Company, or Arrow (for engines), Air-X-Changers and Air Cooled Exchangers (for coolers), and Ariel Corporation, GE Oil &Gas Gemini products and Arrow (for compressor frames and cylinders). We also rely primarily on three vendors, A G Equipment Company, StandardEquipment Corp. and S&R Compression, LLC (“S&R”), to package and assemble our compression units. Although we rely primarily on these suppliers, webelieve alternative sources for natural gas compression equipment are generally available if needed. However, relying on alternative sources may increase ourcosts and change the 6 Table of Contents standardized nature of our fleet. We have not experienced any material supply problems to date, although lead-times for Caterpillar engines and Arielcompressor frames 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. Please read “— Item 1A. — Risk Factors — Risks Related to Our Business — We depend on a limited number of suppliers and arevulnerable to product shortages and price increases, which could have a negative impact on our results of operations.” Competition The compression services business is highly competitive. Some of our competitors have a broader geographic scope, as well as greater financial and otherresources than we do. On a regional basis, we experience competition from numerous smaller companies that may be able to more quickly adapt to changeswithin our industry and changes in economic conditions as a whole, more readily take advantage of available opportunities and adopt more aggressive pricingpolicies. Additionally, the current availability of attractive financing terms from financial institutions and equipment manufacturers makes the purchase ofindividual compression units increasingly affordable to our 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. Seasonality Our results of operations have not historically reflected any material seasonality, and we do not currently have reason to believe seasonal fluctuations willhave a material impact in the foreseeable future. Insurance 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 byinsurance would increase our costs. The compression business can be hazardous, involving unforeseen circumstances such as uncontrollable flows of gas orwell fluids, fires and explosions or environmental damage. To address the hazards inherent in our business, we maintain insurance coverage that, subject tosignificant deductibles, includes physical damage coverage, third party general liability insurance, employer’s liability, environmental and pollution and othercoverage, although coverage for environmental and pollution related losses is subject to significant limitations. Under the terms of our standard compressionservices contract, we are responsible for the maintenance of insurance coverage on our compression equipment. Environmental and Safety Regulations We are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment or otherwiserelating 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 orendangered species. Compliance with these environmental laws and regulations may expose us to significant costs and liabilities and cause us to incursignificant capital expenditures in our operations. We are often obligated to obtain permits or approvals in our operations from various federal, state and localauthorities. Permits and approvals can be denied or delayed, which may cause us to lose potential and current customers, interrupt our operations and limitour growth and revenue. Moreover, failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminalpenalties, imposition of remedial obligations and the issuance of injunctions delaying or prohibiting operations. Private parties may also have the right topursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury orproperty damage. While we believe that our operations are in substantial compliance with applicable environmental laws and regulations and that continuedcompliance with current requirements would not have a material adverse effect on us, there is no assurance that this trend of compliance will continue in thefuture. In addition, the clear trend in environmental regulation is to place more restrictions on activities that may affect the environment and thus, any changesin, 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. 7 Table of Contents 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 enforcementpolicies, the promulgation of new laws or regulations, or the development or discovery of new facts or conditions or unforeseen incidents will not cause us toincur significant costs. The following is a discussion of material environmental and safety laws that relate to our operations. We believe that we are insubstantial compliance with all of these environmental laws and regulations. Air emissions. The Clean Air Act, or CAA, and comparable state laws regulate emissions of air pollutants from various industrial sources, including naturalgas compressors, and impose certain monitoring and reporting requirements. Such emissions are regulated by air emissions permits, which are applied forand obtained through the various state or federal regulatory agencies. Our standard natural gas compression contract typically provides that the customer isresponsible for obtaining air emissions permits and assuming the environmental risks related to site operations. Increased obligations of operators to reduce airemissions of nitrogen oxides and other pollutants from internal combustion engines in transmission service have been enacted by governmental authorities. Forexample, on August 20, 2010, the EPA published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationaryreciprocal internal combustion engines, also known as Quad Z regulations. On June 7, 2012, the EPA proposed amendments to the final rule in response toseveral petitions for reconsideration. The EPA finalized the amendments on January 30, 2013. The rule requires us to undertake certain expenditures andactivities, including purchasing and installing emissions control equipment on certain compressor engines and generators. The final rule became effective onApril 1, 2013, and imposed varying compliance deadlines based on engine rating and type of site, with the latest deadlines falling on October 19, 2013. We donot believe the final rule has an impact on our operations and we do not believe that the costs associated with compliance with the final rule will be material. On June 7, 2012, the EPA proposed minor amendments to the CAA regulations applicable to the manufacturers, owners, and operators of new, modifiedand reconstructed stationary reciprocating internal combustion engines, also known as Quad J regulations, in order to conform the final rule to theamendments to the Quad Z regulations discussed above. These amendments were finalized on January 30, 2013 and were effective April 1, 2013. These recentmodifications are not expected to impose material unbudgeted costs on operations. The modifications seem to primarily make minor adjustments to theexisting program that would not appear to add significant compliance costs. In March 2008, the EPA also promulgated a new, lower National Ambient Air Quality Standard, or NAAQS, for ozone that was recently upheld infederal court. Under the CAA, the EPA was required to review recent scientific findings related to ground level ozone in 2013 and may issue a new NAAQS.However, a new standard has not yet been proposed. In addition, on January 15, 2013, the EPA promulgated a final rule revising the annual standard for PM2.5 by lowering the level from 15 to 12 micrograms per cubic meter. The EPA does not anticipate making initial attainment or nonattainment designationsuntil December 2014. Designation of new non-attainment areas for the revised ozone or PM 2.5 NAAQS may result in additional federal and state regulatoryactions that could impact our customers’ operations and increase the cost of additions to property, plant and equipment. On April 17, 2012, the EPA finalized rules that establish new air emission controls for oil and natural gas production and natural gas processingoperations. Specifically, the EPA’s rule package included New Source Performance Standards to address emissions of sulfur dioxide and volatile organiccompounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas productionand processing activities. The rules establish specific new requirements regarding emissions from compressors and controllers at natural gas processingplants, dehydrators, storage tanks and other production equipment as well as the first federal air standards for natural gas wells that are hydraulicallyfractured. In addition, the rules establish leak detection requirements for natural gas processing plants at 500 ppm. On August 5, 2013, the EPA issued a finalupdate to the VOC performance standards for storage tanks used in crude oil and natural gas production and transmission. These rules may require a numberof modifications to our operations, including the installation of new equipment to control emissions from our compressors at initial startup. Compliance withsuch rules could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. 8 Table of Contents In addition, the Texas Commission on Environmental Quality, or TCEQ, has finalized revisions to certain air permit programs that significantly increasethe air permitting requirements for new and certain existing oil and gas production and gathering sites for 15 counties in the Barnett Shale production area. Thefinal rule establishes new emissions standards for engines, which could impact the operation of specific categories of engines by requiring the use of alternativeengines, compressor packages or the installation of aftermarket emissions control equipment. The rule became effective for the Barnett Shale production areain April 2011, with the lower emissions standards becoming applicable between 2015 and 2030 depending on the type of engine and the permittingrequirements. 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 willconsider expanding application of the new air permit program statewide. At this point, we cannot predict the cost to comply with such requirements if thegeographic scope is expanded. There can be no assurance that future requirements compelling the installation of more sophisticated emission control equipment would not have amaterial adverse impact on our business, financial condition, results of operations and ability to make cash distributions to our unitholders. Climate change. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples ofgreenhouse gases. In recent years, the U.S. Congress has considered legislation to reduce emissions of greenhouse gases. It presently appears unlikely thatcomprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other initiatives are expected tobe proposed that may be relevant to greenhouse gas emissions issues. However, almost half of the states have begun to address greenhouse gas emissions,primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs. Depending on the particular program,we could be required to control greenhouse gas emissions or to purchase and surrender allowances for greenhouse gas emissions resulting from our operations. Independent of Congress, the EPA is beginning to adopt regulations controlling greenhouse gas emissions under its existing CAA authority. For example,on December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other greenhouse gases endanger humanhealth and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climaticchanges. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that restrict emissions of greenhousegases under existing provisions of the CAA. In 2009, the EPA adopted rules regarding regulation of greenhouse emissions from motor vehicles. In addition, onSeptember 22, 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions in the United States beginning in 2011 for emissionsoccurring in 2010 from specified large greenhouse gas emission sources. On November 30, 2010, the EPA published a final rule expanding its existinggreenhouse gas emissions reporting rule for petroleum and natural gas facilities, including natural gas transmission compression facilities that emit 25,000metric tons or more of carbon dioxide equivalent per year. The rule, which went into effect on December 30, 2010, requires reporting of greenhouse gasemissions by such regulated facilities to the EPA by September 2012 for emissions during 2011 and annually thereafter. In 2010, the EPA also issued a finalrule, known as the “Tailoring Rule,” that makes certain large stationary sources and modification projects subject to permitting requirements for greenhousegas emissions under the CAA. Both the Tailoring Rule and the EPA’s endangerment finding were challenged in federal court and were upheld by the D.C. Court of Appeals. OnOctober 15, 2013, the United States Supreme Court agreed to hear arguments regarding the Tailoring Rule during its 2013-2014 session. However, the Courtrefused to consider other issues such as whether greenhouse gases endanger public health. A decision is expected in this case by the end of June 2014. Finally, on January 8, 2014, the EPA published standards of performance for greenhouse gas emissions from power plants. The proposal sets forth aperformance standard for integrated gasification combined cycled units and utility boilers based on the use of partial carbon capture and sequestrationtechnology. The proposal also sets limits for stationary natural gas combustion turbines based on the use of natural gas combined cycle technology. Commentson this proposed rule are due March 10, 2014. Although it is not currently possible to predict with specificity how any proposed or future greenhouse gas legislation or regulation will impact ourbusiness, any legislation or regulation of greenhouse gas emissions that may be imposed in areas in which we conduct business could result in increasedcompliance costs or additional operating restrictions or reduced demand for our services, and could have a material adverse effect on our business, financialcondition and results of operations. 9 Table of Contents Water discharge. The Clean Water Act, or CWA, and analogous state laws impose restrictions and strict controls with respect to the discharge ofpollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters isprohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA and regulations implemented thereunderalso prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issuedpermit. The CWA also requires the development and implementation of spill prevention, control and countermeasures, including the construction andmaintenance of containment berms and similar structures, if required, to help prevent the contamination of navigable waters in the event of a petroleumhydrocarbon tank spill, rupture or leak at such facilities. In addition, the CWA and analogous state laws require individual permits or coverage under generalpermits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil andcriminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous statelaws and regulations. Our compression operations do not generate process wastewaters that are discharged to waters of the U.S. In any event, our customersassume responsibility under the majority of our standard natural gas compression contracts for obtaining any discharge permits that may be required underthe CWA. Safe Drinking Water Act. A significant portion of our customers’ natural gas production is developed from unconventional sources that require hydraulicfracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation tostimulate 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 ofthe chemical constituents of the fluids used in the fracturing process, have been proposed and the U.S. Congress continues to consider legislation to amend theSafe Drinking Water Act. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a multi-year study of thepotential environmental impacts of hydraulic fracturing, the results of which are anticipated to be available in 2014. The EPA also has recently announced thatit believes hydraulic fracturing using fluids containing diesel fuel can be regulated under the SDWA notwithstanding the SDWA’s general exemption forhydraulic fracturing. Several states have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. We cannot predict the future ofsuch legislation and what additional, if any, provisions would be. If additional levels of regulation, restrictions and permits were required through the adoptionof new laws and regulations at the federal or state level, that could lead to delays, increased operating costs and process prohibitions that could reduce demandfor our compression services, 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 hazardousand non-hazardous waste. These laws and regulations govern the generation, storage, treatment, transfer and disposal of wastes that we generate including, butnot limited to, used oil, antifreeze, filters, sludges, paint, solvents and sandblast materials. The EPA and various state agencies have limited the approvedmethods 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 hazardoussubstance into the environment. These persons include the owner and operator of a disposal site where a hazardous substance release occurred and anycompany that transported, disposed of or arranged for the transport or disposal of hazardous substances released at the site. Under CERCLA, such personsmay be liable for the costs of remediating the hazardous substances that have been released into the environment, for damages to natural resources, and for thecosts of certain health studies. In addition, where contamination may be present, it is not uncommon for the neighboring landowners and other third parties tofile claims for personal injury, property damage and recovery of response costs. While we generate materials in the course of our operations that may beregulated as hazardous substances, we have not received notification that we may be potentially responsible for cleanup costs under CERCLA at any site. 10 Table of Contents 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 thirdparty properties for such storage and possible maintenance and repair activities. In addition, our active compression units typically are placed on propertiesowned or leased by third party customers and operated by us pursuant to terms set forth in the natural gas compression services contracts executed by thosecustomers. Under most of our natural gas compression services contracts, our customers must contractually indemnify us for certain damages we may sufferas a result of the release into the environment of hazardous and toxic substances. We are not currently responsible for any remedial activities at any propertiesused by us; however, there is always the possibility that our future use of those properties may result in spills or releases of petroleum hydrocarbons, wastesor other regulated substances into the environment that may cause us to become subject to remediation costs and liabilities under CERCLA, RCRA or otherenvironmental laws. We cannot provide any assurance that the costs and liabilities associated with the future imposition of such remedial obligations upon uswould 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 safetyof employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar statestatutes require that we organize and, as necessary, disclose information about hazardous materials used or produced in our operations to various federal, stateand local agencies, as well as employees. Properties We do not currently own or lease any material facilities or properties for storage or maintenance of our compression units. As of December 31, 2013, ourheadquarters consisted of 11,307 square feet of leased space located at 100 Congress Avenue, Austin, Texas 78701. Employees USAC Management, a wholly owned subsidiary of our general partner, operates our assets and performs other administrative services for us, such asaccounting, corporate development, finance and legal. All of our employees, including our executives, are employees of USAC Management. As ofDecember 31, 2013, USAC Management had 360 full time employees. None of our employees are subject to collective bargaining agreements. We consider ouremployee relations to be good. Legal Proceedings 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 aparty to any legal proceedings that we believe would have a material adverse effect on our financial position, results of operations or cash flows. Available Information Our internet website address is www.usacpartners.com. We make available, free of charge at the “Investor Relations” portion of our website, our AnnualReport on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports filed or furnished pursuant toSection 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, as soon as reasonably practicable after such reports are electronically filed with, orfurnished to, the SEC. The information contained on our website does not constitute part of this report. The SEC maintains an internet website that contains these reports at www.sec.gov. Any materials that the Partnership files with the SEC may be read orcopied at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information concerning the operation of the Public ReferenceRoom may be obtained by calling the SEC at (800) 732-0330. 11 Table of Contents ITEM 1A. Risk Factors As described in Part I,“Disclosure Regarding Forward-Looking Statements,” this report contains forward-looking statements regarding us, ourbusiness and our industry. The risk factors described below, among others, could cause our actual results to differ materially from the expectationsreflected in the forward-looking statements. If any of the following risks were to occur, our business, financial condition or results of operations couldbe materially and adversely affected. In that case, we might not be able to pay our minimum quarterly distribution on our common units or grow suchdistributions and the trading price of our common units could decline. 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 costreimbursements to our general partner, to enable us make cash distributions at our current distribution rate to holders of our common units andsubordinated units. In order to make cash distributions at our current distribution rate of $0.48 per unit per quarter, or $1.92 per unit per year, we will require available cashof $18.7 million per quarter, or $74.6 million per year, based on the number of common units, subordinated units and the 2.0% general partner interestcurrently outstanding at February 18, 2014. Under our cash distribution policy, the amount of cash we can distribute to our unitholders principally dependsupon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things: · the level of production of, demand for, and price of natural gas and crude oil, particularly the level of production in the locations where we providecompression services; · the fees we charge, and the margins we realize, from our compression services; · the cost of achieving organic growth in current and new markets; · the level of competition from other companies; and · prevailing global and regional economic and regulatory conditions, and their impact on our customers. In addition, the actual amount of cash we will have available for distribution will depend on other factors, including: · the levels of our maintenance capital expenditures and expansion capital expenditures; · the level of our operating costs and expenses; · our debt service requirements and other liabilities; · fluctuations in our working capital needs; · restrictions contained in our revolving credit facility; · the cost of acquisitions, if any; · fluctuations in interest rates; · our ability to borrow funds and access capital markets; and · the amount of cash reserves established by our general partner. 12 Table of Contents 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 thedemand for our services or the prices we charge for our services, which could result in a decrease in our revenues and cash available fordistribution 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 beaffected by, among other factors, natural gas prices, crude oil prices, weather, availability of alternative energy sources, governmental regulation and generaldemand for energy. Any prolonged, substantial reduction in the demand for natural gas or crude oil would, in all likelihood, depress the level of productionactivity and result in a decline in the demand for our compression services, which would reduce our cash available for distribution. Lower natural gas pricesor 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 ourcompression services. Additionally, an increasing percentage of natural gas and crude oil production comes from unconventional sources, such as shales, tightsands and coalbeds. Such sources can be less economically feasible to produce in low natural gas price environments, in part due to costs related tocompression requirements, and a reduction in demand for natural gas or gas lift for crude oil may cause such sources of natural gas or crude oil to beuneconomic to drill and produce, which could in turn negatively impact the demand for our services. In addition, governmental regulation and tax policy mayimpact the demand for natural gas or crude oil or impact the economic feasibility of development of new 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 distributionto 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 ourfinancial results than for a company with a more diverse customer base. Our largest customer for the years ended December 31, 2013 and 2012 wasSouthwestern Energy Company and its subsidiaries, or Southwestern Energy. Southwestern Energy accounted for 14.3% of our revenue for the year endedDecember 31, 2013 and 14.5% of our revenue for the year ended December 31, 2012. Our ten largest customers accounted for 49% and 54% of our revenue forthe years ended December 31, 2013 and 2012, respectively. The loss of all or even a portion of the compression services we provide to our key customers, as aresult of competition or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cashdistributions 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 ofdebt or equity financing, which could result in a reduction in our customers’ spending for our services. For example, our customers could seek to preservecapital by using lower cost providers, not renewing month-to-month contracts or determining not to enter into any new compression service contracts. Reduceddemand for our services could adversely affect our business, results of operations, financial condition and cash flows. In addition, in the event of thefinancial 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 otherresources than we do. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flows couldbe adversely affected by the activities of our competitors and our customers. If our competitors substantially increase the resources they devote to thedevelopment and marketing of competitive services or substantially decrease the prices at which they offer their services, we may be unable to competeeffectively. Some of these competitors may expand or construct newer, more powerful or more flexible compression fleets that would create additionalcompetition for us. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition andreduce 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, expanding theamount of compression units they currently own or using alternative technologies for enhancing crude oil production. Our customers that are significant producers, processors, gatherers and transporters of natural gas and crude oil may choose to vertically integrate theiroperations by purchasing and operating their own compression fleets in lieu of using our compression services. Currently, the availability of attractivefinancing terms from financial institutions and equipment manufacturers facilitates this possibility by making the purchase of individual compression unitsincreasingly affordable to our customers. In addition, there are many technologies available for the artificial enhancement of crude oil production and ourcustomers may elect to use these alternative technologies instead of the 13 Table of Contents gas lift compression services we provide. Such vertical integration, increases in vertical integration or use of alternative technologies could result in decreaseddemand for our compression services, which may have a material adverse effect on our business, results of operations, financial condition and reduce ourability to make cash distributions to our unitholders. A significant portion of our services are provided to customers on a month-to-month basis, and we cannot be sure that our customers willcontinue to utilize these services that have continued beyond the primary term. As of December 31, 2013, approximately 38% of our compression services on a horsepower basis (and 43% on a revenue basis for the year endedDecember 31, 2013) were provided on a month-to-month basis to customers who continue to utilize our services following expiration of the primary term oftheir contracts with us. These customers can generally terminate their month-to-month compression services contracts on 30-days’ written notice. If asignificant number of these customers were to terminate their month-to-month services, or attempt to renegotiate their month-to-month contracts at substantiallylower rates, it could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to ourunitholders. 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 ourunitholders. A principal focus of our strategy is to continue to grow the per unit distribution on our common units by expanding our business. Our future growth willdepend upon a number of factors, some of which we cannot control. These factors include our ability to: · develop new business and enter into service contracts with new customers; · retain our existing customers and maintain or expand the services we provide them; · recruit and train qualified personnel and retain valued employees; · expand our geographic presence; · effectively manage our costs and expenses, including costs and expenses related to growth; · consummate accretive acquisitions; · obtain required debt or equity financing for our existing and new operations; and · meet customer specific contract requirements or pre-qualifications. If we do not achieve our expected growth, we may not be able to pay the aggregate minimum quarterly distribution on our common units and subordinatedunits and the 2.0% general partner interest, in which event the market price of our common units will likely decline materially. We may be unable to grow successfully through acquisitions, and we may not be able to integrate effectively the businesses we may acquire, whichmay 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 newareas of operations. On August 30, 2013, we completed the acquisition of all of the compression and related assets of S&R. We will continue to reviewacquisition opportunities in the future, but we may not be able to identify attractive acquisition opportunities or successfully acquire identified targets. Inaddition, we may not be successful in integrating any future acquisitions into our existing operations, which may result in unforeseen operational difficultiesor diminished financial performance or require a disproportionate amount of our management’s attention. Even if we are successful in integrating futureacquisitions into our existing operations, we may not derive the benefits, such as operational or administrative synergies, that we expected from suchacquisitions, which may result in the commitment of our capital resources without the expected returns on such capital. Furthermore, competition foracquisition opportunities may escalate, increasing our cost of making acquisitions or causing us to refrain from making acquisitions. Our inability to makeacquisitions, or to integrate acquisitions successfully into our existing operations, may adversely impact our operations and limit our ability to increasedistributions to our unitholders. 14 Table of Contents Our ability to grow in the future is dependent on our ability to access external expansion capital. Our partnership agreement requires us to distribute all of our available cash after expenses and prudent operating reserves to our unitholders. We expectthat we will rely primarily upon external financing sources, including borrowings under our revolving credit facility and the issuance of debt and equitysecurities, 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 theextent we are unable to efficiently finance growth externally, our ability to increase distributions to our uniholders could be significantly impaired. 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. Tothe extent we issue additional units in connection with other expansion capital expenditures, the payment of distributions on those additional units mayincrease 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 ourability to issue additional units, including units ranking senior to the common units. The incurrence of borrowings or other debt by us to finance our growthstrategy would result in interest expense, which in turn would affect the available cash that we have to distribute to our unitholders. Our debt levels may limit our flexibility in obtaining additional financing, pursuing other business opportunities and paying distributions. We have an $850 million revolving credit facility that matures on December 13, 2018. In addition, we have the option to increase the amount of totalcommitments under the revolving credit facility by $100 million, subject to receipt of lender commitments and satisfaction of other conditions. As ofDecember 31, 2013, we had outstanding borrowings of $420.9 million and available borrowings of $264.6 million, based on our borrowing base. Our abilityto incur additional debt is subject to limitations in our revolving credit facility. Our level of debt could have important consequences to us, including thefollowing: · our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired orsuch financing may not be available on favorable terms; · we will need a portion of our cash flow to make payments on our indebtedness, reducing the funds that would otherwise be available for operatingactivities, future business opportunities and distributions; and · our debt level will make us more vulnerable, than our competitors with less debt, to competitive pressures or a downturn in our business or theeconomy generally. Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailingeconomic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service our debtunder the revolving credit facility could be impacted by market interest rates, as all of our outstanding borrowings are subject to interest rates that fluctuatewith movements in interest rate markets. A substantial increase in the interest rates applicable to our outstanding borrowings could have a material impact onour cash available for distribution. If our operating results are not sufficient to service our current or future indebtedness, we could be forced to take actionssuch as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring orrefinancing 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 onacquisition 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 tofinance future operations or capital needs or to expand or pursue our business activities. Our amended and restated credit agreement restricts or limits ourability to (subject to exceptions): · grant liens; · make certain loans or investments; · incur additional indebtedness or guarantee other indebtedness; 15 Table of Contents · enter into transactions with affiliates; · merge or consolidate; · sell our assets; or · make certain acquisitions. Furthermore, our revolving credit facility contains certain operating and financial covenants. Our ability to comply with these covenants and restrictionsmay be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other economic conditionsdeteriorate, our ability to comply with these covenants may be impaired. If we violate any of the restrictions, covenants, ratios or tests in our revolving creditfacility, a significant portion of our indebtedness may become immediately due and payable, our lenders’ commitment to make further loans to us mayterminate, and we may be prohibited from making distributions to our unitholders. We might not have, or be able to obtain, sufficient funds to make theseaccelerated payments. Any subsequent replacement of our revolving credit facility or any new indebtedness could have similar or greater restrictions. Pleaseread Part II, Item 7, “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 $208.1 million of goodwill and $85.9 million of other intangible assets as of December 31, 2013. Goodwill is recorded when thepurchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. Generally accepted accountingprinciples (“GAAP”) requires us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might beimpaired. 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 inour business. These events could cause us to record impairments of goodwill or other intangible assets. If we determine that any of our goodwill or otherintangible assets are impaired, we will be required to take an immediate charge to earnings with a corresponding reduction of partners’ capital resulting in anincrease in balance sheet leverage as measured by debt to total capitalization. There was no impairment recorded for goodwill or other intangible assets for theyears ended December 31, 2013 and 2012. 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 could have a significant negative effect on ourbusiness, 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 could become more challenging as we grow and ifenergy industry market conditions continue to be positive. When general industry conditions are good, the competition for experienced operational and fieldtechnicians increases as other energy and manufacturing companies’ needs for the same personnel increases. Our ability to grow or even to continue ourcurrent level of service to our current customers could 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 onour results of operations. The substantial majority of the components for our natural gas compression equipment are supplied by Caterpillar, Cummins and Arrow (for engines),Air-X-Changers and Air Cooled Exchangers (for coolers), and Ariel Corporation, GE Oil & Gas Gemini products and Arrow (for compressor frames andcylinders). Our reliance on these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply of requiredcomponents in a timely manner. We also rely primarily on three vendors, A G Equipment Company, Standard Equipment Corp. and S&R, to package andassemble our compression units. We do not 16 Table of Contents 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 resultsof operations and could damage our customer relationships. Some of these suppliers manufacture the components we purchase in a single facility and anydamage to that facility could lead to significant delays in delivery of completed units. 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 materialsinto the environment, emission controls and other environmental protection and occupational health and safety concerns. Environmental laws and regulationsmay, in certain circumstances, impose strict liability for environmental contamination, which may render us liable for remediation costs, natural resourcedamages 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 oroperators or other third parties. In addition, where contamination may be present, it is not uncommon for neighboring land owners and other third parties tofile claims for personal injury, property damage and recovery of response costs. Remediation costs and other damages arising as a result of environmental lawsand regulations, and costs associated with new information, changes in existing environmental laws and regulations or the adoption of new environmental lawsand regulations could be substantial and could negatively impact our financial condition or results of operations. Moreover, failure to comply with theseenvironmental laws and regulations may result in the imposition of administrative, civil and criminal penalties and the issuance of injunctions delaying orprohibiting operations. We conduct operations in a wide variety of locations across the continental U.S. These operations require U.S. federal, state or local environmentalpermits or other authorizations. Our operations may require new or amended facility permits or licenses from time to time with respect to storm waterdischarges, waste handling or air emissions relating to equipment operations, which subject us to new or revised permitting conditions that may be onerous orcostly to comply with. Additionally, the operation of compression units may require individual air permits or general authorizations to operate under variousair regulatory programs established by rule or regulation. These permits and authorizations frequently contain numerous compliance requirements, includingmonitoring and reporting obligations and operational restrictions, such as emission limits. Given the wide variety of locations in which we operate, and thenumerous environmental permits and other authorizations that are applicable to our operations, we may occasionally identify or be notified of technicalviolations of 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 orreleased on, under or from properties used by us to provide compression services or inactive compression unit storage or on or under other locations wheresuch substances or wastes have been taken for disposal. These properties may be subject to investigatory, remediation and monitoring requirements underfederal, 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 orregulations, or the adoption of new environmental laws or regulations may also negatively impact oil and natural gas exploration and production, gathering andpipeline 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, couldresult in increased compliance costs. In August 2010, the U.S. Environmental Protection Agency, or the EPA, published new regulations under the CAA to control emissions of hazardous airpollutants from existing stationary reciprocating internal combustion engines. In June, 2012, the EPA proposed amendments to the final rule in response toseveral petitions for reconsideration, and EPA finalized the proposed amendments in January, 2013. The final rule was effective in April, 2013, and imposesvarying compliance deadlines based on engine ratings and type of site, with the latest deadlines falling during October 2013. The rule requires us to undertakecertain expenditures and activities, including purchasing and installing emissions control equipment on a portion of our engines located at major sources ofhazardous air pollutants, following prescribed maintenance practices for engines (which are consistent with our existing practices), and implementingadditional emissions testing and monitoring. If we were unable to maintain compliance with the final rule, our business, financial condition, results ofoperations or ability to make cash distributions to our unitholders could be impacted. 17 Table of Contents In April 2012, the EPA finalized rules that establish new air emission controls for oil and natural gas production and natural gas processing operations.Specifically, the EPA’s rule package included New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, orVOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processingactivities. The rules establish specific new requirements regarding emissions from compressors and controllers at natural gas processing plants, dehydrators,storage tanks and other production equipment as well as the first federal air standards for natural gas wells that are hydraulically fractured. In addition, therules establish leak detection requirements for natural gas processing plants at 500 ppm. In August 2013, the EPA issued a final update to the VOCperformance standards for storage tanks used in crude oil and natural gas production and transmission. These rules may require a number of modifications toour operations, including the installation of new equipment to control emissions from our compressors at initial startup. Compliance with such rules couldresult 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 the TCEQ, has finalized revisions to certain air permit programs that significantlyincrease the air permitting requirements for new and certain existing oil and gas production and gathering sites for 15 counties in the Barnett Shale productionarea. The final rule establishes new emissions standards for engines, which could impact the operation of specific categories of engines by requiring the use ofalternative engines, compression packages or the installation of aftermarket emissions control equipment. The rule became effective for the Barnett Shaleproduction area in April 2011, with the lower emissions standards becoming applicable between 2015 and 2030 depending on the type of engine and thepermitting 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 itwill consider expanding application of the new air permit program statewide. At this point, we cannot predict the cost to comply with such requirements if thegeographic scope is expanded. These new regulations and proposals, when finalized, and any other new regulations requiring the installation of more sophisticated pollution controlequipment could have a material adverse impact on our business, results of operations, financial condition and ability to make cash distributions to ourunitholders. 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. In recentyears, the U.S. Congress has considered legislation to reduce emissions of greenhouse gases. It presently appears unlikely that comprehensive climatelegislation will be passed by either house of Congress in the near future, although energy legislation and other initiatives are expected to be proposed that maybe relevant to greenhouse gas emissions issues. However, almost half of the states have begun to address greenhouse gas emissions, primarily through theplanned development of emission inventories or regional greenhouse gas cap and trade programs. Depending on the particular program, we could be required tocontrol greenhouse gas emissions or to purchase and surrender allowances for greenhouse gas emissions resulting from our operations. Independent of Congress, the EPA is beginning to adopt regulations controlling greenhouse gas emissions under its existing CAA authority. For example,in December 2009, the EPA officially published its findings that emissions of carbon dioxide, methane, and other greenhouse gases endanger human healthand 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 allowed the agency to proceed with the adoption and implementation of regulations that restrict emissions of greenhouse gases underexisting provisions of the CAA. In 2009, the EPA adopted rules regarding regulation of greenhouse emissions from motor vehicles. In addition, onSeptember 2009, the EPA issued a final rule requiring the reporting of greenhouse gas emissions in the United States beginning in 2011 for emissionsoccurring in 2010 from specified large greenhouse gas emission sources. On November 2010, the EPA published a final rule expanding its existing greenhousegas emissions reporting rule for petroleum and natural gas facilities, including natural gas transmission compression facilities that emit 25,000 metric tons ormore of carbon dioxide equivalent per year. The rule, which went into effect on December 2010, requires reporting of greenhouse gas emissions by suchregulated 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 greenhouse gas emissions underthe CAA. 18 Table of Contents Both the Tailoring Rule and the EPA’s endangerment finding were challenged in federal court and were upheld by the D.C. Court of Appeals. OnOctober 15, 2013, the United States Supreme Court agreed to hear arguments regarding the Tailoring Rule during its 2013-2014 session. However, the Courtrefused to consider other issues such as whether greenhouse gases endanger public health. A decision is expected in this case by the end of June 2014. Finally, on January 8, 2014, the EPA published standards of performance for greenhouse gas emissions from power plants. The proposal sets forth aperformance standard for integrated gasification combined cycled units and utility boilers based on the use of partial carbon capture and sequestrationtechnology. The proposal also sets limits for stationary natural gas combustion turbines based on the use of natural gas combined cycle technology. Although it is not currently possible to predict with specificity how any proposed or future greenhouse gas legislation or regulation will impact ourbusiness, any legislation or regulation of greenhouse gas emissions that may be imposed in areas in which we conduct business could result in increasedcompliance costs or additional operating restrictions or reduced demand for our services, and could have a material adverse effect on our business, financialcondition and results of operations. Increased regulation of hydraulic fracturing could result in reductions or delays in natural gas production by our customers, which couldadversely impact our revenue. A significant portion of our customers’ natural gas production is from unconventional sources that require hydraulic fracturing as part of the completionprocess. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. Legislation toamend the Safe Drinking Water Act, or SDWA, to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and requirefederal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluidsused in the fracturing process, were proposed in recent sessions of Congress. The U.S. Congress continues to consider legislation to amend the SDWA.Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a multi-year study of the potential environmental impactsof hydraulic fracturing, the results of which are anticipated to be available in 2014. The EPA also has recently announced that it believes hydraulic fracturingusing fluids containing diesel fuel can be regulated under the SDWA notwithstanding the SDWA’s general exemption for hydraulic fracturing. Several stateshave also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. We cannot predict if additional legislation will ever be enacted andif so, what its provisions would be. If additional levels of regulation, restriction and permits were required through the adoption of new laws and regulations atthe federal or state level, that could lead to delays, increased operating costs and process prohibitions that could reduce demand for our compression services,which could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to ourunitholders. 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 uncontrollableflows of gas or well fluids, fires and explosions. These risks could expose us to substantial liability for personal injury, death, property damage, pollutionand other environmental damages. Our insurance may be inadequate to cover our liabilities. Further, insurance covering the risks we face or in the amounts wedesire 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 suchdamages 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 liabilityinsurance, our business, results of operations and financial condition could be adversely affected. Please read Part I, Item 1, “Business—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 ofmaterials into the environment or otherwise relating to protection of human health and environment. 19 Table of Contents Terrorist attacks, the threat of terrorist attacks, hostilities in the Middle East, or other sustained military campaigns may adversely impact ourresults 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 terroristattacks 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 othersustained military campaigns may affect our operations in unpredictable ways, including disruptions of natural gas supplies and markets for natural gas andnatural gas liquids and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurancemarkets attributable to terrorist attacks may make certain types of insurance more difficult for us to obtain. Moreover, the insurance that may be available tous may be significantly more expensive than our existing insurance coverage. Instability in the financial markets as a result of terrorism or war could alsoaffect 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 preventfraud, which would likely have a negative impact on the market price of our common units. In connection with the closing of our initial public offering, we became subject to the public reporting requirements of the Securities Exchange Act of1934, as amended, or the Exchange Act. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operatesuccessfully as a publicly traded partnership. Our efforts to develop and maintain our internal controls may not be successful, and we may be unable tomaintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes OxleyAct of 2002, or Section 404. For example, Section 404(a) requires us, among other things, to review and report annually on the effectiveness of our internalcontrol over financial reporting. We were required to comply with Section 404(a) for our fiscal year ended December 31, 2013. In addition, our independentregistered public accountants will be required to assess the effectiveness of internal control over financial reporting at the end of the fiscal year after we are nolonger an “emerging growth company” under the Jumpstart Our Business Startups Act, which may be for up to five fiscal years after the completion of ourinitial public offering in January 2013. Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harmour operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls overfinancial reporting, we can provide no assurance as to our independent registered public accounting firm’s conclusions about the effectiveness of our internalcontrols, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls will subject us to regulatory scrutiny and aloss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on thetrading price of our common units. 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, limitedability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner orits board of directors. USA Compression Holdings is the sole member of our general partner and will have the right to appoint our general partner’s entireboard of directors, including its independent directors. If the unitholders are dissatisfied with the performance of our general partner, they will have littleability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of theabsence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to callmeetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction ofmanagement. 20 Table of Contents USA Compression Holdings owns and controls our general partner, which has sole responsibility for conducting our business and managingour operations. Our general partner and its affiliates, including USA Compression Holdings, have conflicts of interest with us and limitedfiduciary 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 appointed all of theofficers and directors of our general partner, some of whom are also officers and directors of USA Compression Holdings. Although our general partner has afiduciary 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 tomanage our general partner in a manner that is beneficial to its owners. Conflicts of interest will arise between USA Compression Holdings, Riverstone andour 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 itsown interests and the interests of USA Compression Holdings and the other owners of USA Compression Holdings over our interests and the interests of ourcommon unitholders. These conflicts include the following situations, among others: · neither our partnership agreement nor any other agreement requires USA Compression Holdings to pursue a business strategy that favors us; · our general partner is allowed to take into account the interests of parties other than us, such as USA Compression Holdings, in resolving conflictsof interest; · our partnership agreement limits the liability of and reduces the fiduciary duties owed by our general partner, and also restricts the remediesavailable to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty; · except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval; · our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership interests and thecreation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders; · our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenancecapital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. Thisdetermination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated unitsto convert to common units; · our general partner determines which costs incurred by it are reimbursable by us; · our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowingis to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period; · our partnership agreement permits us to classify up to $36.6 million as operating surplus, even if it is generated from asset sales, non-workingcapital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinatedunits or to our general partner in respect of the general partner interest or the incentive distribution rights; · our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or enteringinto additional contractual arrangements with any of these entities on our behalf; · our general partner intends to limit its liability regarding our contractual and other obligations; 21 Table of Contents · our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80%of the common units; · our general partner controls the enforcement of the obligations that it and its affiliates owe to us; · our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and · 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 ourgeneral partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or ourunitholders. This election may result in lower distributions to our common unitholders in certain situations. 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 againstour assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that arenonrecourse 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 ourgeneral partner’s fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated toreimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments wouldreduce the amount of cash otherwise available for distribution to our unitholders. Our partnership agreement limits our general partner’s fiduciary duties to holders of our common and subordinated units. Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner would otherwise be held bystate fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, asopposed 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 consideronly 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, ouraffiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include: · how to allocate business opportunities among us and its affiliates; · whether to exercise its limited call right; · how to exercise its voting rights with respect to the units it owns; · whether to elect to reset target distribution levels; and · whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement. By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the provisionsdiscussed above. Even if holders of our common units are dissatisfied, they cannot remove our general partner without USA Compression Holdings’ consent. The unitholders are currently unable to remove our general partner because our general partner and its affiliates own sufficient units to be able to preventits removal. The vote of the holders of at least 66/% of all outstanding common and subordinated units voting together as a single class is required to removeour general partner. USA Compression Holdings owns an aggregate of 50.9% of our outstanding common and subordinated units. Also, if our general partneris removed without cause during the subordination period and no units held by the holders of the 2223 Table of Contents subordinated units or their affiliates (including the general partner and its affiliates) are voted in favor of that removal, all subordinated units willautomatically be converted into common units. A removal of our general partner under these circumstances would adversely affect our common units byprematurely eliminating their distribution and liquidation preference over our subordinated units, which would otherwise have continued until we had metcertain distribution and performance tests. Cause is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealablejudgment finding our general partner liable for actual fraud or willful misconduct in its capacity as our general partner. Cause does not include most cases ofcharges 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 mightotherwise 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 mightotherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement: · provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our generalpartner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subjectto any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity; · provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long assuch decisions are made in good faith, meaning that it believed that the decisions were in the best interest of our partnership; · provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assigneesresulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdictiondetermining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or,in the case of a criminal matter, acted with knowledge that the conduct was criminal; and · provides that our general partner will not be in breach of its obligations under the partnership agreement or its fiduciary duties to us or ourunitholders if a transaction with an affiliate or the resolution of a conflict of interest is: (a) approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seeksuch approval; (b) approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and itsaffiliates; (c) on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or (d) fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions thatmay be particularly favorable or advantageous to us. 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 ingood 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 theboard of directors of our general partner determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interestsatisfies either of the standards set forth in subclauses (c) and (d) above, then it will conclusively be deemed that, in making its decision, the board ofdirectors acted in good faith. 23 Table of Contents 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 itsincentive distribution rights, without the approval of the conflicts committee of its board of directors or the holders of our common units. Thiscould 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 highestlevel 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 ourdistributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will beadjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on percentageincreases 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 to maintain its general partnerinterest. 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 anaverage aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentivedistribution 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 existedimmediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growthprojects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our generalpartner 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 itsincentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on theinitial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributionsthat our common unitholders would have otherwise received had we not issued new common units to our general partner in connection with resetting the targetdistribution 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% ormore of any class of units then outstanding, other than our general partner, its affiliates, their direct transferees and their indirect transferees approved by ourgeneral 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 theconsent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of USA Compression Holdings to transfer all or a portion of itsownership 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 andofficers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers. 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 toreceive a higher rate of return than would otherwise be obtainable from lower-risk investments. Accordingly, as interest rates rise, the ability of investors toobtain higher risk-adjusted rates of return by purchasing government backed debt securities may cause a corresponding decline in demand for riskierinvestments generally, including yield based equity investments such as publicly traded partnership interests. Reduced demand for our common unitsresulting from investors seeking other more favorable investment opportunities may cause the trading price of our common units to decline. 24 Table of Contents 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 ourunitholders. The issuance by us of additional common units, including pursuant to our Dividend Reinvestment Plan (“DRIP”), or other equity securities ofequal or senior rank, will have the following effects: · our existing unitholders’ proportionate ownership interest in us will decrease; · the amount of cash available for distribution on each unit may decrease; · because a lower percentage of total outstanding units will be subordinated units during the subordination period, the risk that a shortfall in thepayment of the minimum quarterly distribution will be borne by our common unitholders will increase; · the ratio of taxable income to distributions may increase; · the relative voting strength of each previously outstanding unit may be diminished; and · the market price of the common units may decline. USA Compression Holdings may sell units in the public or private markets, and such sales could have an adverse impact on the trading price ofthe common units. USA Compression Holdings holds an aggregate of 5,337,977 common units and 14,048,588 subordinated units. All of the subordinated units willconvert into common units at the end of the subordination period and may convert earlier under certain circumstances. In addition, USA CompressionHoldings may acquire additional common units in connection with our DRIP. We have agreed to provide USA Compression Holdings with certain registrationrights for any common and subordinated units it owns. The sale of these units in the public or private markets could have an adverse impact on the price ofthe 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 assignto 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 isnot 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 yourcommon units at an undesirable time or price. You may also incur a tax liability upon a sale of your units. USA Compression Holdings owns an aggregate ofapproximately 22.2% of our outstanding common units. At the end of the subordination period, assuming no additional issuances of common units (otherthan upon the conversion of the subordinated units), USA Compression Holdings will own an aggregate of approximately 50.9% of our outstanding commonunits. 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 thepartnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in anumber of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearlyestablished 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 courtor government agency were to determine that: · we were conducting business in a state but had not complied with that particular state’s partnership statute; or 25 Table of Contents · your right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to takeother actions under our partnership agreement constitute “control” of our business. Unitholders may have liability to repay distributions that were wrongfully distributed to them. Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the DelawareRevised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution to you if the distribution would cause our liabilities to exceedthe 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 receivedthe 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 substitutedlimited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from thepartnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are countedfor purposes of determining whether a distribution is permitted. The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements. Our common units are listed on the NYSE. Because we are a publicly traded partnership, the NYSE does not require us to have a majority ofindependent 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 investors in certain corporations that are subject to all of the NYSE corporate governancerequirements. Please read Part III, Item 10 (“Directors, Executive Officers and Corporate Governance”). Pursuant to certain federal securities laws, our independent registered public accounting firm will not be required to attest to the effectiveness ofour internal control over financial reporting pursuant to Section 404 of the Sarbanes Oxley Act of 2002 for so long as we are an emerginggrowth company. We are required to disclose changes made in our internal control over financial reporting on a quarterly basis, and we are required to assess theeffectiveness of our controls annually. However, for as long as we are an “emerging growth company” under federal securities laws, our independent registeredpublic accounting firm will not be required to attest to the effectiveness of our internal control over financial reporting pursuant to Section 404. We could be anemerging growth company for up to five years from the date of our initial public offering, which occurred on January 18, 2013. Even if we conclude that ourinternal control over financial reporting is effective, our independent registered public accounting firm may still decline to attest to our assessment or may issuea report that is qualified if it is not satisfied with our controls or the level at which our controls are documented, designed, operated or reviewed, or if itinterprets the relevant requirements differently from us. Tax Risks to Common Unitholders Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federalincome tax purposes, which would subject us to entity level taxation, then our cash available for distribution to our unitholders would besubstantially 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 incometax purposes. We have not requested 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 asa 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 ourbusiness 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. 26 Table of Contents 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, whichis currently a maximum of 35%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporatedividends (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 upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, ifwe 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 ourunitholders, 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 distributionto 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 otherreasons, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise and other forms oftaxation. 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 theprior 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. The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial oradministrative changes or differing interpretations, possibly applied 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 byadministrative, legislative or judicial interpretation at any time. For example, judicial interpretations of the U.S. federal income tax laws may have a direct orindirect 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 apartnership. Moreover, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws thatwould affect the tax treatment of certain publicly traded partnerships. One such legislative proposal would have eliminated the qualifying income exception tothe treatment of all publicly traded partnerships as corporations, upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.We are unable to predict whether any of these or any other proposals, will be reintroduced, introduced or will ultimately be enacted. Any such changes ordiffering 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 acorporation or otherwise subjects us to entity level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and thetarget distribution amounts may be adjusted to reflect the impact of that law on us. Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributionsfrom us. Because a unitholder will be treated as a partner to whom we will allocate taxable income that could be different in amount than the cash we distribute, aunitholder’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 andlocal income taxes, on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributionsfrom us equal to their share of our taxable income or even equal to the actual tax liability that results from that income. 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 IRScontest 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 report or from the positions we take, and the IRS’s positionsmay ultimately be sustained. 27 Table of Contents 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 maynot 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 amaterially 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 beborne 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 realizedand 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 theircommon units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable incometo 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 dueto potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourseliabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale. Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences tothem. 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, includingIRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be subject towithholding taxes imposed at the highest tax rate applicable to such non-U.S. persons, and each non-U.S. person will be required to file U.S. federal incometax returns and pay tax on its share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult a tax advisor beforeinvesting 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 IRSmay 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 amortizationpositions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amountof 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 orthe 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 adjustments to yourtax returns. We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units eachmonth 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 monthbased 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 thisproration method may not be permitted under existing Treasury Regulations. The U.S. Treasury Department’s proposed Treasury Regulations allowing asimilar monthly simplifying convention are not final and do not specifically authorize the use of the proration method we have adopted. If the IRS were tochallenge our proration method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss anddeduction among our unitholders. 28 Table of Contents A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to effect a short sale of common units) maybe considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner withrespect to those common units during the period of the loan and may recognize gain or loss from the disposition. Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose common units arethe subject of a securities loan may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposesas 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 suchdisposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable bythe unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiringto assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to discuss whether it isadvisable 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 thevalue 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 unrealizedgain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating thevalue 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 beunfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their InternalRevenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge ourvaluation 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. Italso 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 orresult 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 ourpartnership 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 inour capital and profits within a twelve month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interestwill be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which wouldresult 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 calendar yearand 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 otherthan a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxableincome for the year of termination. A technical termination currently would not affect our classification as a partnership for federal income tax purposes, butinstead 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 subjectto penalties if we are unable to determine that a termination occurred. The IRS has announced a publicly traded partnership technical termination reliefprogram whereby a publicly traded partnership that technically terminated may request publicly traded partnership technical termination relief which, ifgranted by the IRS, among other things would permit the partnership to provide only one Schedule K-1 to unitholders for the year notwithstanding twopartnership tax years. 29 Table of Contents As a result of investing in our common units, you will likely become subject to state and local taxes and return filing requirements in jurisdictionswhere 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 andestate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, evenif 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 incometaxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. Wecurrently conduct business in thirteen states. Many of these states currently impose a personal income tax on individuals. Many of these states also impose anincome tax on corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional statesor foreign jurisdictions that impose a personal income tax. It is your responsibility to file all foreign, federal, state and local tax returns. ITEM 1B. Unresolved Staff Comments None. ITEM 2. Properties We do not currently own or lease any material facilities or properties for storage or maintenance of our compression units. As of December 31, 2013, ourheadquarters consisted of 11,307 square feet of leased space located at 100 Congress Avenue, Austin, Texas 78701. ITEM 3. Legal Proceedings None. ITEM 4. Mine Safety Disclosures None. PART II ITEM 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Our Partnership Interests As of February 18, 2014, we had outstanding 24,034,240 common units, 14,048,588 subordinated units, a 2% general partner interest and incentivedistribution rights, or IDRs. As of February 18, 2014, USA Compression Holdings, LLC owned approximately 22.2% of our outstanding common units and100% of our subordinated units. Our general partner currently owns a 2.0% general partner interest in us and all of our IDRs. As discussed below under“Selected Information from Our Partnership Agreement— General Partner Interest and IDRs,” the IDRs represent the right to receive increasing percentages, upto a maximum of 48%, of the cash we distribute from operating surplus (as defined below) in excess of $0.4888 per unit per quarter. Our common units,which represent limited partner interests in us, are listed on the New York Stock Exchange (“NYSE”) under the symbol “USAC.” Our common units have been traded on the NYSE since January 15, 2013, and therefore, we have not set forth quarterly information with respect to thehigh and low prices for our common units for periods prior to that date. The following table sets forth high and low sales prices per common unit and cashdistributions per common unit to common unitholders for the periods indicated. The last reported sales price for our common units on February 18, 2014,was $26.23. 30 Table of Contents CashDistributionPrice RangePer CommonPeriodHighLowUnitDate Paid First Quarter 2013(1)$20.00$17.25$0.348(2)May 14, 2013Second Quarter 2013$23.72$18.77$0.44August 14, 2013Third Quarter 2013$26.50$22.50$0.46November 14, 2013Fourth Quarter 2013$27.12$22.07$0.48February 14, 2014 (1) Beginning on January 15, 2013 the first day our common units were traded on the NSYE.(2) Prorated to reflect 72 days of a quarterly cash distribution rate of $0.435 per unit. Holders At the close of business on February 18, 2014, we had 27 holders of record of our common units. The number of record holders does not include holdersof shares in “street names” or persons, partnerships, associations, corporations or other entities identified in security position listings maintained bydepositories. Selected Information from our Partnership Agreement Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions, minimum quarterly distributionsand IDRs. Available Cash Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnershipagreement) to unitholders of record on the applicable record date. Our partnership agreement generally defines available cash, for each quarter, as cash on handat the end of a quarter less the amount of reserves established by our general partner to provide for the proper conduct of our business, comply with applicablelaw, our revolving credit facility or other agreements; and provide fund for distributions to our unitholders for any one or more of the next four quarters pluscash on hand resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are borrowings made under a creditfacility, commercial paper facility or other similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributionsto partners and with the intent of the borrower to repay such borrowings within twelve months from sources other than working capital borrowings. Minimum Quarterly Distribution Our partnership agreement provides that, during the subordination period, the common units will have the right to receive distributions of available cashfrom operating surplus each quarter in an amount equal to $0.425 per common unit, which amount is defined in our partnership agreement as the minimumquarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before anydistributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period oftime, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received theminimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practicaleffect of the subordinated units is to increase the likelihood that during the subordination period there will be available cash to be distributed on the commonunits. On January 23, 2014, the Partnership announced a cash distribution of $0.48 per unit on its common and subordinated units. This fourth quarterdistribution corresponds to an annualized distribution rate of $1.92 per unit. The distribution was paid on February 14, 2014 to unitholders of record as ofthe close of business on February 4, 2014. USA Compression Holdings, and Argonaut Private Equity, L.L.C. (“Argonaut”) and certain other relatedunitholders elected to reinvest all of this distribution with respect to their units pursuant to the Partnership’s Distribution Reinvestment Plan (“DRIP”).Following the issuance of common units under the DRIP, USAC Compression Holdings owned 50.9% of the Partnership’s outstanding limited partnerinterests, and Argonaut and the related parties participating in the DRIP, owned 19.4% of the Partnership’s outstanding limited partner interests. 31 Table of Contents General Partner Interest and IDRs Our partnership agreement provides that our general partner initially will be entitled to 2.0% of all distributions that we make. Our general partner has theright, 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. Ourgeneral 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 unitsin the future (other than the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of theincentive distribution rights) and our general partner does not contribute a proportionate amount of capital to us in order to maintain its 2.0% general partnerinterest. Our partnership agreement does not require that the general partner fund its capital contribution with cash and our general partner may fund its capitalcontribution by the contribution to us of common units or other property. Incentive distribution rights represent the right to receive increasing percentages (13.0%, 23.0% and 48.0%) of quarterly distributions of available cashfrom operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. Our general partner currently holds theincentive distribution rights, but may transfer these rights separately from its general partner interest. Issuer Purchases of Equity Securities None. Sales of Unregistered Securities; Use of Proceeds from Sale of Securities On January 18, 2013, we completed our IPO of common units pursuant to a Registration Statement on Form S-1, as amended (Reg. No. 333-174803), thatwas declared effective on January 14, 2013. Under the registration statement, we sold an aggregate of 11,000,000 common units at a price to the public of$18.00 per common unit. Barclays Capital Inc. and Goldman, Sachs & Co. acted as joint book-running managers of the offering. The offering closed onJanuary 18, 2013. As a result of our IPO, we raised a total of $198.0 million in gross proceeds, and approximately $180.5 million in net proceeds afterdeducting underwriting discounts and commissions of $12.2 million, structuring fees of $0.7 million and offering expenses of $4.6 million. On August 30, 2013, in connection with the acquisition from S&R of certain assets and liabilities related to the business of providing compressionservices to third parties engaged in the exploration, production, gathering, processing, transportation or distribution of oil and gas (the “S&R Acquisition”),the Partnership issued 7,425,261 common units to certain accredited investors (the “Holders”) who are members or beneficial owners of S&R or itscontrolling member, Argonaut Private Equity, L.L.C. (“Argonaut”). The common units issued in connection with the S&R Acquisition were issued in a private placement in reliance upon an exemption from the registrationrequirements of the Securities Act, pursuant to Section 4(a)(2) thereof. In connection with the S&R Acquisition, we entered into a registration rights agreementwith Argonaut and the other Holders pursuant to which we agreed to register the common units issued in connection with the S&R Acquisition. On February 3,2014, we filed a Registration Statement on Form S-3 (File No. 333-193724) (the “S-3 Registration Statement”). Until such time as the S-3 RegistrationStatement is declared effective by the SEC, the common units issued in connection with the S&R Acquisition may not be offered or sold in the United Statesabsent an applicable exemption from the registration requirements of the Securities Act and applicable state securities laws. Equity Compensation Plan For disclosures regarding securities authorized for issuance under equity compensation plans, see Part III, Item 12 “Security Ownership of CertainBeneficial Owners and Management and Related Stockholder Matters” of this report. 32 Table of Contents ITEM 6. Selected Financial Data SELECTED HISTORICAL FINANCIAL DATA In the table below we have presented certain selected financial data for USA Compression Partners, LP for each of the five years in the period endedDecember 31, 2013, which has been derived from our audited consolidated financial statements. The following information should be read together withManagement’s Discussion and Analysis of Financial Condition and Results of Operations and the Financial Statements contained in Item 7 of this report. We were acquired by USA Compression Holdings on December 23, 2010, which we refer to as the Holdings Acquisition. In connection with thisacquisition, our assets and liabilities were adjusted to fair value on the closing date by application of “push-down” accounting. Due to these adjustments, ouraudited condensed consolidated financial statements are presented in two distinct periods to indicate the application of two different bases of accountingbetween the periods presented: (i) the periods prior to the acquisition date for accounting purposes, using a date of convenience of December 31, 2010, areidentified as “Predecessor,” and (ii) the periods from December 31, 2010 forward are identified as “Successor.” The following table includes the non-GAAP financial measure of Adjusted EBITDA. We define Adjusted EBITDA as our net income before interestexpense, income taxes, depreciation and amortization expense, impairment of compression equipment, unit-based compensation expense, restructuringcharges, management fees, expenses under our operating lease with Caterpillar, certain fees and expenses related to the Holdings Acquisition and transactionexpenses for the S&R Acquisition. For a reconciliation of Adjusted EBITDA to its most directly comparable financial measures calculated and presented inaccordance with GAAP, please read “—Non-GAAP Financial Measures.” Successor(1)PredecessorYears ended December 31,Years ended December 31,20132012201120102009(in thousands)(in thousands)Revenues:Contract operations$150,360$116,373$93,896$89,785$93,178Parts and service2,5582,4144,8242,2432,050Total revenues152,918118,78798,72092,02895,228Costs and expenses:Cost of operations48,09737,79639,60533,29230,096Selling, general and administrative27,58718,26912,72611,3709,136Restructuring charges(2)——300——Depreciation and amortization52,91741,88032,73824,56922,957(Gain) loss of sale of assets284266178(90)(74)Impairment of compression equipment203———1,677Total costs and expenses129,08898,21185,54769,14163,792Operating income23,83020,57613,17322,88731,436Other income (expense):Interest expense(12,488)(15,905)(12,970)(12,279)(10,043)Other928212625Total other expense(12,479)(15,877)(12,949)(12,253)(10,018)Income before income tax expense11,3514,69922410,63421,418Income tax expense(3)280196155155190Net income$11,071$4,503$69$10,479$21,228Adjusted EBITDA$81,130$63,484$51,285$51,987$56,917Other Financial Data:Capital expenditures(4)$159,547$179,977$133,264$18,886$29,580Cash flows provided by (used in):Operating activities68,19041,97433,78238,57242,945Investing activities(153,946)(178,589)(140,444)(18,768)(26,763)Financing activities85,756136,619106,662(19,804)(16,545) 33 Table of Contents Successor(1)PredecessorYears ended December 31,Years ended December 31,20132012201120102009(in thousands)(in thousands)Balance Sheet Data (at period end):Working capital(5)$(24,177)$(12,076)$(11,295)$(3,984)$(4,678)Total assets1,185,884872,645727,876614,718352,757Long-term debt420,933502,266363,773255,491260,470Partners’ equity707,727343,526339,023338,95472,626 (1) Reflects the push-down of the purchase accounting for the Holdings Acquisition.(2) During the year ended December 31, 2011, we incurred $0.3 million of restructuring charges for severance and retention benefits related to the terminationof certain administrative employees. These charges are reflected as restructuring charges in our consolidated statement of operations. These restructuringcharges were paid in 2012.(3) This represents the Texas franchise tax (applicable to income apportioned to Texas) which, in accordance with Financial Accounting Standards BoardAccounting Standards Codification 740 “Income Taxes,” or ASC 740, is classified as income tax for reporting purposes.(4) On December 15, 2011, we purchased all the compression units previously leased from Caterpillar for $43 million and terminated all the lease schedulesand covenants under the facility. This amount is included in capital expenditures for the year ended December 31, 2011. On December 16, 2011, thePartnership entered into an agreement with a compression equipment supplier to reduce certain previously made progress payments from $10 million to$2 million. The Partnership applied this $8 million credit to new compression unit purchases from this supplier in the year ended December 31, 2012.Before the application of this credit, capital expenditures were $188.0 million for the year ended December 31, 2012.(5) Working capital is defined as current assets minus current liabilities. Non-GAAP Financial Measures We define Adjusted EBITDA as our net income before interest expense, income taxes, depreciation and amortization expense, impairment of compressionequipment, unit based compensation expense, restructuring charges, management fees, expenses under our operating lease with Caterpillar, certain fees andexpenses related to the Holdings Acquisition and transaction expenses for the S&R Acquisition. We view Adjusted EBITDA as one of our primarymanagement 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, prior year and to budget. Adjusted EBITDA is used as a supplemental financial measure by our management and external users of our financialstatements, such as investors and commercial banks, to assess: · the financial performance of our assets without regard to the impact of financing methods, capital structure or historical cost basis of our assets; · the viability of capital expenditure projects and the overall rates of return on alternative investment opportunities; · the ability of our assets to generate cash sufficient to make debt payments and to make distributions; and · our operating performance as compared to those of other companies in our industry without regard to the impact of financing methods and capitalstructure. We believe that Adjusted EBITDA provides useful information to investors because, when viewed with our GAAP results and the accompanyingreconciliations, it provides a more complete understanding of our performance than GAAP results alone. We also believe that external users of our financialstatements 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 operatingactivities 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. 34 Table of Contents Adjusted EBITDA does not include interest expense, income taxes, depreciation and amortization expense, impairment of compression equipment, unit-based compensation expense, restructuring charges, management fees, expenses under our operating lease with Caterpillar, certain fees and expenses related tothe Holdings Acquisition and transaction expenses for the S&R Acquisition. Because we borrow money under our revolving credit facility and havehistorically utilized operating leases to finance our operations, interest expense and operating lease expense are necessary elements of our costs. Because we usecapital assets, depreciation and impairment of compression equipment is also a necessary element of our costs. Expense related to unit-based compensationexpense related to equity awards to employees is also necessary to operate our business. Therefore, measures that exclude these elements have materiallimitations. To compensate for these limitations, we believe that it is important to consider both net income and net cash provided by operating activitiesdetermined under GAAP, as well as Adjusted EBITDA, to evaluate our financial performance and our liquidity. Our Adjusted EBITDA excludes some, butnot all, items that affect net income and net cash provided by operating activities, and these measures may vary among companies. Management compensatesfor the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between themeasures and incorporating this knowledge into management’s decision making processes. The following table reconciles Adjusted EBITDA to net income and net cash provided by operating activities, its most directly comparable GAAPfinancial measures, for each of the periods presented: Successor(1)PredecessorYears ended December 31,Years ended December 31,20132012201120102009(in thousands)(in thousands)Net income$11,071$4,503$69$10,479$21,228Interest expense12,48815,90512,97012,27910,043Depreciation and amortization52,91741,88032,73824,56922,957Income taxes280196155155190Impairment of compression equipment(2)203———1,677Unit-based compensation expense1,343——382269Equipment operating lease expense(3)——4,0532,285553Riverstone management fee(4)491,0001,000——Restructuring charges(5)——300——Fees and expenses related to the Holdings Acquisition(6)———1,838—Transaction expenses for S&R Acquisition (7)2,142————Other637————Adjusted EBITDA$81,130$63,484$51,285$51,987$56,917Interest expense(12,488)(15,905)(12,970)(12,279)(10,043)Income tax expense(280)(196)(155)(155)(190)Equipment operating lease expense(3)——(4,053)(2,285)(553)Unit-based compensation expense(1,343)——(382)(269)Riverstone management fee(4)(49)(1,000)(1,000)——Restructuring charges(5)——(300)——Impairment of compression equipment(2)(203)———(1,677)Fees and expenses related to the Holdings Acquisition(6)———(1,838)—Transaction expenses for S&R Acquisition(7)(2,142)————Other3,386(58)(920)3,7442,234Changes in operating assets and liabilities:Accounts receivable and advance to employee(11,675)169(976)(336)1,865Inventory(5,725)(1,004)1,974503(3,680)Prepaids(601)(153)(219)(18)608Other non-current assets3,824(1,315)(2,601)1(4)Accounts payable8,133(5,340)1,987(825)(857)Accrued liabilities and deferred revenue6,2233,2921,730455(1,406)Net cash provided by operating activities$68,190$41,974$33,782$38,572$42,945 (1) Reflects the push-down of the purchase accounting for the Holdings Acquisition. (2) 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. (3) Represents expenses for the respective periods under the operating lease facility with Caterpillar, from whom we historically leased compression units andother equipment. On December 15, 2011, we purchased the compression units that were previously leased from Caterpillar for $43 million andterminated all the lease schedules and covenants under the facility. As such, we believe it is useful to investors to view our results excluding these leasepayments. 35 Table of Contents (4) Represents management fees paid to Riverstone for services performed during 2013, 2012 and 2011. As these fees are not paid by us as a publiccompany, we believe it is useful to investors to view our results excluding these fees. (5) During the year ended December 31, 2011, we incurred $0.3 million of restructuring charges for severance and retention benefits related to the terminationof certain administrative employees. These charges are reflected as restructuring charges in our consolidated statement of operations. These restructuringcharges were paid in 2012. We believe that it is useful to investors to view our results excluding this non-core expense. (6) 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 expectto incur similar fees or expenses in the future as a publicly traded partnership. (7) Represents S&R transaction expenses incurred during the third and fourth quarter of 2013. As these fees are not recurring, the Partnership believes it isuseful to investors to view its results excluding these fees. We define distributable cash flow as net income (loss) plus non-cash interest expense, depreciation and amortization expense, impairment of compressionequipment charges, and non-cash SG&A costs, less maintenance capital expenditures. We define adjusted distributable cash flow as distributable cash flowplus certain one-time transaction expenses for the S&R Acquisition. We believe distributable cash flow and adjusted distributable cash flow are an importantmeasures of operating performance because they allow management, investors and others to compare basic cash flows we generate (prior to the establishment ofany retained cash reserves by our general partner) to the cash distributions we expect to pay our unitholders. Using distributable cash flow and adjusteddistributable cash flow, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Our distributable cashflow may not be comparable to a similarly titled measure of another company because other entities may not calculate distributable cash flow in the samemanner. Distributable cash flow and adjusted distributable cash flow are not measures of financial performance under GAAP, and should not be considered inisolation or as an alternative to net income (loss), cash flows from operating activities and other measures determined in accordance with GAAP. Itemsexcluded from distributable cash flow and adjusted distributable cash flow are significant and necessary components to the operations of our business, and,therefore, distributable cash flow and adjusted distributable cash flow should only be used as a supplemental measure of our operating performance. The following table reconciles our net income to distributable cash flow and adjusted distributable cash flow for each of the periods presented (inthousands): Successor(1)PredecessorYears Ended December 31,Years Ended December 31,20132012201120102009Net income$11,071$4,503$69$10,479$21,228Plus: Non-cash interest expense2,2011,855(1,057)3,449363Plus: Depreciation and amortization52,91741,88032,73824,56922,957Plus: Unit-based compensation expense1,343——382269Plus: Impairment of compression equipment203———1,677Less: Maintenance capital expenditures(2)14,30413,3108,96113,0189,354Distributable cash flow$53,431$34,928$22,789$25,861$37,140Transaction expenses for S&R Acquisition and other(3)2,779————Adjusted distributable cash flow$56,210$34,928$22,789$25,861$37,140 (1) Reflects the push-down of the purchase accounting for the Holdings Acquisition. (2) Reflects actual maintenance capital expenditures for the period presented. Maintenance capital expenditures are capital expenditures made to replacepartially or fully depreciated assets, to maintain the operating capacity of our assets and extend their useful lives, or other capital expenditures thatare incurred in maintaining our existing business and related cash flow. (3) Reflects $2.1 million of transaction expenses for the S&R Acquisitions and $0.7 million of nonrecurring expenses, for 2013. 36 Table of Contents ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidatedfinancial statements, the notes thereto, and the other financial information appearing elsewhere in this report. The following discussion includesforward-looking statements that involve certain risks and uncertainties. See Part I (“Disclosure Regarding Forward-Looking Statements”) andPart I, Item 1A (“Risk Factors”) in this report. 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 thelargest independent providers of compression services in the U.S. in terms of total compression unit horsepower. We have been providing compression servicessince 1998. As of December 31, 2013, we had 1,202,374 horsepower in our fleet and approximately 180,000 horsepower on order for expected deliveryprimarily in the first half of 2014. Our primary focus is to provide compression services to our customers in connection with infrastructure applications.Natural gas compression is a mechanical process whereby natural gas is compressed to a smaller volume, resulting in higher pressure. This process hasvarious applications, including both allowing for the transportation of the natural gas through the domestic pipeline system and enhancing crude oilproduction through artificial lift processes. As such, our compression services play a critical role in the production and transportation of both natural gas andcrude oil. We provide compression services in a number of shale plays throughout the U.S., including the Marcellus, Eagle Ford, Utica, Mississippi Lime, GraniteWash, Woodford, Barnett, Permian Basin, Haynesville and Fayetteville shales. Because the demand for our services is driven by production of natural gasand crude oil, we have focused our activities in areas of attractive growth, which are generally found in these shale and unconventional resource plays. Further, we believe production in these areas will increase in the future. According to the 2013 Outlook prepared by the EIA, natural gas production from shaleformations is expected to increase from 34% of total U.S. natural gas production in 2011 to 50% of total U.S. natural gas production in 2040. In addition, theEIA forecasts in its 2013 Outlook that total domestic crude oil production will increase by 33% from 2011 to 2019, and more importantly, forecasts tight oilproduction to increase by 128% over the same time period. Not only are the production and transportation volumes in these and other shale plays increasing,the geological and reservoir characteristics are also particularly attractive for compression services. The changes in production volume and pressure of shaleplays over time result in a wider range of compression requirements than in conventional basins. We believe we are well-positioned to meet these changingoperating conditions as a result of the flexibility of our compression units. While our business focuses largely on compression services in shale plays, we alsoprovide compression services in more mature conventional basins, including crude oil wells targeted by horizontal drilling techniques. Wells in conventionalbasins typically require increasing amounts of compression as they age and pressures decline. In addition, the continued development of horizontal drilling,particularly in crude oil wells, has allowed producers to produce incremental volumes of crude oil on attractive economic terms. Our gas lift fleet, critical toproducing oil from horizontal wells, serves this growing market demand. We operate in a single business segment, the compression service business. We provide our customers with compression services to maximize theirnatural gas and crude oil production, throughput and cash flow. We provide domestic compression services to major oil companies and independentproducers, processors, gatherers and transporters of natural gas and crude oil using our modern, flexible fleet of compression units, which have been designedto be rapidly deployed and redeployed throughout the country. As part of our services, we engineer, design, operate, service and repair our compression unitsand maintain related support inventory and equipment. We provide compression services to our customers under fixed-fee contracts, with initial contract terms of up to five years for midstream applications andsix to twelve months for crude oil gas lift applications. We typically continue to provide compression services to our customers beyond their initial contractterms, either through contract renewals or on a month-to-month basis. For the year ended December 31, 2013, approximately 38% of our compression serviceson a horsepower basis (and 43% on a revenue basis) were provided to customers under contracts continuing on a month to month basis. We generally enter intotake-or-pay contracts whereby our customers are required to pay our monthly fee even during periods of limited or disrupted throughput, which enhances thestability and predictability of our cash flows. We are not directly exposed to commodity price risk 37 Table of Contents 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 customerswithout 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 themajority of our contracts. As of December 31, 2013, we estimate that approximately 89% of our revenue generating horsepower was deployed in infrastructureapplications, including large volume gathering systems, processing facilities, transportation applications and crude oil gas lift. General Trends and Outlook Following a period of decreasing market rates in 2009 and 2010, when we elected to sign shorter-term contracts to limit our long-term exposure to lowermarket rates, rates have improved and generally stabilized starting in 2011 and continue improving throughout 2013. We have experienced some pricingpressure on certain of our midstream compression units during 2013. However, over the long term, we expect that continued improved pricing will ultimatelyimprove our average monthly revenue per revenue generating horsepower as contracts that we entered into in 2009 and early 2010 expire and we enter into newcontracts at higher rates. In our gas lift fleet, we have continued to experience strong market demand and, as a result, attractive pricing. We intend to grow thenumber of midstream and gas lift units in our fleet. While larger horsepower units used in midstream applications in general allow us to generate higher grossoperating margins than gas lift 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 theutilization of idle compression units. During 2011, we began to see an increase in overall natural gas activity in the U.S. and experienced an increase indemand for our compression services that has continued through 2012 and 2013. The generally strong activity in crude oil production in our core gas liftregions has also contributed to increased demand for our services. Revenue generating horsepower increased by 34.8% from December 31, 2012 toDecember 31, 2013, in part due to the S&R Acquisition. Average revenue generating horsepower increased by 20.3%, primarily due to growth in our coremidstream compression business along with the S&R Acquisition, from the year ended December 31, 2012 to the year ended December 31, 2013. We believethe natural gas activity levels in the U.S. will continue to increase in the foreseeable future, particularly in shale plays, with respect to natural gas, as well ascrude oil. 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 and crude oil activity and demand for our compression services may not occur for a variety of reasons.Please read Part I, Item 1A. “Risk Factors — Risks Related to Our Business — A long-term reduction in the demand for, or production of, natural gas orcrude 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 adecrease in our revenues and cash available for distribution to our unitholders.” Factors That Affect Our Future Results Customers We provide compression services to major oil companies and independent producers, processors, gatherers and transporters of natural gas and crude oil,and operate in a number of U.S. natural gas shale plays, including the Fayetteville, Marcellus, Woodford, Barnett, Eagle Ford, Utica, Permian Basin andHaynesville shales. Our customers use our services primarily in large volume gathering systems, processing facilities and transportation applications as wellas in gas-lift compression for crude oil wells. Regardless of the application for which our services are provided, our customers rely upon the availability of theequipment used to provide compression services and our expertise to help generate the maximum throughput of product, reduce fuel costs and reduceemissions. While we are currently focused on our existing service areas, our customers have compression demands in other areas of the U.S. in conjunctionwith their field development projects. We continually consider expansion of our areas of operation in the U.S. based upon the level of customer demand. Ourmodern, flexible fleet of compression units, which have been designed to be rapidly deployed and redeployed throughout the country, provides us withcontinuing opportunities to expand into other areas with both new and existing customers. From April 2008 through December 2013, we redeployedapproximately 66,900 horsepower of our compression units from our Central operating region to our Northeast operating region, which includes the Marcellusshale, to meet increasing customer demand in that geographic area. 38 Table of Contents Many of our customers have access to low-cost capital, made available by banks and equipment manufacturers, and have elected to access this capital toadd compression units to their owned compression fleets. Additional purchases of compression equipment by our customers may result in reduced demand forour compression services by these customers, which could materially reduce our results of operations and ability to make cash distributions to ourunitholders. Supply and Demand for Natural Gas and Crude Oil 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 andconsumers. The EIA forecasts in its 2013 Outlook that natural gas production in the U.S. is expected to increase by approximately 44% from 2011 to 2040. Webelieve this long-term increasing demand for natural gas will create increasing demand for compression services, for both existing natural gas fields as they ageand 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 oftenhave lower producing pressures than conventional reservoirs, results in a further increase in compression needs. In the short-term, changes in natural gaspricing, based primarily upon the supply of natural gas, will affect the development activities of natural gas producers based upon the costs associated withfinding 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 ashort-term negative effect on the development activity in natural gas fields, periods of lower development activity tend to place emphasis on improvingproduction efficiency. As a result of our commitment to providing a high level of availability of the equipment used to provide compression services, we believeour service run times position us to satisfy the needs of our customers. The continued development of horizontal drilling, particularly in crude oil wells, has allowed producers to produce incremental volumes of crude oil fromtight oil formations on attractive economic terms. The EIA forecasts in its 2013 Outlook that total domestic crude oil production will increase by 33% from2011 to 2019, and more importantly, forecasts tight oil production to increase by 128% over the same time period. Gas lift and other artificial lift technologiesare critical to the enhancement of production of oil from horizontal wells operating in tight shale plays. Gas lift is a process by which natural gas is injectedinto the production tubing, thus reducing the hydrostatic pressure and allowing the oil to flow at a higher rate. We believe that our flexible fleet of smallerhorsepower units that are primarily utilized in gas lift applications will enable us to capitalize on this growing market demand. Access to External Expansion Capital 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 setaside 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 financingsources, including borrowings under our revolving credit facility and issuances of debt and equity securities, rather than cash reserves, to fund our expansioncapital expenditures. To the extent we are unable to finance growth externally and are unwilling to establish cash reserves to fund future expansions, our cashavailable for distribution will not significantly increase. In addition, because we distribute all of our available cash, we may not grow as quickly asbusinesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any expansion capitalexpenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unitdistribution 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. 39 Table of Contents Operating Highlights The following table summarizes certain horsepower and horsepower utilization percentages for the periods presented. Year EndedDecember 31,Percent ChangeOperating Data (unaudited):20132012201120132012Fleet horsepower(1)1,202,374919,121722,20130.8%27.3%Total available horsepower(2)1,278,829935,681809,41836.7%15.6%Revenue generating horsepower(3)1,070,457794,324649,28534.8%22.3%Average revenue generating horsepower(4)902,168749,821570,90020.3%31.3%Average revenue per revenue generating horsepowerper month$14.15$13.39$14.075.7%(4.8)%Revenue generating compression units2,137978888118.5%10.1%Average horsepower per revenuegenerating compression unit(5)720791692(9.0)%14.3%Horsepower utilization(6):At period end94.1%92.8%95.7%1.4%(3.0)%Average for the period(7)93.8%94.5%92.3%(0.7)%2.4% (1) Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order). As of December 31, 2013, we hadapproximately 180,000 horsepower on order for delivery which is expected to be delivered primarily in the first half of 2014. (2) Total available horsepower is revenue generating horsepower under contract for which we are billing a customer, horsepower in our fleet that is undercontract 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 purchaseorder, 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 generatingrevenue 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) totalavailable horsepower less idle horsepower that is under repair. Horsepower utilization based on revenue generating horsepower and fleet horsepower at eachapplicable period end was 89.0%, 86.4% and 89.9%, for the years ended December 31, 2013, 2012 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, 2013 compared to December 31, 2012 is attributable to the compression units added to our fleet tomeet the incremental demand by new and current customers and the S&R Acquisition. Revenue generating horsepower increased by 34.8% from December 31,2012 to December 31, 2013 primarily due to organic growth in our core midstream fleet and acquiring compression units under contract in connection with theS&R Acquisition. The average horsepower per revenue generating compression unit decreased from 791 to 720, or (9.0)%, over that same period, due to thesmaller horsepower gas lift units that were added to the fleet in the S&R Acquisition. The increase in fleet horsepower as of December 31, 2012 compared toDecember 31, 2011 is attributable to the compression units added to our fleet to meet the incremental demand by new and current customers. Revenuegenerating horsepower increased by 22.3% from December 31, 2011 to December 31, 2012, primarily due to organic growth and increasing customer demand.The average horsepower per revenue generating compression unit increased from 692 to 791 between 2011 and 2012, primarily due to our focus during thatperiod on the addition of large horsepower compression units. Year Ended December 31,Percent ChangeOther Financial Data:20132012201120132012(in thousands)Gross Operating Margin(1)$104,821$80,991$59,11529.4%37.0%Gross operating margin percentage(2)68.5%68.2%59.9%0.5%13.9%Adjusted EBITDA(3)81,13063,48451,28527.8%23.8%Adjusted EBITDA percentage(2)53.1%53.4%51.9%(0.6)%2.9% (1) Gross operating margin is a non-GAAP financial measure. We calculate gross operating margin as revenue less cost of operations, exclusive ofdepreciation and amortization expense. We believe that gross operating margin is useful as a supplemental measure of our operating profitability. Grossoperating margin should not be considered an alternative to, or more meaningful than, operating income or any other measure of financial performancepresented in accordance with GAAP. Moreover, gross operating margin as presented may not be comparable to similarly titled measures of othercompanies. Because we capitalize assets, depreciation and amortization of equipment is a necessary element of our costs. To compensate for thelimitations 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. For more information, please read “Item 6 — Selected HistoricalFinancial Data — Non-GAAP Financial Measures.” 40 Table of Contents The following table reconciles gross operating margin to operating income, its most directly comparable GAAP financial measure, for each of the periodspresented: Year Ended December 31,201320122011(in thousands)Revenues:Contract operations$150,360$116,373$93,896Parts and service2,5582,4144,824Total revenues152,918118,78798,720Cost of operations, exclusive of depreciation and amortization48,09737,79639,605Gross operating margin104,82180,99159,115Other operating and administrative costs and expenses:Selling, general and administrative27,58718,26912,726Restructuring charges——300Depreciation and amortization52,91741,88032,738(Gain) loss on sale of assets284266178Impairment of compression equipment203——Total other operating and administrative costs and expenses80,99160,41545,942Operating income$23,830$20,576$13,173 (2) Gross operating margin percentage and Adjusted EBITDA percentage are calculated as a percentage of revenue. (3) For a reconciliation of Adjusted EBITDA, a non-GAAP financial measure, to net income and cash flows from operating activities, its most directlycomparable GAAP financial measures, see “Item 6 — Selected Historical Financial Data—Non-GAAP Financial Measures.” Gross operating margin, as a percentage of total revenues, increased to 68.5% in 2013 from 68.2% in 2012. The increase in gross operating margin wasprimarily attributable to a 28.7% increase in total revenues when comparing the periods, partially offset by an increase of 27.3% in cost of operations. Averagerevenue generating horsepower increased from 749,821 in 2012 to 902,168 in 2013, an increase of 20.3%, primarily due to compression units added to ourfleet to meet the incremental demand by new and current customers and the S&R Acquisition. Average revenue per revenue generating horsepower per monthincreased to $14.15 in 2013 from $13.39 in 2012, an increase of 5.7%. The increase in average revenue per revenue generating horsepower per month wasprimarily due to higher revenue per horsepower per month from the gas lift compression units that were acquired from S&R. The increase in cost of operationsis primarily attributable to (1) a $2.8 million increase in lubrication oil expenses due to a 21.7% increase in gallons consumed, offset by a 3.9% decrease inthe average supplier price per gallon, (2) a $4.3 million increase in direct labor expenses, (3) a $0.9 million increase in training and safety expense, (4) a $0.4million increase in maintenance parts and (5) a $0.6 million increase related to vehicle tools and gasoline. These factors are attributable primarily to theincrease in our fleet size due to organic growth and four months of operations related to the assets acquired in the S&R Acquisition. In addition, business andproperty insurance increased by $0.4 million primarily due to certain insurance claims on our compression units and the increase in the size of our fleet. Gross operating margin, as a percentage of total revenues, increased to 68.2% in 2012 from 59.9% in 2011. The increase in gross operating marginpercentage was primarily attributable to a 20.3% increase in total revenues when comparing the periods, and a 4.6% decrease in cost of operations. Averagerevenue generating horsepower increased from 570,900 in 2011 to 749,821 in 2012, an increase of 31.3%, primarily due to organic growth and increasingcustomer demand. Average revenue per revenue generating horsepower per month declined to $13.39 in 2012 from $14.07 in 2011, a decrease of 4.8%. Thedecline in average revenue per revenue generating horsepower per month related primarily to the 14.3% increase in average horsepower per revenue generatingcompression unit to 791 for 2012 from 692 in 2011, resulting from our focus on the addition of large horsepower compression units to our fleet. The decreasein cost of operations is attributable to a $4.1 million decrease in equipment operating lease expense, as the Caterpillar operating lease schedules were terminatedon December 15, 2011. Partially offsetting the decrease related to the Caterpillar operating lease were certain cost increases, including (1) a $1.1 millionincrease in lubrication oil expenses due to both a 7.1% increase in the average supplier price per gallon and a 12.7% increase in gallons consumed, (2) a $1.0million increase in direct labor expenses and (3) a $0.3 million increase related to vehicle tools and gasoline, all of which were attributable primarily to theincrease in the size of our fleet. 41 Table of Contents Financial Results of Operations Year ended December 31, 2013 compared to the year ended December 31, 2012 The following table summarizes our results of operations for the periods presented: Year ended December 31,Percent20132012Change(in thousands)Revenues:Contract operations$150,360$116,37329.2%Parts and service2,5582,4146.0%Total revenues152,918118,78728.7%Costs and expenses:Cost of operations, exclusive of depreciation andamortization48,09737,79627.3%Selling, general and administrative27,58718,26951.0%Depreciation and amortization52,91741,88026.4%(Gain) loss on sale of assets2842666.8%Impairment of compression equipment203——Total costs and expenses129,08898,21131.4%Operating income23,83020,57615.8%Other income (expense):Interest expense(12,488)(15,905)(21.5)%Other928(67.9)%Total other expense(12,479)(15,877)(21.4)%Income before income tax expense11,3514,699141.6%Income tax expense28019642.9%Net income$11,071$4,503145.9% Contract operations revenue. Contract operations revenue was $150.4 million for the year ended December 31, 2013 compared to $116.4 million in2012, an increase of 29.2%. Average revenue generating horsepower increased from 749,821 for the year ended December 31, 2012 to 902,168 for the yearended December 31, 2013, an increase of 20.3%, primarily due to growth in our core midstream compression assets along with the addition of assets inconnection with the S&R Acquisition. Average revenue per revenue generating horsepower per month increased from $13.39 for the year ended December 31,2012 to $14.15 for the year ended December 31, 2013, an increase of 5.7%, primarily due to higher revenue per horsepower per month from the gas liftcompression units that were acquired in the S&R Acquisition. There were 2,137 revenue generating compression units at December 31, 2013 compared to 978at December 31, 2012, a 118.5% increase, primarily due to the S&R Acquisition and organic growth in our core midstream compression assets. Revenuegenerating horsepower was 1,070,457 at December 31, 2013 compared to 794,324 at December 31, 2012, a 34.8% increase, primarily due to growth in ourcore midstream compression assets along with the S&R Acquisition. Parts and service revenue. Parts and service revenue was $2.6 million for the year ended December 31, 2013 compared to $2.4 million in 2012, or a6.0% increase. Cost of operations, exclusive of depreciation and amortization. Cost of operations was $48.1 million for the year ended December 31, 2013 comparedto $37.8 million for the year ended December 31, 2012, an increase of 27.3%. The increase is primarily attributable to the increase in our fleet size. Certaincost increases consisted of (1) a $2.8 million increase in lubrication oil expenses due to a 21.7% increase in gallons consumed, partially offset by a 3.9%decrease in the average price per gallon paid, (2) a $4.3 million increase in direct labor expenses, (3) a $0.9 42 Table of Contents million increase in training and safety expense, (4) a $0.4 million increase in maintenance parts and (5) a $0.6 million increase related to vehicle tools andgasoline. These factors are primarily attributable to the increase in our fleet size due to organic growth and four months of operations related to the assetsacquired in the S&R Acquisition. In addition, business and property insurance increased by $0.4 million primarily due to certain insurance claims on ourcompression units and the increase in the size of our fleet. The cost of operations was 31.5% of revenue for the year ended December 31, 2013 as compared to31.8% for the year ended December 31, 2012. Selling, general and administrative expense. Selling, general and administrative expense was $27.6 million for the year ended December 31, 2013compared to $18.3 million for the year ended December 31, 2012, an increase of 51.0%. Approximately $3.5 million of the increase in selling, general andadministrative expense is related to a rise in salaries and benefits due to (i) an increase in employee headcount to support operations and sales management and(ii) the addition of certain executive positions to operate as a public company. Additionally, the Partnership expensed $1.3 million of unit-based compensationexpense related to the issuance of phantom units in 2013 under the Partnership’s 2013 Long-Term Incentive Plan. Other significant increases included (1) a$0.6 million due to increased sales support costs, (2) $3.8 million of increased professional fees, including $2.1 million related to the S&R Acquisition and(3) $0.3 million of increased computer hardware and software expenses, all of which were attributable to increased employee headcount and support services.In addition, business and property insurance increased by $0.6 million due to certain insurance claims on our compression units and the increase in the sizeof our fleet and were offset by a $1.0 million decrease in management fees that are no longer owed by the Partnership subsequent to its initial public offering.The selling, general and administrative employee headcount was 86 at December 31, 2013, a 45.8% increase from December 31, 2012. The selling, generaland administrative employee headcount increased to support the continued growth of the business, including the S&R Acquisition. Selling, general andadministrative expense represented 18.0% and 15.4% of revenue for the years ended December 31, 2013 and 2012, respectively. Depreciation and amortization expense. Depreciation and amortization expense was $52.9 million for the year ended December 31, 2013 compared to$41.9 million for the year ended December 31, 2012, an increase of 26.4%. The increase was related to an increase in property, plant and equipment,including the S&R Acquisition, of 39.8% for the year ended December 31, 2013 as compared to December 31, 2012. Interest expense. Interest expense was $12.5 million for the year ended December 31, 2013 compared to $15.9 million for the year ended December 31,2012, a decrease of 21.5%. Included in interest expense is amortization of deferred loan costs of $2.2 million and $1.9 million for the years endedDecember 31, 2013 and 2012, respectively. Interest expense for both periods was related to borrowings under our revolving credit facility. Average borrowingsoutstanding under our revolving credit facility were $370.8 million for the year ended December 31, 2013 compared to $442.1 million for the year endedDecember 31, 2012. Our revolving credit facility had an interest rate of 2.17% and 2.96% at December 31, 2013 and 2012, respectively, and an averageinterest rate of 2.43% and 2.99%, excluding the effects from the interest rate swap instruments discussed below for 2012, for the year then ended, respectively.The composite fixed interest rate for $140 million of notional coverage under three interest rate swap instruments was 2.52% at December 31, 2011 plus theapplicable margin of 2.75%. These interest rate swaps expired during 2012. We did not designate our swap agreements as cash flow hedges. As a result,amounts paid or received from the interest rate swaps were charged or credited to interest expense. For the year ended December 31, 2012, we recorded a fairvalue gain of $2.2 million, with respect to these swaps as a reduction in interest expense. Income tax expense. We incurred approximately $279,972 and $196,040 in franchise tax for the years ended December 31, 2013 and 2012,respectively, as a result of the Texas franchise tax. Year ended December 31, 2012 compared to the year ended December 31, 2011 The following table summarizes our results of operations for the periods presented: SuccessorYear Ended December 31,Percent20122011Change(in thousands)Revenues:Contract operations$116,373$93,89623.9%Parts and service2,4144,824(50.0)%Total revenues118,78798,72020.3% 43 Table of Contents SuccessorYear Ended December 31,Percent20122011ChangeCosts and expenses:Cost of operations, exclusive of depreciation and amortization37,79639,605(4.6)%Selling, general and administrative18,26912,72643.6%Restructuring charges—300Depreciation and amortization41,88032,73827.9%(Gain) loss on sale of assets26617849.4%Total costs and expenses98,21185,54714.8%Operating income20,57613,17356.2%Other income (expense):Interest expense(15,905)(12,970)22.6%Other282133.3%Total other expense(15,877)(12,949)22.6%Income before income tax expense4,6992241,997.8%Income tax expense19615526.5%Net income$4,503$696,426.1% Contract operations revenue. Contract operations revenue was $116.4 million for the year ended December 31, 2012 compared to $93.9 million in2011, an increase of 23.9%. Average revenue generating horsepower increased from 570,900 for the year ended December 31, 2011 to 749,821 for the yearended December 31, 2012, an increase of 31.3%, primarily due to organic growth and increasing customer demand. Average revenue per revenue generatinghorsepower per month declined from $14.07 for the year ended December 31, 2011 to $13.39 for the year ended December 31, 2012, a decrease of 4.8%. Thedecline in average revenue per revenue generating horsepower per month related primarily to the 14.3% increase in the estimated average horsepower per revenuegenerating compression unit, which was 692 and 791 at December 31, 2011 and 2012, respectively, as large horsepower compression units generally generatelower average monthly revenue per revenue generating horsepower. While pricing for these services stabilized in mid-2010 and 2011 and began to improveduring 2012, compression units that were placed under service contracts during 2009 and 2010 were contracted at lower market rates. There were 978 revenuegenerating compression units at December 31, 2012 compared to 888 at December 31, 2011, a 10.1% increase. Revenue generating horsepower was 794,324 atDecember 31, 2012 compared to 649,285 at December 31, 2011, a 22.3% increase. Parts and service revenue. Parts and service revenue was $2.4 million for the year ended December 31, 2012 compared to $4.8 million in 2011, or a50.0% decrease. A portion of retail service revenue, including billings for trucking and crane services, was $1.1 million during 2011, including $1.0 millionrecognized during the fourth quarter of 2011 due to the deployment and redeployment of compression units. These ancillary trucking and crane services, all ofwhich are billed to customers, result in no gross operating margin. Cost of operations, exclusive of depreciation and amortization. Cost of operations was $37.8 million for the year ended December 31, 2012 comparedto $39.6 million for the year ended December 31, 2011, a decrease of 4.6%. The decrease is attributable to a $4.1 million decrease in equipment operating leaseexpense, as the Caterpillar operating lease schedules were terminated on December 15, 2011. Partially offsetting the decrease related to the Caterpillar operatinglease are certain cost increases consisting of (1) a $1.1 million increase in lubrication oil expenses due to both a 7.1% increase in the average price per gallonpaid and a 12.7% increase in gallons consumed, (2) a $1.0 million increase in direct labor expenses and (3) a $0.3 million increase related to vehicle tools andgasoline, all of which were attributable primarily to the increase in the size of our fleet. The cost of operations was 31.8% of revenue for the year endedDecember 31, 2012 as compared to 40.2% for the year ended December 31, 2011. Selling, general and administrative expense. Selling, general and administrative expense was $18.3 million for year ended December 31, 2012compared to $12.7 million for the year ended December 31, 2011, an increase of 43.6%. Selling, general and administrative expense represented 15.4% and12.9% of revenue for the years ended December 31, 2012 and 2011, respectively. Approximately $2.6 million of the increase in selling, general andadministrative expense related to a rise in salaries and benefits due to (i) an increase in employee headcount to 44 Table of Contents support operations and sales management and (ii) certain executive positions to operate as a public company. Additionally, accounting fees increased $0.3million due to increased services as we prepared to operate as a public company. Other significant increases included (1) $0.3 million due to increased officerent, (2) $0.6 million due to increased sales support costs, (3) $0.5 million of increased outside services costs and (4) $0.4 million of increased telephone andoffice supply expenses, all of which were attributable to increased employee headcount and support services. The selling, general and administrative employeeheadcount was 59 at December 31, 2012, a 15.7% increase from December 31, 2011. The selling, general and administrative employee headcount increasedto support the 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 benefitsrelated to the termination of certain administrative employees. These charges are reflected as restructuring charges in our consolidated statement of operationsfor the year ended December 31, 2011. We paid these restructuring charges in 2012. Depreciation and amortization expense. Depreciation and amortization expense was $41.9 million for the year ended December 31, 2012 compared to$32.7 million for the year ended December 31, 2011, an increase of 27.9%. The increase was related to an increase in depreciable property, plant andequipment, including the compression units purchased from Caterpillar for $43.0 million, of 33.6% over these periods. Interest expense. Interest expense was $15.9 million for the year ended December 31, 2012 compared to $13.0 million for the year ended December 31,2011, an increase of 22.6%. Included in interest expense is amortization of deferred loan costs of $1.9 million and $1.5 million for the years endedDecember 31, 2012 and 2011, respectively. Interest expense for both periods was related to borrowings under our revolving credit facility. Average borrowingsoutstanding under our revolving credit facility were $442.1 million for the year ended December 31, 2012 compared to $275.1 million for the year endedDecember 31, 2011. Our revolving credit facility had an interest rate of 2.96% and 3.02% at December 31, 2012 and 2011, respectively, and an averageinterest rate of 2.99% and 3.71%, excluding the effects from the interest rate swap instruments discussed below, for the year then ended, respectively. Thecomposite fixed interest rate for $140 million of notional coverage under three interest rate swap instruments was 2.52% at December 31, 2011 plus theapplicable margin of 2.75%. These interest rate swaps expired during 2012. As of December 31, 2010, we no longer designate our swap agreements as cashflow hedges. As a result, amounts paid or received from the interest rate swaps are charged or credited to interest expense. For the years ended December 31,2012 and 2011, we recorded a fair value gain of $2.2 million and $2.6 million, respectively, with respect to these swaps as a reduction in interest expense. Income tax expense. We incurred approximately $196,000 and $155,000 in franchise tax for the years ended December 31, 2012 and 2011,respectively, as a result of the Texas franchise tax. Liquidity and Capital Resources The following table summarizes our sources and uses of cash for the years ended December 31, 2013, 2012 and 2011, and our cash as of the end of theperiods presented: Year Ended December 31,201320122011(in thousands)Net cash provided by operating activities$68,190$41,974$33,782Net cash used in investing activities(153,946)(178,589)(140,444)Net cash provided by financing activities85,756136,619106,662 Net cash provided by operating activities. Net cash provided by operating activities increased to $68.2 million for the year ended December 31, 2013,from $42.0 million for the year ended December 31, 2012. The increase relates primarily to an increase in net income during the year ended December 31,2013, due to the increase in the size of our operating fleet, and a $4.5 million increase in working capital in 2013 due to increased purchases and timing ofpayments for new compression unit equipment. Net cash provided by operating activities increased to $42.0 million for the year ended December 31, 2012,from $33.8 million in the year ended December 31, 2011. The increase related primarily to a higher income level in 2012, offset by a $6.2 million decrease inworking capital in the year ended December 31, 2012, primarily due to timing of payments for new compression unit equipment. 45 Table of Contents Net cash used in investing activities. Net cash used in investing activities decreased to $153.9 million for the year ended December 31, 2013, from$178.6 million for the year ended December 31, 2012. The decrease related primarily to lower capital expenditures of $159.5 million during the year endedDecember 31, 2013, offset by (1) $0.8 million of higher proceeds from the sale of equipment during the year ended December 31, 2013 and (2) cash receivedas part of a purchase price adjustment related to the S&R Acquisition of $3.4 million during 2013. Net cash used in investing activities increased to $178.6million for the year ended December 31, 2012, from $140.4 million for the year ended December 31, 2011. The increase related primarily to higher capitalexpenditures of $180.0 million, offset by $0.6 million of higher proceeds from the sale of equipment during the year ended December 31, 2012. Net cash provided by financing activities. Net cash provided by financing activities was $85.8 million for the year ended December 31, 2013 ascompared $136.6 million for the year ended December 31, 2012. The decrease was due to lower borrowings under our revolving credit facility for the yearended December 31, 2013 due to the application of the net proceeds from our initial public offering to pay down outstanding borrowings as compared to higherborrowings for the year ended December 31, 2012 related to expansion capital expenditures. Net cash provided by financing activities was $136.6 million forthe year ended December 31, 2012 as compared to $106.7 million for the year ended December 31, 2011. The increase was due to lower borrowings under ourrevolving credit facility for the year ended December 31, 2011 as compared to higher borrowings for the year ended December 31, 2012 related to increasedexpansion capital expenditures. Capital Expenditures The compression business is capital intensive, requiring significant investment to maintain, expand and upgrade existing operations. Our capitalrequirements have consisted primarily of, and we anticipate that our capital requirements will continue to consist primarily of, the following: · maintenance capital expenditures, which are capital expenditures made to replace partially or fully depreciated assets, to maintain the operatingcapacity of our assets and extend their useful lives, or other capital expenditures that are incurred in maintaining our existing business and relatedcash flow; and · expansion capital expenditures, which are capital expenditures made to expand the operating capacity or revenue generating capacity of existing ornew assets, including by acquisition of compression units or through modification of existing compression units to increase their capacity. We expect that our maintenance capital expenditure requirements will continue to increase as the overall size and age of our fleet increases. Our aggregatemaintenance capital expenditures for the years ended December 31, 2013 and 2012 were $14.3 million and $13.3 million, respectively. Given our growth objective, we anticipate that we will continue to make significant expansion capital expenditures. Our expansion capital expenditures forthe years ended December 31, 2013 and 2012 were $323.7 million and $166.7 million, respectively. Of the $323.7 million, $178.5 million (including $120.0million of fixed assets, $7.6 million of intangible assets and $51.0 million of goodwill) related to the S&R Acquisition and was financed through the issuanceof 7,425,261 common units to S&R’s owners. In addition to organic growth, we may also consider a variety of assets or businesses for potential acquisition. We expect to fund any future capitalexpenditures or acquisitions primarily with capital from external financing sources, such as borrowings under our revolving credit facility and issuances ofdebt and equity securities, including our issuance of additional partnership units and future debt offerings given market conditions. Description of Revolving Credit Facility We amended our revolving credit agreement in December 2010 to increase the overall commitments under the facility to $400 million and extend the termuntil October 5, 2015. On November 16, 2011, we amended the revolving credit agreement to increase the overall commitments under the facility from $400million 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 rangeof 200 to 275 basis points above LIBOR, depending on our leverage ratio. We further amended our revolving credit agreement on June 1, 2012 to increase theoverall commitments under the facility from $500 million to $600 million and to provide an option to increase the overall commitments by an additional $50million upon satisfaction of certain conditions. 46 Table of Contents In addition, on June 1, 2012, we entered into the Fourth Amended and Restated Credit Agreement in order to provide a covenant structure that was moreappropriate for a public company than was the prior credit agreement, including a reduction of the applicable margin for LIBOR loans to a range of 175 to250 basis points above LIBOR, depending on the our leverage ratio. This amended and restated credit agreement became effective on January 18, 2013, theclosing date of our initial public offering, was secured by a first priority lien against our assets and had a schedule maturity of October 5, 2015. OnDecember 10, 2012, we amended the Fourth Amended and Restated Credit Agreement to extend the periods during which the maximum funded debt toEBITDA ratio thresholds will apply. We paid various loan fees and incurred costs in respect of the third amendment to the credit agreement and the FourthAmended and Restated Credit Agreement in the amount of $1.8 million in 2012. On December 13, 2013, we entered into the Fifth Amended and Restated Credit Agreement whereby the aggregate commitment under the facility increasedfrom $600 million to $850 million (subject to availability under a borrowing base and a further potential increase of $100 million) and reduced the applicablemargin for LIBOR loans to a range of 150 to 225 basis points above LIBOR, depending on our leverage ratio. The revolving credit facility is secured by a firstpriority lien against our assets and matures on December 13, 2018, at which point all amounts outstanding will become due. The Fifth Amended and Restated Credit Agreement permits us to make distributions of available cash to unitholders so long as (a) no default under thefacility has occurred, is continuing or would result from the distribution, (b) immediately prior to and after giving effect to such distribution, we are incompliance with the facility’s financial covenants and (c) immediately after giving effect to such distribution, we have availability under the revolving creditfacility of at least $20 million. In addition, the amended and restated credit agreement contains various covenants that may limit, among other things, ourability to (subject to certain exceptions): · grant liens; · make certain loans or investments; · incur additional indebtedness or guarantee other indebtedness; · enter into transactions with affiliates; · merge or consolidate; · sell our assets; or · make certain acquisitions. The Fifth Amended and Restated Credit Agreement also contains various financial covenants, including covenants requiring us to maintain: · a minimum EBITDA to interest coverage ratio of 2.5 to 1.0; and · a maximum funded debt to EBITDA ratio, determined as of the last day of each fiscal quarter, for the annualized trailing three months of (a) 5.50 to1.0, with respect to any fiscal quarter ending on or after December 13, 2013, the closing date of the amended credit facility, through June 30, 2015 or(b) 5.00 to 1.0, with respect to the fiscal quarter ending September 30, 2015 and each fiscal quarter thereafter, in each case subject to a provision forincreases to such thresholds by 0.5 in connection with certain future acquisitions for the six consecutive month period following the period in whichany such acquisition occurs. 47 Table of Contents If a default exists under the revolving credit facility, the lenders will be able to accelerate the maturity on the amount then outstanding and exercise otherrights and remedies. As of December 31, 2013, we were in compliance with all of the covenants under our current credit agreement. Distribution Reinvestment Plan We have filed a registration statement with the SEC to register the issuance of up to 4,150,000 of our common units in connection with a DRIP, whichinitially became effective on January 30, 2013. Our DRIP provides our common unitholders a means by which they can increase the number of common unitsthey own by reinvesting the quarterly cash distributions, which they would otherwise receive in cash, into the purchase of additional common units. As ofFebruary 18, 2014, 1,552,749 common units had been issued under this registration statement. Total Contractual Cash Obligations The following table summarizes our total contractual cash obligations as of December 31, 2013: Payments Due by PeriodContractual ObligationsTotal1 year2 - 3 years4 - 5 yearsMore than5 years(in thousands)Long-term debt(1) $420,933$—$—$420,933$—Interest on long-term debt obligations(2) 45,2209,13418,26817,818—Equipment/capital purchases(3) 158,318158,318———Operating lease obligations(4) 4,9221,0831,8111,417611Total contractual cash obligations$629,393$168,535$20,079$440,168$611 (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, 2013 of 2.17%. (3) Represents commitments for new compression units that are being fabricated. (4) Represents commitments for future minimum lease payments on noncancelable leases. Effects of Inflation. Our revenues and results of operations have not been materially impacted by inflation and changing prices in the past three fiscalyears. 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 wereprepared in conformity with U.S. GAAP. As such, we are required to make certain estimates, judgments and assumptions that affect the reported amounts ofassets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. We base ourestimates on historical experience, available information and various other assumptions we believe to be reasonable under the circumstances. On an ongoingbasis, we evaluate our estimates; however, actual results may differ from these estimates under different assumptions or conditions. The accounting policiesthat we believe require management’s most difficult, subjective or complex judgments and are the most critical to its reporting of results of operations andfinancial position are as follows: Depreciation 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 anacceleration in depreciation 48 Table of Contents expense. Major overhauls and improvements that extend the life of an asset are capitalized. As of December 31, 2013, we had 2,390 compression units thatwere subject to depreciation. Given the large number of compression units being depreciated, the impact of a particular unit incurring an actual useful life thatis less than the estimated useful life would not have a material impact on our results of operations. Business Combinations and Goodwill Goodwill acquired in connection with business combinations represents the excess of consideration over the fair value of net assets acquired. Certainassumptions and estimates are employed in determining the fair value of assets acquired and liabilities assumed, as well as in determining the allocation ofgoodwill to the appropriate reporting unit. Goodwill is not amortized, but is reviewed for impairment annually based on the carrying values as of October 1, ormore frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered. We perform a qualitative assessment to determine whether it is more likely than not that the fair value of the reporting unit is impaired. Management usesall available information to make these determinations, including evaluating the macroeconomic environment, industry specific conditions, cost factors,overall financial performance and unit price, at the assessment date of October 1. If for any reason the fair value of our goodwill declines below the carryingvalue in the future, we may incur charges for the impairment. There was no impairment recorded for goodwill for the years ended December 31, 2013, 2012and 2011. Long-Lived Assets Long-lived assets, which include property and equipment, and intangible assets comprise a significant amount of our total assets. Long-lived assets to beheld and used by us are reviewed to determine whether any events or changes in circumstances indicate the carrying amount of the asset may not berecoverable. 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 economicbenefit of the assets, any historical or future profitability measurements and other external market conditions or factors that may be present. If suchimpairment indicators are present or other factors exist that indicate the carrying amount of the asset may not be recoverable, we determine whether animpairment has occurred through the use of an undiscounted cash flows analysis. If an impairment has occurred, we recognize a loss for the differencebetween 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 ofquoted market prices, is based on an estimate of discounted cash flows. In 2013, we recorded $203,149 related to the impairment of a certain group of ourcompression equipment. There was no impairment recorded for the years ended December 31, 2012 and 2011. Allowances and Reserves We maintain an allowance for bad debts based on specific customer collection issues and historical experience. On an ongoing basis, we conduct anevaluation of the financial strength of our customers based on payment history and specific identification and make adjustments to the allowance as necessary.The allowance for doubtful accounts was $246,410, $259,638 and $260,598 at December 31, 2013, 2012 and 2011, respectively. Revenue Recognition Revenue is recognized by us using the following criteria: (i) persuasive evidence of an arrangement, (ii) delivery has occurred or services have beenrendered, (iii) the customer’s price is fixed or determinable and (iv) collectability is reasonably assured. Revenue from compression services is recognized as earned under our fixed fee contracts. Compression services are billed monthly in advance of theservice period, except for our gas lift compression customers (which are billed at the beginning of the service month), and are recognized as deferred revenue onthe balance sheet until earned. 49 Table of Contents Recent Accounting Pronouncements We qualify as an emerging growth company under Section 109 of the Jumpstart Our Business Startups, (“JOBS”) Act. An emerging growth companycan take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accountingstandards. In other words, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise applyto private companies. However, we have chosen to “opt out” of such extended transition period, and as a result, are compliant with new or revised accountingstandards on the relevant dates on which adoption of such standards is required for non-emerging growth companies. Section 108 of the JOBS Act providesthat our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable. ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk Commodity Price Risk Market risk is the risk of loss arising from adverse changes in market rates and prices. We do not take title to any natural gas in connection with ourservices and, accordingly, have no direct exposure to fluctuating commodity prices. However, the demand for our compression services depends upon thecontinued demand for, and production of, natural gas and crude oil. Lower natural gas prices or crude oil prices over the long term could result in a decline inthe production of natural gas or crude oil, which could result in reduced demand for our compression services. Please read Part I, Item 1A “Risk Factors —Risks Related to Our Business.” We do not intend to hedge our indirect exposure to fluctuating commodity prices. Interest Rate Risk We are exposed to market risk due to variable interest rates under our financing arrangements. As of December 31, 2013 we had approximately $420.9 million of variable-rate outstanding indebtedness at a weighted-average interest rate of 2.4%. A 1%increase in the effective interest rate on our variable-rate outstanding debt at December 31, 2013 would result in an annual increase in our interest expense ofapproximately $4.2 million. For further information regarding our exposure to interest rate fluctuations on our debt obligations, see Note 5 to the Financial Statements. We may, in thefuture, hedge all or a portion of our variable rate debt. Credit Risk Our credit exposure generally relates to receivables for services provided. If any significant customer of ours should have credit or financial problemsresulting in a delay or failure to repay the service fees owed to us, this could have a material adverse effect on our business, financial condition, results ofoperations or cash flows. ITEM 8. Financial Statements and Supplementary Data The financial statements and supplementary information specified by this Item are presented in Part IV, Item 15 of this report. ITEM 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure None. ITEM 9A. Controls and Procedures Disclosure Controls and Procedures As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, includingour principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls 50 Table of Contents and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosurecontrols and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under theExchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate,and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Commission. Based upon the evaluation,our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31,2013 at the reasonable assurance level. Management’s Annual Report on Internal Control Over Financial Reporting Our management is responsible for establishing and maintaining adequate internal control over financial reporting for us. Our internal control system wasdesigned to provide reasonable assurance regarding the preparation and fair presentation of our published financial statements. There are inherent limitations to the effectiveness of any control system, however well designed, including the possibility of human error and the possiblecircumvention or overriding of controls. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits ofcontrols must be considered relative to their costs. Management must make judgments with respect to the relative cost and expected benefits of any specificcontrol measure. The design of a control system also is based in part upon assumptions and judgments made by management about the likelihood of futureevents, and there can be no assurance that a control will be effective under all potential future conditions. As a result, even an effective system of internalcontrol over financial reporting can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processesunder which they were prepared. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2013. In making this assessment,management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — IntegratedFramework. Based on this assessment, our management believes that, as of December 31, 2013, our internal control over financial reporting was effective.This annual report does not include an attestation report of the company’s registered public accounting firm due to a transition period established by rules ofthe Securities and Exchange Commission for emerging growth companies. Changes in Internal Control over Financial Reporting There were no changes in our internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the last fiscalquarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. ITEM 9B. Other Information None. PART III ITEM 10. Directors, Executive Officers and Corporate Governance Board of Directors Our general partner, USA Compression GP, LLC, manages our operations and activities. Our general partner is not elected by our unitholders and is notsubject to re-election on a regular basis in the future. Our general partner has a board of directors that manages our business. The board of directors of our general partner is comprised of eight members, all of whom have been designated by USA Compression Holdings and threeof whom are independent as defined under the independence standards established by the New York Stock Exchange. The NYSE does not require a listedlimited partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committeeor a nominating committee. 51 Table of Contents Independent Directors. The board of directors of our general partner has determined that Robert F. End, John D. Chandler and Forrest E. Wylie areindependent directors under the standards established by the NYSE and the Exchange Act. The board of directors considered all relevant facts andcircumstances and applied the independent guidelines of the NYSE and the Exchange Act in determining that none of these directors has any materialrelationship with us, our management, our general partner or its affiliates or our subsidiaries. Audit Committee. The board of directors has appointed an audit committee comprised solely of directors who meet the independence and experiencestandards established by the NYSE and the Exchange Act. The audit committee consists of Robert F. End, John D. Chandler and Forrest E. Wylie.Mr. Chandler serves as chairman of the audit committee. The board of directors has determined that Mr. Chandler is an “audit committee financial expert” asdefined in Item 407(d)(5)(ii) of SEC Regulation S-K, and that each of Messrs. End, Chandler and Wylie is “independent” within the meaning of the applicableNYSE and Exchange Act rules regulating audit committee independence. The audit committee assists the board of directors in its oversight of the integrity ofour financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The audit committee has the soleauthority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, andpre-approve any non-audit services to be rendered by our independent registered public accounting firm. The audit committee is also responsible forconfirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm will begiven unrestricted access to the audit committee. A copy of the charter of the audit committee is available under the Investor Relations tab on our website atwww.usacpartners.com. We also will provide a copy of the charter of the audit committee to any of our unitholders without charge upon written request toInvestor Relations, 100 Congress Avenue, Suite 450, Austin, TX 78701. Compensation Committee. The NYSE does not require a listed limited partnership like us to have a compensation committee. However, our board hasestablished a compensation committee to, among other things, oversee the compensation plans described below in Item 11 (“Executive Compensation”). Thecompensation committee establishes and reviews general policies related to our compensation and benefits. The compensation committee has the responsibilityto determine and make recommendations to the board with respect to, the compensation and benefits of our board and executive officers. A copy of the charterof the compensation committee is available under the Investor Relations tab on our website at www.usacpartners.com. We also will provide a copy of thecharter of the compensation committee to any of our unitholders without charge upon written request to Investor Relations, 100 Congress Avenue, Suite 450,Austin, TX 78701. Conflicts Committee. As set forth in the GP Agreement, USA Compression GP, LLC may, from time to time, have a conflicts committee to which theboard of directors will appoint independent directors and which may be asked to review specific matters that the board believes may involve conflicts ofinterest between us, our limited partners and USA Compression Holdings. The conflicts committee will determine the resolution of the conflict of interest inany 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 oremployees of its affiliates, including USA Compression Holdings, and must meet the independence and experience standards established by the NYSE andthe Exchange Act to serve on an audit committee of a board of directors, and certain other requirements. Any matters approved by the conflicts committee ingood 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 itmay owe us or our unitholders. Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Exchange Act requires the board of directors and executive officers of our general partner, and persons who own more than 10 percentof a registered class of our equity securities, to file with the SEC and any exchange or other system on which such securities are traded or quoted initial reportsof ownership and reports of changes in ownership of our common units and other equity securities. Officers, directors and greater than 10 percent unitholdersare required by the SEC’s regulations to furnish to us and any exchange or other system on which such securities are traded or quoted with copies of allSection 16(a) forms they filed with the SEC. To our knowledge, based solely on a review of the copies of such reports furnished to us, we believe that allreporting obligations of the officers and directors of our general partner and greater than 10 percent unitholders under Section 16(a) were satisfied during theyear ended December 31, 2013, except for the Form 3s filed by Mr. Derryberry, Mr. End and Mr. Moody, respectively, on January 15, 2013 that wereoriginally due on January 14, 2013, in connection with the effectiveness of our registration statement on Form S-1 on January 14, 2013 relating to our initialpublic offering. 52 Table of Contents Corporate Governance Guidelines and Code of Ethics The board of directors has adopted Corporate Governance Guidelines that outline important policies and practices regarding our governance and provide aframework for the function of the board of directors and its committees. The board of directors has also adopted a Code of Business Conduct and Ethics (the“Code”) that applies to USA Compression GP LLC and its subsidiaries and affiliates, including us, and to all of its and their directors, employees andofficers, including its principal executive officer, principal financial officer and principal accounting officer. Copies of the Corporate Governance Guidelinesand the Code are available under the Investor Relations tab on our website at www.usacpartners.com. We also will provide copies of the Corporate GovernanceGuidelines and the Code to any of our unitholders without charge upon written request to Investor Relations, 100 Congress Avenue, Suite 450, Austin, TX78701. Reimbursement of Expenses of Our General Partner Our general partner will not receive any management fee or other compensation for its management of us. Our general partner and its affiliates will bereimbursed for all expenses incurred on our behalf, including the compensation of employees of USA Compression GP, LLC or its affiliates that performservices on our behalf. These expenses include all expenses necessary or appropriate to the conduct of our business and that are allocable to us. Ourpartnership 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 thatmay be paid or reimbursed to our general partner or its affiliates for compensation or expenses incurred on our behalf. Directors and Executive Officers The following table shows information as of February 18, 2014 regarding the current directors and executive officers of USA Compression GP, LLC. NameAgePosition with USA Compression GP, LLCEric D. Long55President and Chief Executive Officer and DirectorJoseph C. Tusa, Jr.55Vice President, Chief Financial Officer and TreasurerJ. Gregory Holloway56Vice President, General Counsel and SecretaryDavid A. Smith51Vice President and President, Northeast RegionWilliam G. Manias51Vice President and Chief Operating OfficerMatthew C. Liuzzi39Vice President—Strategic DevelopmentJohn D. Chandler44DirectorJim H. Derryberry69DirectorRobert F. End58DirectorWilliam H. Shea, Jr.58DirectorAndrew W. Ward47DirectorOlivia C. Wassenaar34DirectorForrest E. Wylie50Director The directors of our general partner hold office until the earlier of their death, resignation, removal or disqualification or until their successors have beenelected and qualified. Officers serve at the discretion of the board of directors. There are no family relationships among any of the directors or executive officersof 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 BassEnterprises Production Co. and Texas Oil & Gas. Mr. Long then served in a variety of senior officer level operating positions with affiliates of HanoverEnergy, Inc., a company primarily engaged in the business of gathering, compressing and transporting natural gas. In 1993, Mr. Long co-founded GlobalCompression Services, Inc., a compression services company. Mr. Long was formerly on the board of directors of the Wiser Oil Company, an NYSE listedcompany from May 2001 until it was sold to Forest Oil Corporation in May 2004. Mr. Long received his bachelor’s degree, with honors, in PetroleumEngineering from Texas A&M University. He is a registered Professional Engineer in the state of Texas. 53 Table of Contents As a result of his professional background, Mr. Long brings to us executive level strategic, operational and financial skills. These skills, combined withhis 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 avaluable 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 withArthur Andersen in Houston, Texas in its oil and gas exploration and production division. He then served as Chief Financial Officer of DSMCopolymer, Inc., a producer and global supplier of synthetic rubber. From 1997 to 2001, Mr. Tusa served as Senior Vice President of Business Operationsfor Metamor Worldwide, Inc., an IT services company that was listed on the NASDAQ exchange. From 2001 to December 2007, Mr. Tusa served as theChief Financial Officer of Comsys IT Partners, Inc., an information technology staffing company and an affiliate of Metamor. Mr. Tusa received his B.B.A.from Texas State University and his M.B.A. 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 throughJune 2011, Mr. Holloway was a partner at Thompson & Knight LLP in its Austin office. His areas of practice at the firm included corporate, securities andmerger 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. David A. Smith has served as our President, Northeast Region since joining us in November 1998 and was appointed corporate Vice President inJune 2011. Mr. Smith has approximately 20 years of experience in the natural gas compression industry, primarily in operations and sales. From 1985 to1989, Mr. Smith was a sales manager for McKenzie Corporation, a compression fabrication company. From 1989 to 1996, Mr. Smith held positions ofGeneral Manager and Regional Manager of Northeast Division with Compressor Systems Inc., a fabricator and supplier of compression services. Mr. Smithwas the Regional Manager in the northeast for Global Compression Services, Inc., a compression services company, and served in that capacity from 1996 to1998. Mr. Smith received an associates degree in Automotive and Diesel Technology from Rosedale Technical Institute. William G. Manias has served as our Vice President and Chief Operating Officer since July 2013. He served as a director of our general partner fromFebruary 2013 to July 2013. From October 2009 until January 2013, Mr. Manias served as Senior Vice President and Chief Financial Officer of CrestwoodMidstream Partners LP and its affiliates, where his general responsibilities included managing the partnership’s financial and treasury activities. Beforejoining Crestwood in January 2009, Mr. Manias was the Chief Financial Officer of TEPPCO Partners, L.P. starting in January 2006. From September 2004until January 2006, he served as Vice President of Business Development and Strategic Planning at Enterprise Product Partners L.P. He previously served asVice President and Chief Financial Officer of GulfTerra Energy Partners, L.P. from February 2004 to September 2004 at which time GulfTerra EnergyPartners, L.P. was merged with Enterprise Product Partners L.P. Prior to GulfTerra Energy Partners, L.P., Mr. Manias held several executive managementpositions with El Paso Corporation. Prior to El Paso, he worked as an energy investment banker for J.P. Morgan Securities Inc. and its predecessor companiesfrom May 1992 to August 2001. Mr. Manias earned a B.S.E. in civil engineering from Princeton University in 1984, a M.S. in petroleum engineering fromLouisiana State University in 1986 and an M.B.A. from Rice University in 1992. Matthew C. Liuzzi has served as our Vice President — Strategic Development since joining us in April 2013. Mr. Liuzzi joined us after nine years atBarclays Capital (formerly Lehman Brothers), where he was most recently a Director in the Global Natural Resources Group in Houston. At Barclays,Mr. Liuzzi worked primarily with midstream clients on a variety of investment banking assignments, including initial public offerings, public and privatedebt and equity offerings, as well as strategic advisory assignments. He holds a B.A. and an M.B.A., both from the University of Virginia. 54 Table of Contents John D. Chandler has served as a director of USA Compression GP, LLC since October 2013. Mr. Chandler also currently serves as Senior VicePresident and Chief Financial Officer of Magellan GP, LLC, the general partner of Magellan Midstream Partners, LP. He recently announced his intention toresign from these positions effective March 31, 2014. From 2003 until 2009, he served in the same capacities for the general partner of Magellan MidstreamHoldings, L.P. From 1999 to 2002, Mr. Chandler was Director of Financial Planning and Analysis and Director of Strategic Development for a subsidiary ofThe Williams Companies, Inc. From 1992 to 1999, Mr. Chandler held various accounting and finance positions with MAPCO Inc. Mr. Chandler receivedhis B.S. and B.A. in accounting and finance from the University of Tulsa. Mr. Chandler’s experience in the energy industry, particularly through his position as the Chief Financial Officer of the general partner of MagellanMidstream Partners, LP, will provide additional industry perspective to our Board of Directors. He will bring us helpful perspective regarding companygrowth, having been an officer at Magellan since its spin-off from the Williams Companies in 2003. In addition, his understanding of the midstream masterlimited partnership sector in particular and of the unique issues related to operating publicly traded limited partnerships should help him make valuablecontributions to the Partnership. Jim H. Derryberry has served as a director of USA Compression GP, LLC since January 2013. From February 2005 to October 2006, Mr. Derryberryserved on the board of directors of Magellan GP, LLC, the general partner of Magellan Midstream Partners, L.P. Mr. Derryberry served as chief operatingofficer and chief financial officer of Riverstone Holdings, LLC until 2006 and currently serves as a special advisor. Prior to joining Riverstone,Mr. Derryberry was a managing director of J.P. Morgan, where he served as head of the Natural Resources and Power Group. Before joining J.P. Morgan,Mr. Derryberry was in the Goldman Sachs Global Energy and Power Group where he was responsible for mergers and acquisitions, capital markets financingand the management of relationships with major energy companies. He has also served as an advisor to the Russian government for energy privatization.Mr. Derryberry has served as a member of the Board of Overseers for the Hoover Institution at Stanford University and is a member of the EngineeringAdvisory Board at the University of Texas at Austin. He received his B.S. and M.S. degrees in engineering from the University of Texas at Austin and earnedan M.B.A. from Stanford University. Mr. Derryberry brings significant knowledge and expertise to our board from his service on other boards and his years of experience in our industryincluding his useful insight into investments and proven leadership skills as a managing director of Riverstone Holdings, LLC. As a result of his experienceand skills, we believe Mr. Derryberry is a valuable member of our board. Robert F. End has served as a director of USA Compression GP, LLC since November 2012. Mr. End served as a director of Hertz GlobalHoldings, Inc. from December 2005 until August 2011. Mr. End was a Managing Director of Transportation Resource Partners, or TRP, a private equity firmfrom 2009 through 2011. Prior to joining TRP in 2009, Mr. End had been a Managing Director of Merrill Lynch Global Private Equity Division, or MLGPE,the private equity arm of Merrill Lynch & Co., Inc., where he served as Co-Head of the North American Region, and a Managing Director of Merrill LynchGlobal Private Equity, Inc., the Manager of ML Global Private Equity Fund, L.P., a proprietary private equity fund which he joined in 2004. Previously,Mr. End was a founding Partner and Director of Stonington Partners Inc., a private equity firm established in 1994. Prior to leaving Merrill Lynch in 1994,Mr. End was a Managing Director of Merrill Lynch Capital Partners, Merrill Lynch’s private equity group. Mr. End joined Merrill Lynch in 1986 andworked in the Investment Banking Division before joining the private equity group in 1989. Mr. End received his A.B. from Dartmouth College and hisM.B.A. from the Tuck School of Business Administration at Dartmouth College. Mr. End brings significant knowledge and expertise to our board from his service on other boards and his years of experience with private equity groups,including his useful insight into investments and business development and proven leadership skills as Managing Director of MLGPE. As a result of thisexperience and resulting skills set, we believe Mr. End is a valuable member of our board. 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 OperatingOfficer of Buckeye GP LLC and its predecessor entities, or Buckeye, from July 1998 to September 2000, as President and Chief Executive Officer ofBuckeye 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 ofMainLine Management LLC, the general partner of Buckeye GP Holdings, L.P., and as President and Chief Executive Officer of MainLine Management LLCfrom 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 anddirector of the general partner of Penn Virginia GP Holdings, L.P. from March 2010 to March 2011. Mr. Shea has served as a 55 Table of Contents director and the Chief Executive Officer of the general partner of PVR Partners, L.P., or PVR, since March 2010. Mr. Shea has also served as a director ofKayne Anderson Energy Total Return Fund, Inc., and Kayne Anderson MLP Investment Company since March 2008 and Niska Gas Storage Partners LLCsince 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 PVR 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 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 skill 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 2002until 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 inthe midstream sector of the energy industry. Mr. Ward served on the boards of directors of Buckeye and MainLine Management LLC from May 2004 toJune 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 A.B. 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. Inaddition, Mr. Ward’s work with Gibson Energy, Inc., Buckeye and Niska Gas Storage Partners LLC has given him both an understanding of the midstreamsector 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 debtfinancings 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, andsolar sectors of the energy industry. Ms. Wassenaar has also served on the board of directors of Northern Blizzard Resources Inc. since June 2011 and on theboard of directors of Talos Energy LLC. Ms. Wassenaar received her A.B., magna cum laude, from Harvard College and earned an M.B.A. from the WhartonSchool 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 bankermake her a valuable member of our board. Forrest E. Wylie has served as a director of USA Compression GP, LLC since March 2013. Mr. Wylie has also served as the Non-Executive Chairmanof the board of directors of Buckeye GP LLC, the general partner of Buckeye Partners, L.P., since February 10, 2012. He served as Chairman of the Board,CEO and a director of Buckeye GP LLC from June 25, 2007 to February 9, 2012. Mr. Wylie also served as a director of the general partner of Buckeye GPHoldings L.P., the former parent company of Buckeye GP (“BGH”) from June 25, 2007 until the merger of BGH with Buckeye Partners, L.P. onNovember 19, 2010. Prior to his appointment, he served as Vice Chairman of Pacific Energy Management LLC, an entity affiliated with Pacific EnergyPartners, L.P., a refined product and crude oil pipeline and terminal partnership, from March 2005 until Pacific Energy Partners, L.P. merged with Plains AllAmerican, L.P. in November 2006. Mr. Wylie was President and CFO of NuCoastal Corporation, a midstream energy company, from May 2002 untilFebruary 2005. From November 2006 to June 25, 2007, Mr. Wylie was a private investor. Mr. Wylie served on the board of directors and the audit committeeof Coastal Energy Company, a publicly traded entity, until April 2011. Mr. Wylie also served on board of directors and compensation and nominating andcorporate governance committees of Eagle Bulk Shipping Inc. until May 2010. Mr. Wylie’s experience in the energy industry, through his prior position as the CEO of a publicly traded partnership and the past employment describedabove, has given him both an understanding of the midstream sector of the energy business and of the unique issues related to operating publicly tradedlimited partnerships that make him a valuable member of our board. 56 Table of Contents ITEM 11. Executive Compensation As is commonly the case for many publicly traded limited partnerships, we have no employees. Under the terms of our partnership agreement, we areultimately managed by our general partner. All of our employees, including our executive officers are employees of USAC Management, a wholly ownedsubsidiary of our general partner. We sometimes refer herein to USAC Management’s management and executive officers as “our management” and “ourexecutive officers,” respectively. Executive Compensation We are an “emerging growth company” as defined under the Jumpstart Our Business Startups (JOBS) Act. As such, we are permitted to meet thedisclosure requirements of Item 402 of Regulation S-K by providing the reduced disclosure required of a “smaller reporting company.” Executive Summary This Executive Compensation disclosure provides an overview 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. For the year endedDecember 31, 2013, our named executive officers, or our NEOs, were: · Eric D. Long, President and Chief Executive Officer; · Joseph C. Tusa, Jr., Vice President, Chief Financial Officer and Treasurer; and · David A. Smith, Vice President and President, Northeast Region. Mr. Kevin Bourbonnais resigned effective August 2, 2013. He is included as an NEO below due to the fact that he would have been one of our most highlycompensated employees had he been employed on December 31, 2013, but he was no longer considered an executive officer at the end of the 2013 fiscal year. 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, 2012 and 2013. Name and Principal PositionYearSalary ($)Bonus ($) (1)Unit Awards ($)(2)All Other Compensation ($)Total ($)Eric D. Long2013400,000450,0001,200,00036,966(3)2,086,966President and Chief ExecutiveOfficer2012400,000400,000—37,578(4)837,578Joseph C. Tusa, Jr.2013275,000225,000700,00010,650(5)1,210,650Vice President, Chief FinancialOfficer and Treasurer2012275,000175,000—9,313(6)459,313David A. Smith2013250,000450,000200,00024,730(7)924,730Vice President and President,Northeast Region2012250,000400,000—26,165(8)676,165Kevin M. Bourbonnais2013163,942(9)171,725(10)700,000(11)3,0831,038,750Former Vice President and ChiefOperating Officer2012275,000175,000—4,888454,888 (1) Represents the awards earned under annual incentive bonus programs and commission program for Mr. Smith for the years ended December 31, 2012and 2013. For a discussion of the determination of the 2013 bonus amounts, see “—Annual Performance Based Compensation for 2013” below. (2) On March 11, 2013, each of our NEOs received an award of phantom units under our 2013 Long-Term Incentive Plan (the “LTIP”). Each phantom unitis the economic equivalent of one common unit. The phantom units shall vest in three equal annual installments, with the first installment vesting onMarch 11, 2014. In the event of cessation of the NEO’s service for any reason, all phantom units that have not vested prior to or in connection with suchcessation of service shall automatically be forfeited. The phantom unit values reflect the grant date fair value of the awards calculated in accordance withFASB ASC Topic 718. For a detailed discussion of the assumptions utilized in coming to these values, please see Note 7 to our consolidated financialstatements. 57 Table of Contents (3) Includes $18,000 of automobile allowance, $8,316 of club membership dues, $7,650 of employer contributions under the 401(k) plan and $3,000 ofparking. (4) Includes $18,000 of automobile allowance, $8,078 of club membership dues, $8,500 of employer contributions under the 401(k) plan and $3,000 ofparking. (5) Includes $7,650 of employer contributions under the 401(k) plan and $3,000 of parking. (6) Includes $6,313 of employer contributions under the 401(k) plan and $3,000 of parking. (7) Includes $9,960 of automobile allowance, $7,120 of club membership dues and $7,650 of employer contributions under the 401(k) plan. (8) Includes $9,960 of automobile allowance, $6,120 of club membership dues and $10,085 of employer contributions under the 401(k) plan. (9) On July 3, 2013, Mr. Bourbonnais announced his resignation as Vice President and Chief Operating Officer. Mr. Bourbonnais’ resignation becameeffective on August 2, 2013. (10) Includes fees and other payments pursuant to the Resignation and Consulting Agreement Mr. Boubonnais entered into in connection with his resignation.The Resignation and Consulting Agreement is described more fully below. (11) In connection with his resignation and pursuant to the terms of his grant agreement, Mr. Bourbonnais forfeited all rights to his grant under the LTIP andthis value was not actually paid to him. Narrative Disclosure to Summary Compensation Table Elements of the Compensation Program Compensation for our NEOs consists primarily of the elements, and their corresponding objectives, identified in the following table. Compensation ElementPrimary Objective Base salaryTo recognize performance of job responsibilities and to attract and retainindividuals with superior talent. Annual performance-based compensationTo promote near-term performance objectives and reward individualcontributions to the achievement of those objectives. Discretionary long-term equity incentive awardsTo emphasize long-term performance objectives, encourage the maximizationof unitholder value and retain key executives by providing an opportunity toparticipate in the ownership of our partnership. Severance benefitsTo encourage the continued attention and dedication of key individuals andto focus the attention of such key individuals when considering strategicalternatives. Retirement savings (401(k)) planTo provide an opportunity for tax-efficient savings. Other elements of compensation and perquisitesTo attract and retain talented executives in a cost-efficient manner byproviding benefits with high perceived values at relatively low cost. Base Compensation For 2013 Base salaries for our NEOs have generally been set at a level deemed necessary to attract and retain individuals with superior talent. Base salary increasesare determined based upon the job responsibilities, demonstrated proficiency and performance of the executive officers and market conditions, each asassessed by the board of managers of USA Compression Holdings. No formulaic base salary increases are provided to the NEOs. Additionally, no changes tobase salaries for our NEOs were made for the fiscal year ended December 31, 2013. 58 Table of Contents The current 2014 base salaries for our NEOs, including for our Chief Executive Officer, are set forth in the following table: Name and Principal PositionCurrent Base Salary ($)Eric D. Long President and Chief Executive Officer500,000Joseph C. Tusa, Jr. Vice President, Chief Financial Officer and Treasurer300,000David A. Smith Vice President and President, Northeast Region250,000 Annual Performance-Based Compensation For 2013 Each of our NEOs participates 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 their employment agreements. For 2013, the target bonus amounts for each of our NEOs were asfollows: Mr. Long: $300,000; Mr. Tusa: $110,000; Mr. Smith: $120,000 and Mr. Bourbonnais: $137,500. In making individual annual bonus decisions, ourgeneral partner’s board of directors, following the recommendations of our compensation committee, does not rely solely on pre-determined performance goalsor targets. Instead, determinations regarding annual bonus compensation awards are based on a subjective assessment of all reasonably available information,including the applicable executive’s performance, business impact, contributions and leadership, and any pre-determined performance goals are used asguidelines in making these end of year decisions. For 2013, our general partner’s board of directors determined to provide each NEO with a 2013 annual bonus award above the NEO’s target bonus,generally on what it viewed as strong leadership and overall financial performance. In addition, the board of directors sought to reward our NEOs for ouroperational results and significantly increased sales activity during the year. As a result of these considerations, Mr. Long received an annual incentive awardequal to 150% of his target amount in recognition of his strong leadership in sales and operations, Mr. Smith received 208% of his target amount to recognizehis strong sales performance and Mr. Tusa received an award equal to 205% of his target amount due to his leadership in building a strengthened financialand accounting team in 2013 and expanding and improving our credit facility. Mr. Bourbonnais was no longer an officer at the end of the year, thus he did notreceive a bonus award from this program. Awards with respect to the 2013 year were: Eric D. Long$450,000Joseph C. Tusa, Jr.$225,000David A. Smith$250,000 Mr. Smith also receives commissions in an amount up to $200,000 annually based on a percentage of qualifying sales. Based on sales performance in2013, as in prior recent years, Mr. Smith earned the maximum potential amount of commissions available under this arrangement. 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 significantcomponent of executive compensation but which we recognize are an important factor in attracting and retaining talented executives. Executive officers areeligible under the same plans as all other employees with respect to our medical, dental, vision, disability and life insurance plans and a defined contributionplan 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 officerswith an annual automobile allowance. We provide these supplemental benefits to our executive officers due to the relatively low cost of such benefits and thevalue they provide in assisting us in attracting and retaining talented executives. The value of personal benefits and perquisites we provide to each of ourNEOs is set forth above in our “—Summary Compensation Table.” 59 Table of Contents Discretionary Long-Term Equity Incentive Awards In connection with our initial public offering, we adopted a new long-term equity incentive plan, or the LTIP. The LTIP was designed to promote ourinterests, as well as the interests of our unitholders, by rewarding the officers, employees and directors of us, our subsidiaries and our general partner fordelivering desired performance results, as well as by strengthening our and our general partner’s ability to attract, retain and motivate qualified individuals toserve as directors, consultants and employees. The LTIP provides for the grant, from time to time at the discretion of the board of directors of our generalpartner, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights and other unit-based awards,although in 2013 we only granted phantom unit awards pursuant to the LTIP. The outstanding LTIP awards held by our NEOs are reflected in the table below. Prior to the Holdings Acquisition, our NEOs historically received various forms of equity compensation, in the form of both capital and profits interestsin us and our predecessor entities, and in connection with the Holdings Acquisition, each of our NEOs re-invested a substantial portion of the cash proceedsreceived in respect of his prior equity interests in certain classes of capital or profit interest units in USA Compression Holdings. Our NEOs were also granted Class B Units of USA Compression Holdings at the time of the Holdings Acquisition. The grants the NEOs received hadtime-based vesting requirements (which were satisfied in full as of December 31, 2013) and are designed not only to compensate but also to motivate and retainthe recipients by providing an opportunity for equity ownership by our NEOs. The grants to our NEOs also provide our NEOs with meaningful incentives toincrease unitholder value over time. The Class B Units are profits interests that allow our NEOs to participate in the increase in value of USA CompressionHoldings over and above an 8% annual and cumulative preferred return hurdle. Available cash will be distributed to the USA Compression Holdings membersat such times as determined by its board of managers, at which time the holders of Class B Units could receive distributions if the cash distributed reachesthe required distribution hurdles. Distributions to the Class B Unit holders could also occur in connection with a sale or liquidation event of USACompression Holdings. To date, our NEOs have not received distributions with respect to these awards. Outstanding Equity Awards at December 31, 2013 The following table provides information regarding the Class B Units in USA Compression Holdings held by the NEOs as of December 31, 2013. Noneof our NEOs held any option awards that were outstanding as of December 31, 2013. Also reflected within the table are the outstanding phantom units thatwere granted to our NEOs from the LTIP during the 2013 year. Mr. Bourbonnais forfeited all equity awards in connection with his resignation during the 2013year. Unit AwardsNameNumber of Class B Units That Have Vested but Are Still Outstanding (#)(1)Market Value of Class B Units That Have Not Vested ($)(2)Number of Outstanding Phantom Units (#)(3)Market Value of Outstanding Phantom Units ($)(4)Eric D. Long462,500—61,2241,200,000Joseph C. Tusa, Jr.125,000—35,714700,000David A. Smith125,000—10,204200,000 (1) Represents the number of Class B Units in USA Compression Holdings that became vested but had not been settled as of December 31, 2013. TheseClass B Units vested in thirty-six equal monthly installments on each monthly anniversary of December 31, 2011. (2) As described under the heading “—Discretionary Long Term Equity Incentive Awards,” the Class B Units are intended to allow recipients to receive apercentage of profits generated by USA Compression Holdings over and above certain return hurdles. The Class B Units had no recognizable value as ofDecember 31, 2013 and the holders of the Class B Units had not received any distributions with respect to those awards during the 2013 year. (3) Represents the number of phantom units issued pursuant to the 2013 Long Term Incentive Plan that have not vested as of December 31, 2013. Eachphantom unit is the economic equivalent of one common unit. The phantom units shall vest in three equal annual installments, with the first installmentvesting on March 11, 2014. In the event of cessation of the NEO’s service for any reason, all phantom units that have not vested prior to or in connectionwith such cessation of service shall automatically be forfeited. 60 Table of Contents (4) The phantom unit values reflect the grant date fair value of the awards calculated in accordance with FASB ASC Topic 718. For a detailed discussion ofthe assumptions utilized in coming to these values, please see Note 7 to our consolidated financial statements. Severance and Change in Control Arrangements Our NEOs are entitled to severance payments and benefits upon certain terminations of employment and, in certain cases, in connection with a change incontrol of Holdings. Each NEO currently has an employment agreement with USAC Management that provides for severance benefits upon a termination of employment. OnJanuary 1, 2013, we entered into the services agreement with USAC Management, pursuant to which USAC Management provides to us and our generalpartner management, administrative and operating services and personnel to manage and operate our business. Pursuant to the services agreement, we willreimburse USAC Management for the allocable expenses for the services performed, including the salary, bonus, cash incentive compensation and otheramounts paid to our NEOs. See Part III, Item 13 “Certain Relationships and Related Transactions, and Director Independence.” Severance Arrangements Each NEO’s employment agreement, dated as of December 23, 2010, has an initial four-year term and will be extended automatically for successivetwelve month periods thereafter unless either party delivers written notice to the other within ninety days prior to the expiration of the then-current employmentterm. Upon termination of an NEO’s employment for any reason, all earned, unpaid annual base salary and all accrued, unused sick time off and vacationtime shall be paid to the NEO within thirty (30) days of the date of the NEO’s termination of employment. Upon termination of an NEO’s employment eitherby 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 toreceive (i) an amount equal to one times his annual base salary (plus, in the case of Mr. Long, an amount equal to one times his target annual bonus), payablein equal semi-monthly installments over one year following termination (the “Severance Period”) (or, if such termination occurs within two years following achange in control, in a lump sum within thirty days following the termination of employment), subject to acceleration upon the NEO’s death during theSeverance Period, and (ii) continued coverage for twenty-four (24) months (or, with respect to Mr. Long, thirty (30) months) under our group medical plan inwhich the executive and any of his dependents were participating immediately prior to his termination. Continued coverage under our group medical plan issubsidized for the first twelve (12) months following termination, after which time continued coverage shall be provided at the NEO’s sole expense (except withrespect to Mr. Long, who is entitled to reimbursement by us to the extent the cost of such coverage exceeds $1,200 per month) for the remainder of theapplicable 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 deathor disability, the NEO is entitled to receive (i) an amount equal to one times his annual bonus (up to his target annual bonus) for the immediately precedingyear and (ii) a pro-rata portion of any earned annual bonus for the year in which termination occurs (calculated with reference to the performance targetsestablished by the board of managers of USA Compression Holdings for that year). During employment and for two years following termination, each NEO’semployment 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 torenew the employment agreement at the end of an initial term or any renewal term, other than a termination for “cause.” “Cause” is defined in the NEOs’employment agreements to mean (i) any material breach of the employment agreement or the Holdings Operating Agreement, by the executive, (ii) the executive’sbreach 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 ordeceit, 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 ouraffiliates, (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 continuedfailure or refusal to perform substantially the executive’s material obligations pursuant to the employment agreement or the Holdings Operating Agreement orfollow any lawful and reasonable directive from the board of managers of USA Compression Holdings or, as applicable, the Chief Executive Officer, otherthan 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 ouror their reputation. 61 Table of Contents “Good reason” is defined in the NEOs’ employment agreements to mean (i) a material breach by us of the employment agreement, the Holdings OperatingAgreement, 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, otherthan an isolated and inadvertent failure not committed in bad faith, (iii) a material reduction in the executive’s duties, reporting relationships orresponsibilities, (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 reductionthat is generally applicable to all similarly situated employees, or (v) the relocation of the geographic location of the executive’s principal place of employmentby more than fifty miles from the location of the executive’s principal place of employment as of December 23, 2010. With respect to Mr. Long’s employmentagreement, “good reason” also means the failure to appoint and maintain Mr. Long in the office of President and Chief Executive Officer. On July 3, 2013, Mr. Bourbonnais announced his resignation as Vice President and Chief Operating Officer. Mr. Bourbonnais’ resignation becameeffective on August 2, 2013. In connection with his resignation, Mr. Bourbonnais entered into an agreement with USAC Management and us (the “Resignationand Consulting Agreement”). Pursuant to the Resignation and Consulting Agreement, Mr. Bourbonnais’ resignation was treated as a termination byMr. Bourbonnais for convenience, and thus he was generally only entitled to receive accrued but unpaid amounts under his employment agreement. Inaddition, in exchange for receipt of his executed release, under the Resignation and Consulting Agreement Mr. Bourbonnais was entitled to continued healthinsurance coverage for twenty-four (24) months under our group medical plan, with the first twelve (12) month period being subsidized and the second 12month period being provided at Mr. Bourbonnais’ sole expense. Mr. Bourbonnais’ rights to these benefits terminated on December 1, 2013 when he becameeligible under another employer’s plan. Furthermore, Mr. Bourbonnais continued to serve us as a consultant from the period beginning August 2, 2013 throughAugust 31, 2013 (the “Consulting Term”). Under the Resignation and Consulting Agreement, during the Consulting Term, Mr. Bourbonnais received a dailyrate equal to (x) $275,000 divided by (y) 365 for a total of $21,725. At the end of the Consulting Term and pursuant to the Resignation and ConsultingAgreement, Mr. Bourbonnais was paid a lump sum of $150,000. Each of the Class B Units held by the NEOs would be forfeited for no consideration if the NEO was terminated for cause. A termination for “Cause”under the USA Compression Holdings limited liability company agreement is defined substantially the same as the term used within the employmentagreements described above. In the event that the NEO’s employment is terminated for any reason, however, USA Compression Holdings (or its nominee)shall have the right, but not the obligation, to repurchase any vested Class B Units held by the terminated NEO for then-current fair market value or otheragreed value. Change in Control Benefits We generally have double- trigger change in control benefits for our outstanding LTIP awards. If a change in control occurs, and our NEOs are alsoterminated without cause or for good reason (each term as defined in the NEO’s employment agreement) in connection with that change in control event, thecurrent LTIP phantom units would become fully vested. The one exception to this practice is with respect to our CEO, who would receive immediate vesting ofany outstanding phantom units upon the change in control event. Changes Made in 2014 In February 2014, our board of directors approved the adoption of an Annual Cash Incentive Plan (the “Cash Plan”). Each of our NEOs would be entitledto participate in the Cash Plan and their potential bonus will be governed both by the Cash Plan and their employment agreement. The compensationcommittee will act as the administrator of the Cash Plan under the supervision of the full board of directors, and will have the discretion to amend, modify orterminate the Cash Plan at any time upon approval by the board of directors. The board of directors will set a target bonus amount (the “Target Bonus”) for each NEO prior to or during the first quarter of the calendar year. TheTarget Bonus will be subject to the satisfaction of both a partnership performance goal and an individual performance goal. Fifty percent (50%) of the TargetBonus will be subject to our achievement of our budgeted adjusted distributable cash flow level (“Adjusted DCF”) for the year, as determined by our board ofdirectors. Payouts with respect to the portion of the bonus subject to Adjusted DCF (the “Adjusted DCF Bonus”) will not occur unless we have satisfied thethreshold set for Adjusted DCF. For 2014, the board of directors has set the threshold for Adjusted DCF at $81 million. The threshold, target and maximumrequirements for the Adjusted DCF target for each year, as well as the portion of the Adjusted DCF Bonus that would become payable if performance wassatisfied for the year, are set forth below: Levels of AdjustedDCF BonusAdjusted DCF as aPercentage of BudgetedAdjusted DCF forthe 2014 YearPercentage ofAdjusted DCFBonus that wouldbe PaidThreshold80%50%Target100%100%Maximum110%200% If Adjusted DCF performance falls in between threshold and target, or between target and maximum, the amounts payable will be adjusted ratably usingstraight line interpolation. If Adjusted DCF is satisfied above maximum levels, the potential payment of the Adjusted DCF Bonus will be capped at themaximum level of 200%. The remaining fifty percent (50%) of the Target Bonus will be subject to individual objectives specific to each eligible individual’s role at USAC (the“Individual Bonus”). The individual objectives will be agreed upon in advance between the NEO and his immediate supervisor (or, with respect to the chiefexecutive officer, between the board of directors and the chief executive officer) that address the key priorities for that NEO’s position. They may include keyoperating objectives as well as personal development criteria. The Individual Bonus will be subject to a maximum payout of 100% of the targeted IndividualBonus amount, although the Board will have discretion to pay out smaller amounts ranging from 0% to 100%, at their sole discretion, after analyzing theindividual’s personal performance for the year. In the aggregate, the maximum amount payable with respect to a Target Bonus under the Plan will be 150%, as the Adjusted DCF Bonus will be capped at200% of target and the Individual Bonus will be capped at 100% of target. Target Bonuses, if any, shall be paid within one week following delivery by ourindependent auditor of the audit of our financial statements for the year in which the Target Bonus relates, but in no case later than March 15 of the yearfollowing the year in which the Target Bonus relates. 62 Table of Contents Director Compensation For the year ended December 31, 2013, our NEOs who also served as directors did not receive additional compensation for their service as directors. Onlythe independent members of our board of directors receive compensation for their service as directors. The following table shows the total compensation paid to each non-employee director during 2013. NameFees Earned orPaid in Cash($)Unit Awards($) (1)All OtherCompensation($)(2)Total($)John D. Chandler(3)26,50075,000—101,500Robert F. End148,75075,0004,775228,525William G. Manias(4)59,00075,000—134,000Forrest E. Wylie108,500(5)75,0002,274185,774 (1) Represents the grant date fair value of our phantom units, calculated in accordance with ASC 718. For a detailed discussion of the assumptionsutilized in coming to these values, please see Note 7 to our consolidated financial statements. As of December 31, 2013, our independent members ofthe board of directors held the following number of outstanding equity awards under the LTIP: Mr. Chandler, 3,020 phantom units; Mr. End, 3,826phantom units; and Mr. Wylie, 3,826 phantom units.(2) Amounts in this column reflect the value of dividend equivalent rights, or DERs, received by the directors with respect to their outstanding phantomunit awards.(3) Mr. Chandler was appointed to serve on the board on October 28, 2013.(4) Mr. Manias resigned from the board on July 15, 2013.(5) Mr. Wylie elected to receive his annual cash retainer of $75,000 in phantom units that vested in quarterly installments on each of March 31, 2013,June 30, 2013, September 30, 2013 and December 31, 2013. 63 Table of Contents Officers, employees or paid consultants or advisors of us or our general partner or its affiliates who also serve as directors do not receive additionalcompensation for their service as directors. Our directors who are not officers, employees or paid consultants or advisors of us or our general partner or itsaffiliates receive cash and equity based compensation for their services as directors. Our director compensation program consists of the following and will besubject to revision by the board of directors of our general partner from time to time: · an annual cash retainer of $75,000, · an additional annual retainer of $15,000 for service as the chair of any standing committee, · meeting attendance fees of $2,000 per meeting attended, and · an annual equity based award in the form of phantom units that will be granted under our LTIP, having a value as of the grant date of $75,000.Phantom unit awards are expected to be subject to vesting conditions (which, for the 2013 phantom unit grants was a one year vesting period). DERswill be paid either on a current or deferred basis, in each case as will be determined at the time of grant of the awards; the 2013 phantom unit awardsprovided for deferred DERs. Directors will also receive reimbursement for out-of-pocket expenses associated with attending such board or committee meetings and director and officerliability insurance coverage. Each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted underDelaware law. ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters Security Ownership of Certain Beneficial Owners and Management The following table sets forth the beneficial ownership of our units as of February 18, 2014 held by: · each person who beneficially owns 5% or more of our outstanding units; · all of the directors of USA Compression GP, LLC; · each named executive officer of USA Compression GP, LLC; and · all directors and officers of USA Compression GP, LLC as a group. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all units shown asbeneficially owned by them and their address is 100 Congress Avenue, Suite 450, Austin, Texas 78701. 64 Table of Contents Name of Beneficial OwnerCommonUnitsBeneficiallyOwnedPercentage ofCommonUnitsBeneficiallyOwnedSubordinatedUnitsBeneficiallyOwnedPercentage ofSubordinatedUnitsBeneficiallyOwnedPercentage of Common and Subordinated UnitsBeneficiallyOwnedUSA Compression Holdings(1)5,337,97722.2%14,048,588100.0%50.9%Argonaut Private Equity, L.L.C.(2)6,922,50428.8%——18.2%Oppenheimer Funds, Inc.(3)2,681,22211.2%——7.0%Eric D. Long(4)33,798*———Joseph C. Tusa, Jr.(5)11,906*———David A. Smith(6)3,402*———John D. Chandler—————Jim H. Derryberry—————William H. Shea, Jr.—————Robert F. End13,826*———Andrew W. Ward—————Olivia C. Wassenaar—————Forrest E. Wylie8,341*———All directors and executive officers as agroup (13 persons)(7)89,508*——— * Less than 1%. (1) Eric D. Long, Joseph C. Tusa, Jr., William G. Manias, J. Gregory Holloway, David A. Smith and Matthew C. Liuzzi, each of whom are executiveofficers of our general partner, Aladdin Partners, L.P., a limited partnership affiliated with Mr. Long, and R/C IV USACP Holdings, L.P., or R/CHoldings, own equity interests in USA Compression Holdings. USA Compression Holdings is managed by a three person board of managers consistingof Mr. Long, Mr. Ward and Ms. Wassenaar. The board of managers exercises investment discretion and control over the units held by USA CompressionHoldings. R/C Holdings is the record holder of approximately 97.4% of the limited liability company interests of USA Compression Holdings and is entitled to electa majority of the members of the board of managers of USA Compression Holdings. R/C Holdings is an investment partnership affiliated withRiverstone/Carlyle Global Energy and Power Fund IV, L.P., or R/C IV. Management and control of R/C Holdings is vested in its general partner, which isin turn managed and controlled by its general partner, R/C Energy GP IV, LLC. R/C Energy GP IV, LLC is managed by an eight person managementcommittee that includes Andrew W. Ward. The principal business address of R/C Energy GP IV, LLC is 712 Fifth Avenue, 51st Floor, New York, NewYork 10019. Mr. Long, Mr. Ward and Ms. Wassenaar, each of whom is a member of the board of managers of USA Compression Holdings and a member of theboard of directors of our general partner, disclaims beneficial ownership of the units owned by USA Compression Holdings. (2) Argonaut Private Equity, L.L.C. has sole voting and dispositive power of 6,922,504 common units. The principal business address of Argonaut PrivateEquity, L.L.C. is 6733 South Yale Avenue, Tulsa, Oklahoma 74136. (3) Oppenheimer Funds, Inc. has the shared power to vote or to direct the vote, and the shared power to dispose or to direct the disposition of, 2,681,222common units, including 2,650,571 common units held by Oppenheimer SteelPath MLP Income Fund, based on Amendment No. 3 to Schedule 13Gfiled on February 10, 2014 with the SEC. The principal business address of Oppenheimer Funds, Inc. is Two World Financial Center, 225 LibertyStreet, New York, New York 10281, and the principal business address of Oppenheimer SteelPath MLP Income Fund is 2100 Mckinney Ave,Suite 1401, Dallas, Texas 75201. (4) Includes 1,071 common units held directly by Mr. Long, 10,712 common units held by certain trusts of which Mr. Long is the trustee, 1,606 commonunits held by Mr. Long’s spouse and 20,408 common units that Mr. Long has the right to acquire within 60 days upon the vesting of his phantom units. (5) Includes 11,906 common units that Mr. Tusa has the right to acquire within 60 days upon the vesting of his phantom units. (6) Includes 3,402 common units that Mr. Smith has the right to acquire within 60 days upon the vesting of his phantom units. (7) Includes 53,476 common units that certain of our directors and executive officers have the right to receive within 60 days upon the vesting of phantomunits held by such directors and executive officers. 65 Table of Contents Securities Authorized for Issuance Under Equity Compensation Plans In connection with the consummation of our initial public offering on January 18, 2013, the board of directors of our general partner adopted the 2013Long-Term Incentive Plan. The following table provides certain information with respect to this plan as of December 31, 2013: Plan CategoryNumber of securities tobe issued upon exerciseof outstanding options,warrants and rightsWeighted-averageexercise price ofoutstanding options,warrants and rightsNumber of securitiesremaining available forfuture issuance underequity compensationplan (excluding securitiesreflected in the firstcolumn)Equity compensation plans approved by security holders—N/A—Equity compensation plans not approved by security holders229,991N/A1,180,009 For more information about our 2013 Long-Term Incentive Plan, please see Note 7 to our consolidated financial statements. 66 Table of Contents ITEM 13. Certain Relationships and Related Transactions, and Director Independence Certain Relationships And Related Party Transactions In connection with our formation and initial public offering, we and other parties have entered into the following agreements. These agreements were not theresult of arm’s length negotiations, and they, or any of the transactions that they provide for, may not be effected on terms as favorable to the parties to theseagreements as could have been obtained from unaffiliated third parties. Services Agreement We entered into a services agreement with USAC Management, effective on January 1, 2013, pursuant to which USAC Management provides to us andour general partner management, administrative and operating services and personnel to manage and operate our business. We or one of our subsidiaries paysUSAC Management for the allocable expenses it incurs in its performance under the services agreement. These expenses include, among other things, salary,bonus, cash incentive compensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated by USACManagement to us. USAC Management has substantial discretion to determine in good faith which expenses to incur on our behalf and what portion to allocateto us. The services agreement has an initial term of five years, at which point it automatically renews for additional one year terms. The services agreement maybe terminated at any time by (i) the board of directors of our general partner upon 120 days’ written notice for any reason in its sole discretion or (ii) USACManagement upon 120 days’ written notice if (a) we or our general partner experience a change of control, (b) we or our general partner breach the terms of theservices agreement in any material respect following 30 days’ written notice detailing the breach (which breach remains uncured after such period), (c) areceiver is appointed for all or substantially all of our or our general partner’s property or an order is made to wind up our or our general partner’s business;(d) a final judgment, order or decree that materially and adversely affects the ability of us or our general partner to perform under the services agreement isobtained or entered against us or our general partner, and such judgment, order or decree is not vacated, discharged or stayed; or (e) certain events ofbankruptcy, insolvency or reorganization of us or our general partner occur. USAC Management will not be liable to us for their performance of, or failure toperform, services under the services agreement unless its acts or omissions constitute gross negligence or willful misconduct. Management Fees For the year ended December 31, 2013, the Partnership incurred $49,315 of expenses related to a management fee under an agreement between USACompression Holdings, LLC and certain of its affiliates, for services provided to the Partnership for the period from January 1, 2013 through January 17,2013. For the year ended December 31, 2012, the Partnership incurred $1.0 million of management fees under such agreement. After the completion of ourinitial public offering on January 18, 2013, we and our subsidiaries are no longer required to pay this management fee. Relationship with PVR Partners Mr. Shea, a director of USA Compression GP, LLC, is currently a director and the chief executive officer of the general partner of PVR Partners, L.P.(“PVR”). For the years ended December 31, 2013 and 2012, subsidiaries of PVR made compression services payments to us of approximately $3.0 millionand $2.2 million, respectively. Procedures for Review, Approval and Ratification of Related Person Transactions The board of directors of our general partner adopted a code of business conduct and ethics in connection with the closing of our initial public offeringthat provides that the board of directors of our general partner or its authorized committee will periodically review all related person transactions that arerequired to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. If the board of directors of our generalpartner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the code of business conduct and ethicsprovides that our management will make all reasonable efforts to cancel or annul the transaction. 67 Table of Contents The code of business conduct and ethics provides that, in determining whether or not to recommend the initial approval or ratification of a related persontransaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available,including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as aresult of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on a director’sindependence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediately familymember of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services;(vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with thecode of business conduct and ethics. The code of business conduct and ethics described above was adopted in connection with the closing of our initial public offering, and as a result thetransactions described above were not reviewed under such policy. The transactions described above were not approved by an independent committee of ourboard of directors and the terms were determined by negotiation among the parties. Conflicts of Interest Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates, including USACompression Holdings, on the one hand, and our partnership and our limited partners, on the other hand. The directors and officers of our general partnerhave fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a fiduciary duty to manageour partnership in a manner beneficial to us and our unitholders. Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, our generalpartner will resolve that conflict. Our partnership agreement contains provisions that modify and limit our general partner’s fiduciary duties to our unitholders.Our partnership agreement also restricts the remedies available to our unitholders for actions taken by our general partner that, without those limitations, mightconstitute breaches of its fiduciary duty. Our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our unitholders if the resolutionof the conflict is: · approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval; · approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of itsaffiliates; · on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or · fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may beparticularly favorable or advantageous to us. Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of its board of directors. In connectionwith a situation involving a conflict of interest, any determination by our general partner involving the resolution of the conflict of interest must be made ingood faith, provided that, if our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution orcourse of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it willconclusively be deemed that, in making its decision, the board of directors acted in good faith. Unless the resolution of a conflict is specifically provided forin our partnership agreement, our general partner or the conflicts committee may consider any factors that it determines in good faith to be appropriate whenresolving a conflict. When our partnership agreement provides that someone act in good faith, it requires that person to reasonably believe he is acting in thebest interests of the partnership. 68 Table of Contents Director Independence Please see Part III, Item 10 (“Directors, Executive Officers and Corporate Governance—Board of Directors”) of this report for a discussion of directorindependence matters. ITEM 14. Principal Accountant Fees and Services The following table presents fees for professional services rendered by our independent registered public accounting firm, KPMG LLP during the yearsended December 31, 2013 and 2012: Year Ended December 31,20132012(in millions)Audit Fees (1)$0.7$0.5Audit-Related Fees——Tax Fees——All Other Fees——Total$0.7$0.5 (1) Expenditures classified as “Audit Fees” above were billed to USA Compression Partners, LP and include the audits of our annual financial statements,work related to the registration statement on Form S-1 filed in connection with our initial public offering, work related to the pro forma financialstatements in connection with the S&R Acquisition and reviews of our quarterly financial statements. Our audit committee has adopted an audit committee charter, which is available on our website and which requires the audit committee to pre-approve allaudit and non-audit services to be provided by our independent registered public accounting firm. The audit committee does not delegate its pre-approvalresponsibilities to management or to an individual member of the audit committee. Since our audit committee was not established until January 2013, none ofthe services reported in the audit, tax and all other fees categories above for the year ended December 31, 2012 were pre-approved by the audit committee. Ouraudit committee pre-approved all of the services reported in the audit, tax and all other fees categories for the year ended December 31, 2013. PART IV ITEM 15. Exhibits and Financial Statement Schedules (a) Documents filed as a part of this report. 1. Financial Statements. See “Index to Consolidated Financial Statements” set forth on Page F-1. 2. Financial Statement Schedule All other schedules have been omitted because they are not required under the relevant instructions. 3. Exhibits The following documents are filed as exhibits to this report: Exhibit NumberDescription2.1Contribution Agreement dated August 12, 2013 by and among USA Compression Partners, LP, S&R Compression, LLC and ArgonautPrivate Equity, L.L.C. (incorporated by reference to Exhibit 2.1 to the Partnership’s Quarterly Report on Form 10-Q (File No. 001-35779)filed on August 14, 2013) 3.1Certificate of Limited Partnership of USA Compression Partners, LP (incorporated by reference to Exhibit 3.1 to Amendment No. 3 of thePartnership’s registration statement on Form S-1 (Registration No. 333-174803) filed on December 21, 2011) 69 Table of Contents Exhibit NumberDescription3.2First Amended and Restated Agreement of Limited Partnership of USA Compression Partners, LP (incorporated by reference to Exhibit 3.1to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on January 18, 2013) 4.1Registration Rights Agreement dated August 30, 2013 (incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form8-K (File No. 001-35779) filed on September 5, 2013) 10.1Fourth Amended and Restated Credit Agreement (incorporated by reference to Exhibit 10.9 to Amendment No. 6 of the Partnership’sregistration statement on Form S-1 (Registration No. 333-174803) filed on June 8, 2012) 10.2First Amendment to Fourth Amended and Restated Credit Agreement (incorporated by reference to Exhibit 10.10 to Amendment No. 10 ofthe Partnership’s registration statement on Form S-1 (Registration No. 333-174803) filed on January 7, 2013) 10.3Fifth Amended and Restated Credit Agreement dated as of December 13, 2013, by and among USA Compression Partners, LP, USACOpCo 2, LLC and USAC Leasing 2, LLC, as guarantors, USA Compression Partners, LLC and USAC Leasing, LLC, as borrowers,the lenders party thereto from time to time, JPMorgan Chase Bank, N.A., as agent and LC issuer, J.P. Morgan Securities LLC, as leadarranger and sole book runner, Wells Fargo Bank, N.A., as documentation agent, and Regions Bank, as syndication agent (incorporatedby reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on December 17, 2013) 10.4†Long-Term Incentive Plan of USA Compression Partners, LP (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Reporton Form 8-K (File No. 001-35779) filed on January 18, 2013) 10.5†Employment Agreement, dated December 23, 2010, between USA Compression Partners, LLC and Eric D. Long (incorporated by referenceto Exhibit 10.5 to Amendment No. 4 of the Partnership’s registration statement on Form S-1 (Registration No. 333-174803) filed on February13, 2012) 10.6†Employment Agreement, dated December 23, 2010, between USA Compression Partners, LLC and Joseph C. Tusa, Jr. (incorporated byreference to Exhibit 10.6 to Amendment No. 4 of the Partnership’s registration statement on Form S-1 (Registration No. 333-174803) filed onFebruary 13, 2012) 10.7†Employment Agreement, dated December 23, 2010, between USA Compression Partners, LLC and David A. Smith (incorporated byreference to Exhibit 10.8 to Amendment No. 4 of the Partnership’s registration statement on Form S-1 (Registration No. 333-174803) filed onFebruary 13, 2012) 10.8Services Agreement, dated effective January 1, 2013, by and among USA Compression Partners, LP, USA Compression GP, LLC andUSA Compression Management Services, LLC (incorporated by reference to Exhibit 10.11 to Amendment No. 10 of the Partnership’sregistration statement on Form S-1 (Registration No. 333-174803) filed on January 7, 2013) 10.9†USA Compression Partners, LP 2013 Long-Term Incentive Plan—Form of Director Phantom Unit Agreement (incorporated by reference toExhibit 10.8 to the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2012 (File No. 001-35779) filed on March28, 2013) 10.10*†USA Compression Partners, LP 2013 Long-Term Incentive Plan—Form of Employee Phantom Unit Agreement 10.11†USA Compression Partners, LP 2013 Long-Term Incentive Plan—Form of Director Phantom Unit Agreement (in lieu of Annual CashRetainer) (incorporated by reference to Exhibit 10.10 to the Partnership’s Annual Report on Form 10-K for the year ended December 31,2012 (File No. 001-35779) filed on March 28, 2013). 10.12*†USAC Compression Partners, LP Annual Cash Incentive Program 70 Table of Contents Exhibit NumberDescription21.1*List of subsidiaries of USA Compression Partners, LP 23.1*Consent of KPMG LLP 31.1*Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 31.2*Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 32.1#Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 32.2#Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 101.INS##XBRL Instance Document 101.SCH##XBRL Extension Schema Document 101.CAL##XBRL Calculation Linkbase Document 101.DEF##XBRL Definition Linkbase Document 101.LAB##XBRL Label Linkbase Document 101.PRE##XBRL Presentation Linkbase Document * Filed Herewith. # Furnished herewith; not considered to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to theliabilities of that section. † Management contract or compensatory plan or arrangement required to be filed as an exhibit to this Annual Report on Form 10-K pursuant to Item 15(b). ## Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes ofSection 11 and 12 of the Securities Act of 1933, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and otherwise arenot subject to any liability under those sections. 71 Table of Contents SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on itsbehalf by the undersigned, thereunto duly authorized. USA COMPRESSION PARTNERS, LP By:USA Compression Partners, LP,its General Partner By:/s/ Eric D. LongEric D. LongPresident and Chief Executive Officer(Principal Executive Officer) Date:February 20, 2014 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrantand in the capacities indicated on February 20, 2014. NameTitle /s/ Eric D. LongPresident and Chief Executive OfficerEric D. Long(Principal Executive Officer) and Director /s/ Joseph C. Tusa, Jr.Vice President, Chief Financial Officer and Treasurer (Principal FinancialOfficer andJoseph C. Tusa, Jr.Principal Accounting Officer /s/ John D. ChandlerDirectorJohn D. Chandler /s/ Jim H. DerryberryDirectorJim H. Derryberry /s/ Robert F. EndDirectorRobert F. End /s/ William H. Shea, Jr.DirectorWilliam H. Shea, Jr. /s/ Andrew W. WardDirectorAndrew W. Ward /s/ Olivia C. WassenaarDirectorOlivia C. Wassenaar /s/ Forrest E. WylieDirectorForrest E. Wylie 72 Table of Contents INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report of Independent Registered Public Accounting FirmF-1Consolidated Balance Sheets as of December 31, 2013 and 2012F-2Consolidated Statements of Operations for the years ended December 31, 2013, 2012 and 2011F-3Consolidated Statements of Changes in Partners’ Capital for the years ended December 31, 2013, 2012 and 2011F-4Consolidated Statements of Cash Flows for the years ended December 31, 2013, 2012 and 2011F-5Notes to Consolidated Financial StatementsF-6 Table of Contents Report of Independent Registered Public Accounting Firm The PartnersUSA Compression Partners, LP: We have audited the accompanying consolidated balance sheets of USA Compression Partners, LP (a Delaware limited partnership) and subsidiaries as ofDecember 31, 2013 and 2012, and the related consolidated statements of operations, changes in partners’ capital, and cash flows for each of the years in thethree-year period ended December 31, 2013. These consolidated financial statements are the responsibility of the Partnership’s management. Our responsibilityis to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require thatwe plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accountingprinciples used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our auditsprovide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of USA CompressionPartners, LP and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the years in the three-yearperiod ended December 31, 2013, in conformity with U.S. generally accepted accounting principles. /s/ KPMG LLP Dallas, TexasFebruary 20, 2014 F-1 Table of Contents USA COMPRESSION PARTNERS, LP AND SUBSIDIARIES Consolidated Balance SheetsDecember 31, 2013 and 2012(in thousands, except for unit amounts) 20132012AssetsCurrent assets:Cash and cash equivalents$7$7Accounts receivable:Trade20,0798,618Other350137Inventory9,9404,215Prepaid expenses2,4001,800Total current assets32,77614,777Property and equipment, net852,966610,130Identifiable intangible asset-customer relationships71,38867,200Identifiable intangible asset-trade names13,72814,352Identifiable intangible asset-non-compete825—Goodwill208,055157,075Other assets6,1469,111Total assets$1,185,884$872,645 Liabilities and Partners’ CapitalCurrent liabilities:Accounts payable$34,629$10,651Accrued liabilities10,4125,590Deferred revenue11,91210,612Total current liabilities56,95326,853Long-term debt420,933502,266Other liabilities271—Partners’ capital:Limited partner interest:Common units, 23,561,780 units outstanding at December 31, 2013447,562—Subordinated units, 14,048,588 units outstanding at December 31, 2013245,592—General partner interest: 2% interest with 767,558 equivalent units issued and outstanding at December 31,201314,573—Limited partners’ capital—341,130General partner’s capital—2,396Total partners’ capital707,727343,526Total liabilities and partners’ capital$1,185,884$872,645 See accompanying notes to consolidated financial statements. F-2 Table of Contents USA COMPRESSION PARTNERS, LP AND SUBSIDIARIES Consolidated Statements of OperationsYears ended December 31, 2013, 2012 and 2011(in thousands, except per unit amounts) 201320122011Revenues:Contract operations$150,360$116,373$93,896Parts and service2,5582,4144,824Total revenues152,918118,78798,720 Costs and expenses:Cost of operations, exclusive of depreciation and amortization48,09737,79639,605Selling, general and administrative27,58718,26912,726Restructuring charges——300Depreciation and amortization52,91741,88032,738Loss on sale of assets284266178Impairment of compression equipment203——Total costs and expenses129,08898,21185,547Operating income23,83020,57613,173Other income (expense):Interest expense(12,488)(15,905)(12,970)Other92821Total other expense(12,479)(15,877)(12,949)Net income before income tax expense11,3514,699224Income tax expense280196155Net income$11,071$4,503$69 Less:Earnings allocated to general partner prior to initial public offering on January 18,2013$5$45$1Earnings available for limited partners prior to initial public offering on January 18,2013$530$4,458$68Net income subsequent to initial public offering on January 18, 2013$10,536$—$— Net income subsequent to initial public offering allocated to:General partner’s interest in net income$211$—$—Limited partners’ interest in net income:Common units$5,805$—$—Subordinated units$4,520$—$— Weighted average common units outstanding:Basic18,043,075——Diluted18,086,745—— Weighted average subordinated units outstanding:Basic and diluted14,048,588—— Net income per common unit:Basic$0.32$—$—Diluted$0.32$—$— Net income per subordinated unit:Basic and diluted$0.32$—$— Distributions paid per limited partner unit in respective periods$1.25$—$— See accompanying notes to consolidated financial statements. F-3 Table of Contents USA COMPRESSION PARTNERS, LP AND SUBSIDIARIES Consolidated Statements of Changes in Partners’ CapitalYears ended December 31, 2013, 2012 and 2011(in thousands) Partners’ CapitalTotalGeneralLimitedCommon UnitsSubordinated UnitsGeneral Partner UnitsPartners’PartnersPartnersUnitsAmountUnitsAmountUnitsAmountCapitalPartners’ capital opening balance,December 31, 2010$2,350$336,604—$——$——$—$338,954Net Income168——————69Partners’ capital, December 31, 20112,351336,672——————339,023Net Income454,458——————4,503Partners’ capital, December 31, 20122,396341,130——————343,526Net income January 1, 2013 —January 18, 20135530——————535Conversion of Partners’ capital forcommon and subordinatedunits, Incentive Distribution Rights,and General Partner interest(2,401)(341,660)4,04974,52614,049258,60559410,930—Issuance of common units in initialpublic offering——11,000180,555————180,555Vesting of phantom units——4——————General partner contribution——————1744,2514,251Cash distributions and DERs———(22,872)—(17,533)—(819)(41,224)Proceeds from issuance of common Units——1,08426,286————26,286Unit-based compensation———1,343————1,343Acquisition of S&R compression assets——7,425181,919————181,919Net income January 19, 2013 —December 31, 2013———5,805—4,520—21110,536Partners’ capital, December 31, 2013$—$—23,562$447,56214,049$245,592768$14,573$707,727 See accompanying notes to consolidated financial statements. F-4 Table of Contents USA COMPRESSION PARTNERS, LP AND SUBSIDIARIES Consolidated Statements of Cash FlowsYears ended December 31, 2013, 2012 and 2011(in thousands) 201320122011Cash flow from operating activities:Net Income$11,071$4,503$69Adjustments to reconcile net income to net cash provided by operating activities:Depreciation and amortization52,91741,88032,738Amortization of debt issue costs, discount2,1921,8561,529Unit-based compensation expense1,343——Net loss on sale of assets284266178Net gain on change in fair value of interest rate swap—(2,180)(2,629)Impairment of compression equipment203——Changes in assets and liabilities:Accounts receivable and advances to employees(11,674)169(976)Inventory(5,725)(1,004)1,974Prepaids(600)(153)(219)Other noncurrent assets3,824(1,315)(2,601)Accounts payable8,132(5,340)1,989Accrued liabilities and deferred revenue6,2233,2921,730Net cash provided by operating activities68,19041,97433,782Cash flow from investing activities:Capital expenditures(159,547)(179,977)(133,264)Compression unit purchase deposit——(7,975)Proceeds from sale of property and equipment2,2271,388795Acquisitions, net of cash3,374——Net cash used in investing activities(153,946)(178,589)(140,444)Cash flows from financing activities:Proceeds from short-term and long-term debt243,501261,135209,165Payments on short-term and long-term debt(324,834)(122,681)(101,167)Net proceeds from issuance of common units180,555——Cash Distributions(14,669)——General Partner contribution4,251——Financing Cost(3,048)(1,835)(1,336)Net cash provided by financing activities85,756136,619106,662Increase in cash and cash equivalents—4—Cash and cash equivalents, beginning of year733Cash and cash equivalents, end of year$7$7$3Supplemental cash flow information:Cash paid for interest$10,603$16,086$13,727Cash paid for taxes$196$155$155 See accompanying notes to consolidated financial statements. F-5 Table of Contents USA COMPRESSION PARTNERS, LP AND SUBSIDIARIESNotes to Consolidated Financial StatementsDecember 31, 2013, 2012 and 2011 (1) The Partnership, Nature of Business, and Recent Transactions USA Compression Partners, L.P., a Texas limited partnership (the “Former Partnership”), was formed on July 10, 1998. In October 2008, the FormerPartnership entered into several transactions through which the Former Partnership was reorganized into a holding company, USA Compression Holdings, LP(the “Partnership”). The owners of the Former Partnership caused the Partnership to be formed as a Texas limited partnership to conduct its affairs as theholding company of an operating and leasing structure of entities. The Former Partnership’s owners then transferred their equity interests in the FormerPartnership to the Partnership in exchange for identical interests in the Partnership. The Former Partnership became a wholly-owned subsidiary of thePartnership, and was converted into USA Compression Partners, LLC, a Delaware, single-member, limited liability company (the “Operating Subsidiary”) tocontinue providing compression services to customers of the Former Partnership. Concurrently, the Operating Subsidiary formed a wholly-owned subsidiary,USAC Leasing, LLC, as a Delaware limited liability company (the “Leasing Subsidiary”), and agreed to sell its then existing compressor fleet to the LeasingSubsidiary for assumption of debt relating to the then existing fleet. The Leasing Subsidiary leases its compressor fleet to the Operating Subsidiary for use inproviding compression services to its customers. The Partnership joined the Operating Subsidiary’s revolving credit facility as a guarantor and the LeasingSubsidiary joined the revolving credit facility as a co-borrower (see note 4). On June 7, 2011, the Partnership converted from a Texas limited partnership into aDelaware limited partnership and changed its name from USA Compression Holdings, LP to USA Compression Partners, LP. USA Compression GP, LLC,a Delaware limited liability Company and the general partner of the Partnership, is referred to herein as the “General Partner.” In connection with the S&RAcquisition (as defined below), the Partnership acquired all of the membership interests in USAC OpCo 2, LLC, a Texas limited liability company (“OpCo2”), which owned all of the membership interests in USAC Leasing 2, LLC, a Texas limited liability company (“LeaseCo 2”). LeaseCo 2 owns all of thecompression assets acquired in the S&R Acquisition. LeaseCo 2 leases its compressor fleet to OpCo 2 for use in providing compression services to itscustomers. The accompanying consolidated financial statements include the accounts of the Partnership, the Operating Subsidiary, the Leasing Subsidiary,OpCo 2 and LeaseCo 2, and all intercompany balances and transactions have been eliminated in consolidation. The Operating Subsidiary, the LeasingSubsidiary, OpCo 2 and LeaseCo 2, are collectively referred to herein, as the “Operating Subsidiaries.” The Partnership, through the Operating Subsidiaries, primarily provides natural gas compression services under term contracts with customers in the oiland gas industry, using natural gas compressor packages that it designs, engineers, operates and maintains. Partnership net income (loss) is allocated to the partners, both general and limited, in proportion to their respective interest in the Partnership. On January 18, 2013, the Partnership completed its initial public offering (“IPO”) pursuant to a Registration Statement on Form S-1, as amended (Reg.No. 333-174803), that was declared effective on January 14, 2013. Under the registration statement, the Partnership sold 11,000,000 common units at a priceto the public of $18.00 per common unit, which generated net proceeds to the Partnership of approximately $180.5 million after deducting underwritingdiscounts and commissions of $12.1 million, structuring fees of $0.7 million and offering expenses of $4.6 million. The Partnership used the net proceedsfrom the offering to repay $180.5 million of indebtedness outstanding under its revolving credit facility. On August 30, 2013, the Partnership completed the acquisition of assets and certain liabilities related to the business of providing gas lift compressionservices to third parties engaged in the exploration, production, gathering, processing, transportation or distribution of oil and gas (the “S&R Acquisition”) inexchange for 7,425,261 common units, which were valued at $181.9 million at the time of issuance. The S&R Acquisition was consummated pursuant tothe Contribution Agreement dated August 12, 2013 (the “Contribution Agreement”) with S&R Compression, LLC, (“S&R”) and Argonaut Private Equity,L.L.C. (“Argonaut”). The S&R Acquisition had an effective date (from a standpoint of revenues and selected costs) of June 30, 2013. The common unitsissued in the S&R Acquisition were not registered pursuant to the Securities Act of 1933, as amended (the “Securities Act”), or any applicable state securitieslaws, and, at the time of issuance, were restricted securities under the federal securities laws. F-6 Table of Contents USA COMPRESSION PARTNERS, LP AND SUBSIDIARIESNotes to Consolidated Financial StatementsDecember 31, 2013, 2012 and 2011 (2) Summary of Significant Accounting Policies (a) Cash and Cash Equivalents Cash and cash equivalents consist of all cash balances. As of December 31, 2013 and 2012, $6,500 in cash was subject to certain provisions undercredit agreements with a financial institution, as more fully described in Note 5. (b) Trade Accounts Receivable Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts of $246,410 and $259,638at December 31, 2013 and 2012, respectively, is the Partnership’s best estimate of the amount of probable credit losses in the Partnership’s existing accountsreceivable. The Partnership determines the allowance based upon historical write-off experience and specific identification. The Partnership does not have anyoff-balance-sheet credit exposure related to its customers. (c) Inventories Inventories are valued at the lower of cost or market using the first-in, first-out method. Inventory consists of parts used in the assembly of compressionunits. Purchases of these assets are considered operating activities in the consolidated statement of cash flows. (d) Property and Equipment Property and equipment are carried at cost. Overhauls and major improvements that increase the value or extend the life of compressor units arecapitalized and depreciated over 3 to 5 years. Ordinary maintenance and repairs are charged to income. Depreciation is calculated using the straight-line methodof accounting over the estimated useful lives of the assets as follows: Compression equipment25 yearsFurniture and fixtures7 yearsVehicles and computer equipment3 - 7 yearsLeasehold improvements5 years Depreciation expense for the years ended December 31, 2013, 2012 and 2011 was $49.7 million, $38.9 million and $29.7 million, respectively. (e) Impairments of Long-Lived Assets Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to estimated fair value. An assetshall be tested for impairment when events or circumstances indicate that its carrying value may not be recoverable. The carrying value of a long-lived asset isnot recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying valueexceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount of the carrying value exceeding the fair value of the asset isrecognized. 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 ofdiscounted cash flows. In 2013, the Partnership recorded $203,149 related to the impairment of a certain group of its compression equipment. The Partnershipdid not record impairment of long-lived assets in 2012 or 2011. (f) Revenue Recognition Revenue from compression service and equipment rental operations is recorded when earned over the period of service, rental and maintenance contracts,which generally range from one month to five years. Parts and service revenue is recorded as parts are delivered or services are performed for the customer. F-7 Table of Contents USA COMPRESSION PARTNERS, LP AND SUBSIDIARIESNotes to Consolidated Financial StatementsDecember 31, 2013, 2012 and 2011 (g) Income Taxes The Partnership elected to be treated under SubChapter K of the Internal Revenue Code. Under SubChapter K, a partnership return is filed annuallyreflecting each partner’s share of the partnership’s income or loss. Therefore, no provision has been made for federal income tax. Partnership net income (loss)is allocated to the partners in proportion to their respective interest in the Partnership. As a partnership, all income, gains, losses, expenses, deductions and tax credits generated by the Partnership generally flow through to its unitholders.However, Texas imposes an entity-level income tax on partnerships. The State of Texas’ margin tax became effective for tax reports originally due on or after January 1, 2008. This margin tax requires partnerships and otherforms of legal entities to pay a tax of 1.0% on its ‘‘margin,’’ as defined in the law, based on 2013, 2012 and 2011 results. The margin tax base to which thetax rate will be applied is either the lesser of 70% of total revenues for federal income tax purposes, total revenue less cost of goods sold or compensation forfederal income tax purposes. For the years ended December 31, 2013, 2012 and 2011, the Partnership recorded expense related to the Texas margin tax of$279,972, $196,040 and $154,872, respectively. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not of being realized uponultimate settlement with a taxing authority. Interest and penalties related to unrecognized tax benefits are included in income tax expense. (h) Fair Value Measurements The accounting standard for fair value measurements and disclosures establishes a fair value hierarchy that prioritizes the inputs to valuation techniquesused to measure fair value into the following three broad categories: Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the Partnership has the ability to access at themeasurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. At December 31, 2013 and 2012, the Partnership’s financial instruments consist primarily of cash and cash equivalents, trade accounts receivable, tradeaccounts payable and long-term debt. The book values of cash and cash equivalents, trade accounts receivable, and trade accounts payable are representativeof fair value due to their short-term maturity. The carrying amount of long-term debt approximates fair value based on the interest rates charged on instrumentswith similar terms and risks. (i) Pass Through Taxes Taxes incurred on behalf of, and passed through to, customers are accounted for on a net basis. (j) Use of Estimates The preparation of the consolidated financial statements of the Partnership in conformity with accounting principles generally accepted in the UnitedStates of America requires the management of the Partnership to make estimates and assumptions that affect the amounts reported in these consolidatedfinancial statements and the accompanying results. Actual results could differ from these estimates. F-8 Table of Contents USA COMPRESSION PARTNERS, LP AND SUBSIDIARIESNotes to Consolidated Financial StatementsDecember 31, 2013, 2012 and 2011 (k) Intangible Assets As of December 31, 2013, intangible assets consisted of the following (in thousands): CustomerRelationshipsTrade NamesNon-competeTotalBalance at December 31, 2012$67,200$14,352$—$81,552Additions — S&R Acquisition6,700—9007,600Amortization(2,512)(624)(75)(3,211)Balance at December 31, 2013$71,388$13,728$825$85,941 Intangible assets are amortized on a straight-line basis over their estimated useful lives, which is the period over which the assets are expected to contributedirectly or indirectly to the Partnership’s future cash flows. The estimated useful lives range from 4 to 30 years. The expected amortization of the intangibleassets for each of the five succeeding years is as follows (in thousands): Year Ending December 31,Total2014$3,58420153,58420163,58420173,50920183,359 The Partnership assesses long-lived assets, including intangible assets, for impairment whenever events or changes in circumstances indicate that thecarrying amount of an asset may not be recoverable. Recoverability is assessed by comparing the carrying amount of an asset to undiscounted future net cashflows expected to be generated by the asset. If such assets are considered to be impaired, the impairment to be recognized is measured as the amount by whichthe carrying amounts exceed the fair values of the assets. The Partnership did not record any impairment of intangible assets in 2013, 2012 or 2011. (l) Goodwill Goodwill represents consideration paid in excess of the fair value of the identifiable assets acquired in a business combination. Goodwill is not amortized,but is reviewed for impairment annually based on the carrying values as of October 1, or more frequently if impairment indicators arise that suggest thecarrying value of goodwill may not be recovered. As of October 1, 2013, a qualitative assessment was performed to determine whether it is more likely than not that the fair value of the reporting unit isimpaired. Management used all available information to make these determinations, including evaluating the macroeconomic environment, industry specificconditions, cost factors, overall financial performance and unit price, at the assessment date of October 1, 2013. As a result of the qualitative assessment, the Partnership has determined that it is not more likely than not that the fair value of the reporting unit is lessthan its carrying amount. The Partnership did not record any impairment of goodwill for the years ended December 31, 2013, 2012 or 2011. (3) Acquisition On August 30, 2013, the Partnership completed the acquisition of assets and certain liabilities related to the business of providing gas lift compressionservices to third parties engaged in the exploration, production, gathering, processing, transportation or distribution of oil and gas in exchange for 7,425,261common units, which were valued at $181.9 million at the time of issuance. The S&R Acquisition was consummated pursuant to the Contribution Agreementwith S&R and Argonaut. The S&R Acquisition had an effective date (from a standpoint of revenues and selected costs) of June 30, 2013. The common unitsissued in the S&R Acquisition were not registered pursuant to the Securities Act, or any applicable state securities laws, and, at the time of issuance, wererestricted securities under the federal securities laws. In connection with the S&R Acquisition, Argonaut and certain related parties F-9 Table of Contents USA COMPRESSION PARTNERS, LP AND SUBSIDIARIESNotes to Consolidated Financial StatementsDecember 31, 2013, 2012 and 2011 agreed to participate in the Partnership’s Distribution Reinvestment Plan (“DRIP”) through the distribution relating to the quarter ended June 30, 2014, providedthat USA Compression Holdings continues to participate in the DRIP through that same period. The effective purchase price of $178.5 million reflectscustomary effective-date adjustments such as a $3.4 million purchase price adjustment due to working capital changes from the effective date to the closingdate. The transaction was accounted for in accordance with Accounting Standards Codification 805, Business Combinations. The purchase price allocation asof August 30, 2013 is comprised of the following components (in thousands): Issuance of limited partner units$181,919Less cash received for working capital adjustment(3,374)Total consideration$178,545 Trucks and Trailers$2,158Compression equipment117,784Computers23IntangiblesCustomer relationships6,700Non-compete900Total intangibles7,600Goodwill50,980Allocation of Purchase Consideration$178,545 Expenses associated with acquisition activities and transaction activities related to the S&R Acquisition for the year ended December 31, 2013 were $2.1million and are included in selling, general and administrative expenses (“SG&A”). The acquisition was recorded at fair value, which was determined usingthe cost and market approaches for the fixed assets, the multi-period excess earnings method for the customer relationships asset and the with-and-withoutmethod for the non-compete agreement. In applying these accounting principles, we estimated the fair value of the S&R assets acquired to be $127.6 million.This measurement resulted in the recognition of goodwill totaling approximately $51.0 million. Goodwill was calculated as the excess of the considerationtransferred to acquire S&R over the acquisition date estimated fair value of the assets acquired. Goodwill recorded in the S&R Acquisition primarilyrepresents the value of the opportunity to expand into gas lift operations with a high quality fleet, the experience and technical expertise of former S&Remployees who have joined the Partnership and the addition of strategic areas of operations in which the Partnership did not previously have a significantpresence. The intangible asset customer relationships will be amortized over a life of 20 years and the intangible asset non-compete will be amortized over the 4-year term of the agreement. The Partnership recorded a purchase price adjustment of $292,496 related to S&R Acquisition expenses during the fourth quarter of 2013, increasing theamount of goodwill recorded on the December 31, 2013 balance sheet, included in amounts noted above. Revenue, Net Income and Pro Forma Financial Information — Unaudited The S&R Acquisition was not included in the Partnership’s consolidated results until the closing date of August 30, 2013. For the period of August 30,2013 to December 31, 2013, the S&R Acquisition accounted for $14.5 million of revenue, $4.4 million of direct operating expenses and $3.7 million ofdepreciation and amortization, resulting in $6.4 million of net income. The net income attributable to these assets does not reflect certain expenses, such asSG&A and interest expense; therefore, this information is not intended to report results as if these operations were managed on a stand-alone basis. The unaudited pro forma financial information was prepared assuming the S&R Acquisition occurred on January 1, 2011. The financial informationwas derived from the Partnership’s audited historical consolidated financial statements for the years ended December 31, 2013, 2012 and 2011, S&R’saudited historical consolidated financial statements for the years ended December 31, 2012 and 2011, and S&R’s unaudited interim financial statements fromJanuary 1, 2013 through August 30, 2013. F-10 Table of Contents USA COMPRESSION PARTNERS, LP AND SUBSIDIARIESNotes to Consolidated Financial StatementsDecember 31, 2013, 2012 and 2011 The pro forma adjustments were based on currently available information and certain estimates and assumptions by management. If the S&R Acquisitionhad been in effect on the dates or for the periods indicated, the results may have been substantially different. For example, we may have operated the assetsdifferently than S&R, realized revenue may have been different and costs of operation of the compression assets may have been different. This pro formafinancial information is provided for illustrative purposes only and may not provide an indication of results in the future. The following table presents asummary of our pro forma financial information (in thousands, except earnings per share): Year Ended December 31,201320122011(unaudited)Total revenues$176,254$143,985$115,890Net income (loss)15,9198,312(3,504)Net income allocated to:General partner’s interest in net income (1)318——Common units interest in net income (1)10,054——Subordinated units interest in net income (1)5,546——Basic and diluted net income per common unit (1)$0.39——Basic and diluted net income per subordinated unit (1)$0.39—— (1) The Partnership did not complete its initial public offering until January 18, 2013. Therefore, earnings per unit information is not applicable for the2012 or 2011 period. In preparing the pro forma financial information, certain information was derived from financial records and certain information was estimated. Thesources of information and significant assumptions are described below: (a) Revenues and direct operating expenses for S&R were derived from the historical financial records of S&R. Incremental revenue adjustmentsrelated to the S&R Acquisition were $27.1 million, $25.2 million and $17.2 million for the years ended December 31, 2013, 2012 and 2011,respectively. Incremental operating costs related to the S&R Acquisition were $12.2 million, $12.4 million and $9.5 million for the years endedDecember 31, 2013, 2012 and 2011, respectively. (b) Depreciation and amortization was estimated using the straight-line method and reflects the incremental depreciation and amortization expenseincurred due to adding the compression assets and intangible fair value assets acquired from S&R. Incremental depreciation and amortizationwas estimated at $9.7 million for the years ended December 30, 2013, 2012 and 2011. (c) Incremental transaction expenses related to the S&R Acquisition were $2.1 million and were assumed to be funded from cash on hand. (d) The S&R Acquisition was financed solely with common units issued in consideration for the assets and liabilities acquired as part of the S&RAcquisition. (e) The capital contribution made by the General Partner to maintain its 2% general partner interest in the Partnership in connection with theissuance of common units in the S&R Acquisition was used to pay down the Partnership’s revolving credit facility resulting in a reduction ofinterest expense. Incremental interest expense reductions were estimated at $90,000, $111,000 and $138,000 for the years ended December 31,2013, 2012 and 2011, respectively. (4) Property and Equipment Property and equipment consisted of the following at December 31 (in thousands): 20132012Compression equipment$950,823$666,811Furniture and fixtures706439Automobiles and vehicles12,4767,588Computer equipment5,6363,206Leasehold improvements11698Total969,757678,142Less: accumulated depreciation and amortization(116,791)(68,012)Total$852,966$610,130 F-11 Table of Contents USA COMPRESSION PARTNERS, LP AND SUBSIDIARIESNotes to Consolidated Financial StatementsDecember 31, 2013, 2012 and 2011 As of December 31, 2013 and 2012, there was $15.8 million and $5.9 million, respectively, of property and equipment purchases in accounts payableand accrued liabilities. (5) Long-Term Debt The long-term debt of the Partnership consisted of the following at December 31 (in thousands): 20132012Senior debt$420,933$502,266 (a) Senior Debt On December 23, 2010, the Partnership entered into a Third Amended and Restated Credit Agreement. Borrowing availability under this senior debtfacility was limited to the lesser of the $400 million committed facility amount and a borrowing base defined in the credit agreement. The senior debt facilitywas evidenced by notes issued to each of several lenders named in the credit agreement, was secured by a first priority lien against the assets of the Partnershipand matured on October 5, 2015. Interest on debt issued under the facility was due and payable in arrears and calculated, at the option of the Partnership, oneither a floating rate basis, payable monthly or a LIBOR basis, payable at the end of the applicable LIBOR period (1, 2, 3, or 6 months), but no lessfrequently than quarterly. LIBOR borrowings bore interest at LIBOR for the applicable period plus a margin of 3.00% to 3.75% based on the leverage ratio ofthe Partnership’s amount outstanding under this facility to consolidated EBITDA (earnings before interest, taxes, depreciation and amortization) as defined inthe credit agreement. Floating rate borrowings bore interest at a rate per annum that is the higher of the bank prime rate or the federal funds rate plus 0.50%,without additional margin. Generally, the Partnership has maintained several tranches of LIBOR and floating rate borrowings at any time. In addition, thePartnership paid an annual administration fee and an unused commitment fee of 0.50%. The $400 million facility included a $20 million sub-line for issuingletters of credit for a fee at a per annum rate equal to the margin for LIBOR borrowings on the average daily undrawn stated amount of each letter of creditissued under the facility. The Partnership paid various loan fees and incurred costs in respect of the Third Amended and Restated Credit Agreement in theamount of $5.1 million in 2010. On June 6, 2011, the Partnership entered into the first amendment to the credit agreement converting each reference to “USA Compression Holdings, LP”to “USA Compression Partners, LP” and each reference to USA Compression Holdings, LP as a “Texas limited partnership” in the credit agreement or anyother loan document to be a reference to USA Compression Partners, LP as a “Delaware limited partnership.” On November 16, 2011, the Partnership entered into the second amendment to the credit agreement whereby the aggregate commitment under the facilityincreased from $400 million to $500 million and reduced the applicable margin for LIBOR loans to a range of 200 to 275 basis points above LIBOR,depending on the Partnership’s leverage ratio. In addition, the unused commitment fee was reduced to 0.375%. The Partnership paid various loan fees andincurred costs in respect of the first and second amendment to the credit agreement in the amount of $1.1 million in 2011. On June 1, 2012, the Partnership entered into the third amendment to the credit agreement whereby the aggregate commitment under the facility increasedfrom $500 million to $600 million. In addition, on June 1, 2012, the Partnership entered into the Fourth Amended and Restated Credit Agreement in order toprovide a covenant structure that is more appropriate for a public company than was the prior credit agreement, including a reduction of the applicable marginfor LIBOR loans to a range of 175 to 250 basis points above LIBOR, depending on the Partnership’s leverage ratio. This amended and restated creditagreement became effective on January 18, 2013, the closing date of the Partnership’s initial public offering, continued to be secured by a first priority lienagainst our assets and had a scheduled maturity of October 5, 2015. On December 10, 2012, the Partnership amended the Fourth Amended and RestatedCredit Agreement to extend the periods during which the maximum funded debt to EBITDA ratio thresholds would apply. The Partnership paid various loanfees and incurred costs in respect of the third amendment to the credit agreement and the Fourth Amended and Restated Credit Agreement in the amount of $1.6million, in 2012. F-12 Table of Contents USA COMPRESSION PARTNERS, LP AND SUBSIDIARIESNotes to Consolidated Financial StatementsDecember 31, 2013, 2012 and 2011 On December 13, 2013, the Partnership entered into the Fifth Amended and Restated Credit Agreement whereby the aggregate commitment under thefacility increased from $600 million to $850 million (subject to availability under our borrowing base and a further potential increase of $100 million) andreduced the applicable margin for LIBOR loans to a range of 150 to 225 basis points above LIBOR, depending on the Partnership’s leverage ratio. Therevolving credit facility is secured by a first priority lien against the Partnership’s assets and matures on December 13, 2018, at which point all amountsoutstanding will become due. The Fifth Amended and Restated Credit Agreement permits us to make distributions of available cash to unitholders so long as (a) no default under thefacility has occurred, is continuing or would result from the distribution, (b) immediately prior to and after giving effect to such distribution, the Partnershipis in compliance with the facility’s financial covenants and (c) immediately after giving effect to such distribution, the Partnership has availability under therevolving credit facility of at least $20 million. In addition, the amended and restated credit agreement contains various covenants that may limit, among otherthings, the Partnership’s ability to(subject to exceptions): · grant liens; · make certain loans or investments; · incur additional indebtedness or guarantee other indebtedness; · enter into transactions with affiliates; · merge or consolidate; · sell the Partnership’s assets; or · make certain acquisitions. The Fifth Amended and Restated Credit Agreement also contains various financial covenants, including covenants requiring the Partnership to maintain: · a minimum EBITDA to interest coverage ratio of 2.5 to 1.0; and · a maximum funded debt to EBITDA ratio, determined as of the last day of each fiscal quarter, for the annualized trailing three months of (a) 5.50 to1.0, with respect to any fiscal quarter ending on or after December 13, 2013, the closing date of the amended credit facility, through June 30, 2015 or(b) 5.00 to 1.0, with respect to the fiscal quarter ending September 30, 2015 and each fiscal quarter thereafter, in each case subject to a provision forincreases to such thresholds by 0.5 in connection with certain future acquisitions for the six consecutive month period following the period in whichany such acquisition occurs. If a default exists under the revolving credit facility, the lenders will be able to accelerate the maturity on the amount then outstanding and exercise otherrights and remedies. The Partnership paid various loan fees and incurred costs in respect of the Fifth Amended and Restated Credit Agreement in the amount of $3.0 million in2013, which were capitalized to loan costs and will be amortized through December 2018. The Partnership wrote off $0.3 million in 2013 related to certainthird parties that exited the credit facility. As of December 31, 2013 and 2012, the Partnership was in compliance with all of its covenants under the current credit agreement. F-13 Table of Contents USA COMPRESSION PARTNERS, LP AND SUBSIDIARIESNotes to Consolidated Financial StatementsDecember 31, 2013, 2012 and 2011 At December 31, 2013, the Partnership had outstanding borrowings of $420.9 million and borrowing availability under the revolving credit facility of$264.6 million. The borrowing base consists of eligible accounts receivable, inventory and compression units. The largest component, representing 94% and96% of the borrowing base at December 31, 2013 and 2012, respectively, is eligible compression units—compressor packages that are leased, rented or underservice contracts to customers and carried in the financial statements as fixed assets. The Partnership’s effective interest rate in effect for all borrowings underits revolving credit facility at December 31, 2013 and 2012, was 2.17% and 2.96%, respectively, and an average interest rate of 2.43% and 2.99%, excludingthe effects from the interest rate swap instruments discussed below for 2012, for the year then ended, respectively. There were no letters of credit issued atDecember 31, 2013 and 2012. The senior debt facility expires in December 2018 and the Partnership expects to maintain this facility for the term. The facility is a ‘‘revolving creditfacility’’ that includes a ‘‘springing’’ lock box arrangement, whereby remittances from customers are forwarded to a bank account controlled by thePartnership, and the Partnership is not required to use such remittances to reduce borrowings under the facility, unless there is a default or excess availabilityunder the facility is reduced below $20 million. As the remittances do not automatically reduce the debt outstanding absent the occurrence of a default or areduction in excess availability below $20 million, the debt has been classified as long-term at December 31, 2013 and 2012. Maturities of long-term debt (in thousands): Year ending December 31,2014—2015—2016—2017—2018420,933Total Debt$420,933 (b) Hedging and Use of Derivative Instruments During 2012, the Partnership had only limited involvement with derivative financial instruments and used them principally to manage well-definedinterest rate risk. Interest rate swap agreements are used to reduce the potential impact of fluctuations in interest rates on variable rate long-term debt. Theswaps were not used for trading or speculative purposes. In November 2008, the Partnership entered into an interest rate swap agreement expiring October 5, 2012 for a notional amount of $75 million. InMay 2009, the Partnership entered into an interest rate swap agreement expiring June 1, 2012 for a notional amount of $35 million. In August 2009, thePartnership entered into an interest rate swap agreement expiring August 1, 2012 for a notional amount of $30 million. As of December 31, 2011, the Partnership did not designate these interest rate swaps as cash flow hedges. The swap agreements entitled the Partnership to pay or receive from the counter-party, monthly, the amount by which the counter-party’s variable rate(reset monthly) was less than or exceeded the Partnership’s fixed rate under the agreements with respect to the notional amount. Under the swaps, thePartnership received fixed rates of 3%, 1.9% and 2.055% on the notional amounts of $75 million, $35 million and $30 million, respectively, in exchange fora floating rate tied to the BBA London Interbank Offering Rate (“LIBOR”). The swaps minimized interest rate exposure on the revolving senior debt facility,and in effect, converted variable interest payments on the aggregate notional amount to fixed interest payments. Amounts paid or received from the interest rateswap were charged or credited to interest expense and matched with the cash flow and interest expense of the senior debt being hedged, resulting in anadjustment to the effective interest rate. The swap payments for the years ended December 31, 2012 and 2011 were $2.3 million and $3.3 million, respectively.During 2012 and 2011, interest expense was reduced by $2.2 million and $2.6 million, respectively, due to changes in the fair value of the interest rateswaps. F-14 Table of Contents USA COMPRESSION PARTNERS, LP AND SUBSIDIARIESNotes to Consolidated Financial StatementsDecember 31, 2013, 2012 and 2011 (6) Partner’s Capital As of February 18, 2014, USAC Compression Holdings held 5,337,977 common units and 14,048,588 subordinated units and USA CompressionGP, LLC held a 2% general partner interest and the incentive distribution rights (“IDRs”). See the condensed consolidated statement of changes in Partners’Capital. Subordinated Units All of the subordinated units are held by USA Compression Holdings. The partnership agreement provides that, during the subordination period, thecommon units have the right to receive distributions of Available Cash from Operating Surplus (each as defined in the Partnership’s agreement) each quarter inan amount equal to $0.425 per common unit (the “Minimum Quarterly Distribution”), plus any arrearages in the payment of the Minimum QuarterlyDistribution from Operating Surplus on the common units from prior quarters, before any distributions of Available Cash from Operating Surplus may bemade on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinatedunits will not be entitled to receive any distributions from Operating Surplus until the common units have received the Minimum Quarterly Distribution plusany arrearages from prior quarters. The practical effect of the subordinated units is to increase the likelihood that during the subordination period there will beAvailable Cash from Operating Surplus to be distributed on the common units. The subordination period will end on the first business day after thePartnership has earned and paid at least (i) $1.70 (the Minimum Quarterly Distribution on an annualized basis) on each outstanding unit and thecorresponding distribution on the General Partner’s 2.0% interest for each of three consecutive, non-overlapping four-quarter periods ending on or afterDecember 31, 2015 or (ii) $2.55 (150.0% of the annualized Minimum Quarterly Distribution) on each outstanding unit and the corresponding distributionson the General Partner’s 2.0% interest and the related distribution on the incentive distribution rights for the four-quarter period immediately preceding thatdate. When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units thereafter willno longer be entitled to arrearages. Incentive Distribution Rights The General Partner holds the IDRs. The following table illustrates the percentage allocations of available cash from operating surplus between theunitholders and the General Partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest inDistributions” are the percentage interests of the General Partner and the unitholders in any available cash from operating surplus the Partnership distributesup to and including the corresponding amount in the column “Total Quarterly Distribution per Unit.” The percentage interests shown for our unitholders andour general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterlydistribution. The percentage interests set forth below for the General Partner include its 2.0% general partner interest, assume the General Partner hascontributed any additional capital necessary to maintain its 2.0% general partner interest and has not transferred its incentive distribution rights and there areno arrearages on common units. Total Quarterly Marginal Percentage Interest in DistributionsDistributions per UnitUnitholdersGeneral PartnerMinimum Quarterly Distribution$0.42598%2%First Target Distributionup to $0.488898%2%Second Target Distributionabove $0.4888 up to$0.531385%15%Third Target Distributionabove $0.5313 up to$0.637575%25%Thereafterabove $0.637550%50% F-15 Table of Contents USA COMPRESSION PARTNERS, LP AND SUBSIDIARIESNotes to Consolidated Financial StatementsDecember 31, 2013, 2012 and 2011 Cash Distributions The Partnership has declared quarterly distributions per unit to unitholders of record, including holders of common and subordinated units and the 2%general partner interest held by the General Partner as follows (in millions, except distribution per unit): Distribution perAmount Paid toAmount Paid toAmount Paid toLimited PartnerCommonSubordinatedGeneralTotalPayment DateUnitUnitholdersUnitholderPartnerDistributionMay 15, 2013$0.348(1)$5.2$4.9$0.2$10.3August 14, 20130.446.76.20.313.2November 14, 20130.4610.66.50.317.4 (1) Prorated to reflect 72 days of quarterly cash distribution rate of $0.435 per unit. The Partnership’s partnership agreement requires that, within 45 days after the end of each quarter, the Partnership distribute all of its available cash (asdefined in the partnership agreement) to the partners of record on the applicable record date. Certain limited partners, including USA Compression Holdings,and Argonaut Private Equity and certain related parties, have elected to receive distributions in the form of additional common units in accordance with thePartnership’s DRIP. Such distributions, which are treated as non-cash transactions in the accompanying statements of cash flows, totaled $6.3 million, $8.1million and $11.9 million for the first, second and third quarter of 2013, respectively. On January 23, 2014, the Partnership announced a cash distribution of $0.48 per unit on its common units and subordinated units. The distribution waspaid on February 14, 2014 to unitholders of record as of the close of business on February 4, 2014. USA Compression Holdings, the owner of 50.6% of thePartnership’s outstanding limited partner interests, and Argonaut Private Equity and certain related parties, the owners of 19.3% of the Partnership’soutstanding limited partner interests, elected to reinvest all of this distribution with respect to their units pursuant to the Partnership’s DRIP. Following theissuance of common units under the DRIP, USAC Compression Holdings owned 50.9% of the Partnership’s outstanding limited partner interests, andArgonaut Private Equity and the related parties participating in the DRIP, owned 19.4% of the Partnership’s outstanding limited partner interests. F-16 Table of Contents USA COMPRESSION PARTNERS, LP AND SUBSIDIARIESNotes to Consolidated Financial StatementsDecember 31, 2013, 2012 and 2011 Earnings Per Common and Subordinated Unit The computations of earnings per common unit and subordinated unit are based on the weighted average number of common units and subordinatedunits, respectively, outstanding during the applicable period. The Partnership’s subordinated units meet the definition of a participating security; therefore, thePartnership is required to use the two-class method in the computation of earnings per unit. Basic earnings per common unit and subordinated unit aredetermined by dividing net income allocated to the common units and subordinated units, respectively, after deducting the amount allocated to thePartnership’s general partner (including distributions to the general partner on its IDRs), by the weighted average number of outstanding common units andsubordinated units, respectively, during the period. Pursuant to the partnership agreement, to the extent that the quarterly distributions exceed certain targets, the General Partner is entitled to receive certainincentive distributions that will result in more earnings proportionately being allocated to the General Partner than to the holders of common units andsubordinated units. The Partnership’s earnings per unit calculations, which allocate 2% of earnings to the General Partner, assume that, while suchdistribution to the General Partner with respect to its 2% general partner interest was made, no incentive distributions were permitted to be, or were, made to theGeneral Partner because quarterly distributions declared by the board of directors for the fourth quarter of 2013 did not exceed the specified targets. (7) Unit-Based Compensation Class B Units During 2011 and 2013, USA Compression Holdings, LLC issued to certain employees and members of its management, who provide services to thePartnership, Class B nonvoting units. These Class B units are liability-classified profits interest awards which have a service condition. The holders of Class B units in USA Compression Holdings, LLC are entitled to a cash payment of 10% of net proceeds primarily from a monetizationevent, as defined under the provisions of the Amended and Restated Limited Liability Company Agreement of USA Compression Holdings, or the HoldingsOperating Agreement, related to these Class B unit awards, in excess of USA Compression Holdings, LLC’s Class A unitholder’s capital contributions andan 8% cumulative annual dividend (both of which are due upon a monetization event) to the extent of vested units over total units of the respective class. Eachholder of Class B units is then allocated their pro-rata share of the respective class of unit’s entitlement based on the number of units held over the total numberof units in that class of units. The Class B units vest 25% on the first anniversary date of the grant date and then monthly for the next three years (at the rateof 1/48 per month) subject to certain continued employment. Half of the remaining vesting was achieved in connection with the Partnership’s IPO. The unitshave no expiry date provided the employee remains employed with USA Compression Holdings, LLC or one of its subsidiaries. The Class B units vesting schedule consisted of the following at December 31 (in thousands, except unit amounts): Class B Interest UnitsGrant date fair value per unitVestedUnvestedUnit-based compensation expenseBalance of awards as of December 31, 2010—1,000,000Issuance of profit interest units$——187,500Vesting250,000(250,000)Forfeitures——Balance of awards as of December 31, 2011250,000937,500Expense recorded in 2011$—Issuance of profit interest units$———Vesting320,313(320,313)Forfeitures——Balance of awards as of December 31, 2012570,313617,187Expense recorded in 2012$—Issuance of profit interest units$——187,500Vesting531,250(531,250)Forfeitures(62,500)(62,500)Balance of awards as of December 31, 20131,039,063210,937Expense recorded in 2013$— F-17 Table of Contents USA COMPRESSION PARTNERS, LP AND SUBSIDIARIESNotes to Consolidated Financial StatementsDecember 31, 2013, 2012 and 2011 Fair value of the Class B units is based on enterprise value calculated by a predetermined formula. As of December 31, 2013, there was no unit-basedcompensation expense or liability that has been recorded related to these Class B units. The Partnership’s IPO constituted a qualified public offering for purposes of certain vesting provisions of the employee holder’s Class B Units, whichresulted in 50% of certain employee’s unvested Class B Units vesting. Any remaining unvested Class B Units generally (i) vest 25% percent on the firstanniversary dated of the grant date and (ii) with respect to the remaining Class B Units, will vest monthly for the next three years (at the rate of 1/48 permonth) subject to the employee’s continued employment on each applicable vesting date. If any employee holder’s employment is terminated by thePartnership’s general partner without cause or the employee resigns for good reason, the remaining unvested Class B Units will vest in full. As used in theHoldings Operating Agreement, “good reason” and “cause” have the meanings set forth in each employee’s employment agreement. Long-Term Incentive Plan In connection with the Partnership’s IPO, the Board adopted the USA Compression Partners, LP 2013 Long-Term Incentive Plan (“LTIP”) for employees,consultants and directors of the General Partner and any of its affiliates who perform services for the Partnership. The LTIP consists of unit options, unitappreciation rights, restricted units, phantom units, distribution equivalent rights, unit awards, profits interest units and other unit-based awards. The LTIPinitially limits the number of common units that may be delivered pursuant to awards under the plan to 1,410,000 common units. Awards that are forfeited,cancelled, paid or otherwise terminate or expire without the actual delivery of units will be available for delivery pursuant to other awards. The LTIP isadministered by the Board or a committee thereof. During the year ended December 31, 2013, an aggregate of 269,521 phantom units (including the corresponding distribution equivalent rights) weregranted under the LTIP to the General Partner’s executive officers and employees and independent directors. The phantom units (including the correspondingdistribution equivalent rights) awarded are subject to restrictions on transferability, customary forfeiture provisions and time vesting provisions generally inwhich, for employees, one-third of each award vests on the first, second, and third anniversaries of the date of grant. Grants of phantom units to theindependent directors of the General Partner generally vest in full on the one year anniversary of the grant date. Award recipients do not have all the rights of aunitholder in the partnership with respect to the phantom units until the units have vested. The fair value of the phantom units awarded to the General Partner’s executive officers, employees and independent directors was $4.7 million, based onthe market price per unit on the date of grant, less any forfeitures. This amount will be recognized as compensation cost on a straight-line basis over therequisite service period. The General Partner’s executive officers, employees and independent directors were granted these awards to incentivize them to helpdrive the Partnership’s future success and to share in the economic benefits of that success. The compensation costs associated with these awards are recordedas direct general and administrative expenses. During the year ended December 31, 2013, the Partnership recognized $1.3 million of compensation expenseassociated with these awards, net of expense related to forfeited units. F-18 Table of Contents USA COMPRESSION PARTNERS, LP AND SUBSIDIARIESNotes to Consolidated Financial StatementsDecember 31, 2013, 2012 and 2011 The following table summarizes information regarding phantom unit awards for the periods presented: Number of UnitsWeighted-Average Grant Date Fair Value per Unit(1)Phantom units outstanding at December 31, 2012—$—Granted269,52119.96Vested3,81619.65Forfeited35,71419.60Phantom units outstanding at December 31, 2013229,991$20.02 (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. The unrecognized compensation cost associated with phantom unit awards was an aggregate $3.3 million at December 31, 2013. We expect to recognize theunrecognized compensation cost for these awards on a weighted-average basis over a period of 2.1 years. Each phantom unit granted is granted in tandem with a corresponding distribution equivalent right (“DER”), which shall remain outstanding and unpaidfrom the grant date until the earlier of the payment or forfeiture of the related phantom units. Each vested DER shall entitle the participant to receive paymentsin the amount equal to any distributions made by the Partnership following the grant date in respect of the common unit underlying the phantom unit to whichsuch DER relates. (8) Transactions with Related Parties For the year ended December 31, 2013, the Partnership incurred $49,315 of expenses related to management fees under an agreement between USACompression Holdings, LLC and certain of its affiliates, for services provided to the Partnership for the period from January 1, 2013 through January 17,2013. For the years ended December 31, 2012 and 2011, the Partnership incurred $1.0 million of management fees under such agreement. After the completionof the Partnership’s initial public offering on January 18, 2013, the Partnership and its subsidiaries are no longer required to pay this management fee. William Shea, Jr., who has served as a director of USA Compression GP, LLC since June 2011, is currently a director and the chief executive officer ofthe general partner of PVR Partners, L.P. (“PVR”). For the years ended December 31, 2013, 2012 and 2011, subsidiaries of PVR made compression servicespayments of approximately $3.0 million, $2.2 million and $1.3 million, respectively. The Partnership provides compression services to affiliated entities controlled by Riverstone, who owns a majority of the membership interest in USACompression Holdings. As of February 18, 2013, USA Compression Holdings owned and controlled the Partnership’s general partner and owned 50.9% ofour limited partner interests. For the years ended December 31, 2013, 2012 and 2011, affiliated entities made compression services payments to thePartnership of approximately $0.5 million, $0.8 million and $40,613, respectively. The Partnership may provide compression services to additional entitiescontrolled by Riverstone in the future, and any significant transactions will be disclosed. (9) Commitments and Contingencies (a) Operating Leases Rent expense for office space, warehouse facilities and certain corporate equipment for the years ended December 31, 2013, 2012 and 2011 was $1.6million, $1.1 million and $0.8 million, respectively. Commitments for future minimum lease payments for non-cancelable leases are as follows (inthousands): 2014$1,0832015959201685220177852018632Thereafter611$4,922 F-19 Table of Contents USA COMPRESSION PARTNERS, LP AND SUBSIDIARIESNotes to Consolidated Financial StatementsDecember 31, 2013, 2012 and 2011 (b) Operating Lease Facility On August 4, 2009, the Partnership entered into an operating lease facility with Caterpillar Financial Services Corporation (“CFSC”), whereby thePartnership had the ability to lease compression equipment with an aggregate value of up to $45 million. The Partnership paid commitment and arrangementfees of $0.2 million. As part of the facility, the Partnership would pay 150 basis points, amended December 23, 2010 to 220 basis points, on the value of theequipment for each lease as funded. The facility was available for leases with inception dates up to and including June 30, 2011, subject to renewals at thediscretion of CFSC, and mitigated the need to use available capacity under the existing senior debt facility. Each compressor leased under this facility had alease term of one hundred twenty (120) months with a buyout option of 25% of cost which approximated fair value at the end of the lease term. At the end ofthe lease term, the Partnership also had an option to extend the lease term for an additional period of sixty (60) months at an adjusted rate equal to the fairmarket rate at the time. In the event the Partnership elected not to exercise the buyout or renewal option, the equipment was to be returned in a manner fit for useat the end of the lease term. In addition to the fair value buyout option at the end of the lease term, early buyout option provisions existed at month sixty (60)and at month eighty four (84) of the one hundred twenty (120) month lease term. On December 15, 2011, the Partnership purchased all the compression units previously leased from CFSC for $43 million and terminated all the leaseschedules and covenants under the facility. This purchase was funded by additional borrowings under the revolving credit facility. Lease expense under theterms of the facility for the year ended December 31, 2011 was $4.1 million. There are no commitments for future minimum lease payments as the leaseschedules have been terminated. (c) Major Customers The Partnership had revenue from one customer representing 14.3%, 14.5% and 15.9% of total revenue for the years ended December 31, 2013, 2012 and2011, respectively. (d) Litigation The Partnership may be involved in various claims and litigation arising in the ordinary course of business. In management’s opinion, the resolution ofsuch matters is not expected to have a material adverse effect on the Partnership’s consolidated financial position, results of operations or cash flows. (10) Selected Quarterly Financial Data (Unaudited) In the opinion of the Partnership’s management, the summarized quarterly financial data below (in thousands, except per unit amounts) contains allappropriate adjustments, all of which are normally recurring adjustments, considered necessary to present fairly the Partnership’s financial position and theresults of operations for the respective periods. March 31, 2013June 30, 2013September 30, 2013 (2)December 31, 2013Revenue$32,604$33,310$38,362$48,642Gross profit (1)22,18423,17926,44033,018Net income2,5212,4011,7124,437Income per common and subordinated unit — basic$0.07$0.08$0.05$0.12Income per common unit — diluted0.070.080.050.12 F-20 Table of Contents USA COMPRESSION PARTNERS, LP AND SUBSIDIARIESNotes to Consolidated Financial StatementsDecember 31, 2013, 2012 and 2011 March 31, 2012June 30, 2012September 30, 2012December 31, 2012Revenue$27,124$28,870$31,021$31,771Gross profit18,10319,74821,23721,903Net income1,2439971,316948Net income allocated to general partner12101310Net income available for limited partners1,2319871,303938 (1) Gross profit is defined as revenue less cost of operations, exclusive of depreciation and amortization expense.(2) During the third quarter of 2013, we completed the S&R Acquisition (see Note 3). (11) Subsequent Events (a) Shelf Registration On February 3, 2014, the Partnership filed a Registration Statement on Form S-3, (Reg. No. 333-193724) (the “Shelf Registration Statement”). Under theShelf Registration Statement, the Partnership registered the offer and sale of up to $1,000,000,000 aggregate principal amount of Partnership securitiesincluding, common units and other classes of units representing limited partner interests in the Partnership, debt securities and guarantees of debt securities. Inaddition, the Partnership registered up to 33,336,784 common units that may be sold from time to time by certain selling unitholders. The Partnership will usethe net proceeds from any primary offering of securities consummated under the Shelf Registration Statement for general partnership purposes, includingrepayment of debt, acquisitions, capital expenditures and additions to working capital. The actual application of proceeds the Partnership receives from anyparticular primary offering of securities will be set forth in the applicable prospectus supplement to the prospectus included in the Shelf RegistrationStatement. The Partnership will not receive any of the proceeds from a sale of common units by the selling unitholders. (b) Phantom Units On February 4, 2014, an aggregate of 9,087 phantom units (including the corresponding distribution equivalent rights) were granted under the LTIP to theindependent directors of our general partner. The phantom units (including the corresponding distribution equivalent rights) awarded are subject to restrictionson transferability, customary forfeiture provisions and will vest in full on February 15, 2015. F-21 Exhibit 10.10 USA COMPRESSION PARTNERS, LP2013 LONG-TERM INCENTIVE PLAN FORM OFEMPLOYEE PHANTOM UNIT AGREEMENT Pursuant to this Phantom Unit Agreement, dated as of Grant Date identified in the Grant Notice below (this “Agreement”), USA Compression GP,LLC (the “Company”), as the general partner of USA Compression Partners, LP (the “Partnership”), hereby grants to [ ] (the “Participant”)the following award of Phantom Units (“Phantom Units”), pursuant and subject to the terms and conditions of this Agreement and the USA CompressionPartners, LP 2013 Long-Term Incentive Plan (the “Plan”), the terms and conditions of which are hereby incorporated into this Agreement by reference. EachPhantom Unit shall constitute a Phantom Unit under the terms of the Plan and is hereby granted in tandem with a corresponding distribution equivalent right (“DER”), as further detailed in Section 3 below. Except as otherwise expressly provided herein, all capitalized terms used in this Agreement, but not defined,shall have the meanings provided in the Plan. GRANT NOTICE Subject to the terms and conditions of this Agreement, the principal features of this Award are as follows: Number of Phantom Units: [ ] Phantom Units Grant Date: [ ] Vesting of Phantom Units: Phantom Units shall vest in three equal annual installments, with the first installment vesting on [ ] and theother two installments on the next two succeeding anniversaries thereof, subject in each case to the Participant continuing in Service through theapplicable vesting date; provided that the Phantom Units shall be subject to accelerated vesting in certain circumstances as set forth in Section 4(b). Forfeiture of Phantom Units: In the event of a cessation (not including any approved leave of absence) of the Participant’s Service for any reason,all Phantom Units that have not vested prior to or in connection with such cessation of Service shall thereupon automatically be forfeited by theParticipant without further action and without payment of consideration therefor. Payment of Phantom Units: Vested Phantom Units shall be paid to the Participant as set forth in Section 5 below. DERs: Each Phantom Unit granted under this Agreement shall be issued in tandem with a corresponding DER, which shall entitle the Participant toreceive payments in an amount equal to the Partnership distributions in accordance with Section 3 below. TERMS AND CONDITIONS OF PHANTOM UNITS 1. Grant. The Company hereby grants to the Participant, as of the Grant Date, an award of Phantom Units in the amount set forth in theGrant Notice above, subject to all of the terms and conditions contained in this Agreement and the Plan. 2. Phantom Units. Subject to Section 4 below, each Phantom Unit that vests shall represent the right to receive payment, in accordance withSection 5 below, in the form of one (1) Unit. Unless and until a Phantom Unit vests, the Participant will have no right to payment in respect of suchPhantom Unit. Prior to actual payment in respect of any vested Phantom Unit, such Phantom Unit will represent an unsecured obligation of the Partnership,payable (if at all) only from the general assets of the Partnership. 3. Grant of Tandem DER. Each Phantom Unit granted hereunder is hereby granted in tandem with a corresponding DER, which shall remainoutstanding from the Grant Date until the earlier of the payment or forfeiture of the related Phantom Unit. Each DER shall entitle the Participant to receivepayments, subject to and in accordance with this Agreement, in an amount equal to any distributions made by the Partnership following the Grant Date andwhile the DER is outstanding in respect of the Unit underlying the Phantom Unit to which such DER relates. The Company shall make each such paymentto the Participant in cash as soon as reasonably practicable, but not later than forty-five days after each such distribution is paid by the Partnership. 4. Vesting and Forfeiture. (a) Vesting. Subject to Section 4(c) below, the Phantom Units shall vest in such amounts and at such times as are set forth in theGrant Notice above. (b) Accelerated Vesting. Subject to Section 4(c) below, if a Change in Control occurs after the Grant Date and following suchoccurrence, the Participant incurs a termination of Service due to the Participant’s termination by the Company or one of its Affiliates without Causeor the Participant’s resignation for Good Reason, then 100% of the then-unvested Phantom Units shall vest in full as of immediately prior to suchtermination . For purposes of this Agreement, the following definitions shall apply: (i) “Cause” shall have the meaning set forth in a written employment or other similar agreement between the Participant onone hand and the Partnership, the Company or any of their Affiliates on the other hand. In the event the Participant is not a party to a writtenagreement containing a definition of “Cause” or similar term, “Cause” (solely for purposes of this Agreement and not for the purpose ofestablishing any standard of termination for employment) shall mean a finding by the Committee, before or after the Participant’s termination ofService, of: (i) any material failure by the Participant to perform the Participant’s duties and responsibilities as an Employee; (ii) any significant actof fraud, embezzlement, theft or misappropriation by the Participant relating to the Company, the Partnership or any of their Affiliates that isdemonstrably and significantly injurious to the Partnership or any of its Affiliates; (iii) the Participant’s conviction of a felony or a crime involvingmoral turpitude; (iv) any gross negligence or (1) Acceleration for the President and Chief Executive Officer will occur immediately upon a Change in Control. 2(1) intentional misconduct on the part of the Participant in the conduct of the Participant’s duties and responsibilities with the Company, the Partnershipor any of their Affiliates that is demonstrably and significantly injurious to the Partnership or any of its Affiliates; or (v) any material breach by theParticipant of any agreement between the Company, the Partnership or any of their Affiliates, on the one hand, and the Participant on the other;provided, that with respect to items (i), (iv) and (v), the Participant shall have not been able to remedy such deficiencies within 15 days of receivingwritten notice thereof from the Company (as long as any such types of deficiencies have not previously been noticed in writing to Participant in theimmediately preceding six months). The findings and decision of the Committee with respect to such matter, including those regarding the acts ofthe Participant and the impact thereof, will be final for all purposes. (ii) “Good Reason” shall have the meaning set forth in a written employment or other similar agreement between theParticipant on one hand and the Partnership, the Company or any of their Affiliates on the other hand, provided that in no event shall any event oroccurrence constitute Good Reason for purposes of this Agreement unless such event or occurrence constitutes a “material negative change” (withinthe meaning of Treasury Regulation 1.409A-1(n)(2)) to the Participant in his or her service relationship with the Company, the Partnership and itsAffiliates. In the event the Participant is not a party to a written agreement containing a definition of “Good Reason” or similar term, “GoodReason” (solely for purposes of this Agreement and not for the purpose of establishing any standard of termination for employment) shall mean theoccurrence of one or more of the following actions without the Participant’s consent: (1) a material reduction in the duties and responsibilities held bythe Participant, except in connection with a termination of the Participant’s Service for Cause; (2) a material reduction in the Participant’s basesalary, other than a reduction that is generally applicable to all similarly situated employees of the Company; or (3) a material change (i.e., more than50 miles) in the geographic location at which the Participant must perform services for the Company, the Partnership or its Affiliates; provided,however, that no termination of Service by the Participant shall constitute a termination for Good Reason unless (a) the Participant has first providedthe Company, the Partnership or its applicable Affiliate with written notice specifically identifying the acts or omissions constituting the grounds forGood Reason within thirty (30) days after the Participant has or should reasonably be expected to have had knowledge of the occurrence thereof,(b) the Company, the Partnership or its Affiliate, as applicable, has not cured such acts or omissions within thirty (30) days of its actual receipt ofsuch notice, and (c) the effective date of the Participant’s termination for Good Reason occurs no later than ninety (90) days after the initial existenceof the facts or circumstances constituting Good Reason. (c) Forfeiture. Notwithstanding the foregoing, in the event of a cessation (not including any approved leave of absence) of theParticipant’s Service for any reason, all Phantom Units that have not vested prior to or in connection with such cessation of Service shall thereuponautomatically be forfeited by the Participant without further action and without payment of consideration therefor. No portion of the Phantom Unitswhich has not become vested at the date of the Participant’s cessation (not including any approved leave of absence) of Service shall thereafter becomevested. 3 (d) Payment. Vested Phantom Units shall be subject to the payment provisions set forth in Section 5 below. 5. Payment of Phantom Units and DERs. (a) Phantom Units. Unpaid, vested Phantom Units shall be paid to the Participant in the form of Units in a lump-sum as soon asreasonably practical, but not later than forty-five (45) days, following the date on which such Phantom Units vest. Payments of any Phantom Unitsthat vest in accordance herewith shall be made to the Participant (or in the event of the Participant’s death, to the Participant’s estate) in whole Unitsin accordance with this Section 5. In lieu of the foregoing, the Committee may elect in its discretion to pay the Phantom Units in cash equal to theFair Market Value of the Units that would otherwise be distributed as of the date of vesting. (b) DERs. DERs shall be paid to the Participant as provided above in Section 3. (c) Potential Delay. Notwithstanding anything to the contrary in this Agreement, no amounts payable under this Agreement shall bepaid to the Participant prior to the expiration of the six (6)-month period following his “separation from service” (within the meaning of TreasuryRegulation Section 1.409A-1(h)) (a “Separation from Service”) to the extent that the Company determines that paying such amounts prior to theexpiration of such six (6)-month period would result in a prohibited distribution under Section 409A(a)(2)(B)(i) of the Code. If the payment of anysuch amounts is delayed as a result of the previous sentence, then on the first business day following the end of the applicable six (6)-month period(or such earlier date upon which such amounts can be paid under Section 409A of the Code without resulting in a prohibited distribution, includingas a result of the Participant’s death), such amounts shall be paid to the Participant. 6. Tax Withholding. The Company and/or its Affiliates shall have the authority and the right to deduct or withhold, or to require theParticipant to remit to the Company and/or its Affiliates, an amount sufficient to satisfy all applicable federal, state and local taxes (including theParticipant’s employment tax obligations) required by law to be withheld with respect to any taxable event arising in connection with the Phantom Units andthe DERs. In satisfaction of the foregoing requirement the Company and/or its Affiliates shall withhold, solely at the election of the Participant, (a) Unitsotherwise issuable in respect of such Phantom Units having a Fair Market Value equal to the sums required to be withheld, (b) cash, or (c) a combination ofcash and Units otherwise issuable in respect of such Phantom Units. In the event that Units that would otherwise be issued in payment of the PhantomUnits are used to satisfy all or part of such withholding obligations, the number of Units which shall be so withheld shall be limited to the number of Unitswhich have a Fair Market Value (which, in the case of a broker-assisted transaction (if a broker assisted transaction is permitted by the Participant), shall bedetermined by the Committee, consistent with applicable provisions of the Code) on the date of withholding equal to the aggregate amount of such liabilitiesbased on the minimum statutory withholding rates for federal, state, local and foreign income tax and payroll tax purposes that are applicable to suchsupplemental taxable income, less any cash withheld. 4 7. Rights as Unit Holder. Neither the Participant nor any person claiming under or through the Participant shall have any of the rights orprivileges of a holder of Units in respect of any Units that may become deliverable hereunder unless and until certificates representing such Units shall havebeen issued or recorded in book entry form on the records of the Partnership or its transfer agents or registrars, and delivered in certificate or book entry formto the Participant or any person claiming under or through the Participant. 8. Non-Transferability. Except as set forth in the next sentence, neither the Phantom Units nor any right of the Participant under the PhantomUnits may be assigned, alienated, pledged, attached, sold or otherwise transferred or encumbered by the Participant (or any permitted transferee) other thanby will or the laws of descent and distribution and any such purported assignment, alienation, pledge, attachment, sale, transfer or encumbrance shall bevoid and unenforceable against the Company, the Partnership and any of their Affiliates. Notwithstanding the foregoing, (i) the Phantom Units or any rightof the Participant under the Phantom Units may be transferred by a Participant without consideration to any “family member” of the Participant, as definedin the instructions to use of the Form S-8 Registration Statement under the Securities Act, as applicable, or any other transferee specifically approved by theCommittee after taking into account any state, federal, local or foreign tax and securities laws applicable to transferable Awards; and (ii) vested Units may betransferred to the extent permitted by the Partnership Agreement and not otherwise prohibited by this Agreement or any other agreement restricting the transferof such Units. 9. Distribution of Units. Unless otherwise determined by the Committee or required by any applicable law, rule or regulation, neither theCompany nor the Partnership shall deliver to the Participant certificates evidencing Units issued pursuant to this Agreement and instead such Units shall berecorded in the books of the Partnership (or, as applicable, its transfer agent or equity plan administrator). All certificates for Units issued pursuant to thisAgreement and all Units issued pursuant to book entry procedures hereunder shall be subject to such stop transfer orders and other restrictions as theCompany may deem advisable under the Plan or the rules, regulations, and other requirements of the Securities Exchange Commission, any stock exchangeupon which such Units are then listed, and any applicable federal or state laws, and the Company may cause a legend or legends to be inscribed on any suchcertificates or book entry to make appropriate reference to such restrictions. In addition to the terms and conditions provided herein, the Company mayrequire that the Participant make such covenants, agreements, and representations as the Company, in its sole discretion, deems advisable in order to complywith any such laws, regulations, or requirements. No fractional Units shall be issued or delivered pursuant to the Phantom Units and the Committee shalldetermine the amount of cash, other securities, or other property that shall be paid or transferred in lieu of fractional Units. 5 10. Partnership Agreement. Units issued upon payment of the Phantom Units shall be subject to the terms of the Plan and the PartnershipAgreement. Upon the issuance of Units to the Participant, the Participant shall, automatically and without further action on his or her part, (i) be admitted tothe Partnership as a Limited Partner (as defined in the Partnership Agreement) with respect to the Units, and (ii) become bound, and be deemed to have agreedto be bound, by the terms of the Partnership Agreement. 11. No Effect on Service. Nothing in this Agreement or in the Plan shall be construed as giving the Participant the right to be retained in theemploy or service of the Company or any Affiliate thereof or establish standards regarding the termination from employment of the Participant. Furthermore,the Company and its Affiliates may at any time dismiss the Participant from employment or consulting free from any liability or any claim under the Plan orthis Agreement, unless otherwise expressly provided in the Plan, this Agreement or any other written agreement between the Participant and the Company oran Affiliate thereof. 12. Non-Solicitation of Customers and Employees. (a) During the period beginning on the Grant Date and for a period of 12 months following the termination of the Participant’s Service(the “Restricted Period”) for any reason, the Participant agrees to not, directly or indirectly, recruit or otherwise solicit or induce any employee, customer,subscriber or supplier of the Company to terminate its employment or arrangement with the Company, to engage in business with the Participant (or any futureemployer, affiliate or service recipient of the Participant) or to otherwise change its relationship with the Company, the Partnership or any of their Affiliates. Further, during the Restricted Period, the Participant agrees not to, directly or indirectly, hire or attempt to hire, or assist another person, firm, corporation,partnership or business in hiring or attempting to hire any employee (or former employee for six months after termination of employment) of the Company. (b) It is recognized and acknowledged by the Participant that a breach of the covenants contained in this Section 12 will causeirreparable damage to the Company, the Partnership and their Affiliates and their goodwill, the exact amount of which will be difficult or impossible toascertain, and that the remedies at law for any such breach will be inadequate. Accordingly, the Participant agrees that in the event of a breach of any of thecovenants contained in this Section 12, in addition to any other remedy which may be available at law or in equity, the Company, the Partnership and theirAffiliates will be entitled to specific performance and injunctive relief without having to prove damages. In the event any term of this Section 12 shall bedetermined by any court of competent jurisdiction to be unenforceable by reason of its extending for too great a period of time or over too great a geographicalarea or by reason of its being too extensive in any other respect, it will be interpreted to extend only over the maximum period of time for which it may beenforceable, over the maximum geographical area as to which it may be enforceable, or to the maximum extent in all other respects as to which it may beenforceable, all as determined by such court in such action. 13. Non-Disparagement. The Participant agrees to refrain from making any oral or written statements to a third party about the Company, thePartnership, or any of their Affiliates that are slanderous, libelous or defamatory with the effect of damaging the business or reputation of the Company, thePartnership, or any of their Affiliates. If the Participant violates 6 the terms of this Section 13, the violation shall be deemed an Act of Misconduct under the Plan and the Phantom Units, DERs, and Units issuablehereunder, whether vested or unvested and whether or not previously issued, shall be subject to the clawback described in Section 8(o) of the Plan only to theextent that the violation resulted in actual demonstrable harm to the Company, the Partnership, or any of their Affiliates. 14. Severability. If any provision of this Agreement is or becomes or is deemed to be invalid, illegal, or unenforceable in any jurisdiction, suchprovision shall be construed or deemed amended to conform to the applicable law or, if it cannot be construed or deemed amended without, in thedetermination of the Committee, materially altering the intent of this Agreement, such provision shall be stricken as to such jurisdiction, and the remainder ofthis Agreement shall remain in full force and effect. 15. Tax Consultation. None of the Board, the Committee, the Company or the Partnership has made any warranty or representation toParticipant with respect to the income tax consequences of the issuance of the Phantom Units, the DERs, the Units or the transactions contemplated by thisAgreement, and the Participant represents that he or she is in no manner relying on such entities or their representatives for tax advice or an assessment ofsuch tax consequences. The Participant understands that the Participant may suffer adverse tax consequences in connection with the Phantom Units andDERs granted pursuant to this Agreement. The Participant represents that the Participant has consulted with any tax consultants that the Participant deemsadvisable in connection with the Phantom Units and DERs. 16. Amendments, Suspension and Termination. Solely to the extent permitted by the Plan, this Agreement may be wholly or partially amendedor otherwise modified, suspended or terminated at any time or from time to time by the Board or the Committee. Except as provided in the precedingsentence, this Agreement cannot be modified, altered or amended, except by an agreement, in writing, signed by both the Partnership and the Participant. 17. Lock-Up Agreement. The Participant shall agree, if so requested of all executive management personnel by the Company or the Partnershipand any underwriter in connection with any public offering of securities of the Partnership or any Affiliate thereof, not to directly or indirectly offer, sell,contract to sell, sell any option or contract to purchase, purchase any option or contract to sell, grant any option, right or warrant for the sale of or otherwisedispose of or transfer any Units held by him or her for such period, not to exceed one hundred eighty (180) days following the effective date of the relevantregistration statement filed under the Securities Act in connection with such public offering, as such underwriter shall specify reasonably and in good faith. The Company or the Partnership may impose stop-transfer instructions with respect to securities subject to the foregoing restrictions until the end of such180-day period. Notwithstanding the foregoing, the 180-day period may be extended for up to such number of additional days as is deemed necessary bysuch underwriter or the Company or Partnership to continue coverage by research analysts in accordance with FINRA Rule 2711 or any successor rule. 7 18. Conformity to Securities Laws. The Participant acknowledges that the Plan and this Agreement are intended to conform to the extentnecessary with all provisions of the Securities Act and the Exchange Act, any and all regulations and rules promulgated by the Securities and ExchangeCommission thereunder, and all applicable state securities laws and regulations. Notwithstanding anything herein to the contrary, the Plan shall beadministered, and the Phantom Units and DERs are granted, only in such a manner as to conform to such laws, rules and regulations. To the extentpermitted by applicable law, the Plan and this Agreement shall be deemed amended to the extent necessary to conform to such laws, rules and regulations. 19. Code Section 409A. None of the Phantom Units, the DERs or any amounts paid pursuant to this Agreement are intended to constitute orprovide for a deferral of compensation that is subject to Section 409A of the Code. Nevertheless, to the extent that the Committee determines that the PhantomUnits or DERs may not be exempt from (or compliant with) Section 409A of the Code, the Committee may (but shall not be required to) amend thisAgreement in a manner intended to comply with the requirements of Section 409A of the Code or an exemption therefrom (including amendments withretroactive effect), or take any other actions as it deems necessary or appropriate to (a) exempt the Phantom Units or DERs from Section 409A of the Codeand/or preserve the intended tax treatment of the benefits provided with respect to the Phantom Units or DERs, or (b) comply with the requirements ofSection 409A of the Code. To the extent applicable, this Agreement shall be interpreted in accordance with the provisions of Section 409A of the Code. Notwithstanding anything in this Agreement to the contrary, to the extent that any payment or benefit hereunder constitutes non-exempt “nonqualified deferredcompensation” for purposes of Section 409A of the Code, and such payment or benefit would otherwise be payable or distributable hereunder by reason ofthe Participant’s cessation of Service, all references to the Participant’s cessation of Service shall be construed to mean a Separation from Service, and theParticipant shall not be considered to have a cessation of Service unless such cessation constitutes a Separation from Service with respect to the Participant. 20. Adjustments; Clawback. The Participant acknowledges that the Phantom Units are subject to modification and forfeiture in certain eventsas provided in this Agreement and Section 7 of the Plan. The Participant further acknowledges that the Phantom Units, DERs and Units issuable hereunder,whether vested or unvested and whether or not previously issued, are subject to clawback as provided in Section 8(o) of the Plan. 21. Successors and Assigns. This Agreement shall inure to the benefit of the successors and assigns of the Company and the Partnership. Subject to the restrictions on transfer contained herein, this Agreement shall be binding upon the Participant and his or her heirs, executors, administrators,successors and assigns. 22. Governing Law. The validity, construction, and effect of this Agreement and any rules and regulations relating to this Agreement shall bedetermined in accordance with the laws of the State of Delaware without regard to its conflicts of laws principles. 23. Headings. Headings are given to the sections and subsections of this Agreement solely as a convenience to facilitate reference. Suchheadings shall not be deemed in any way material or relevant to the construction or interpretation of this Agreement or any provision hereof. 8 24. Forfeiture. The Award granted under this Agreement shall automatically be deemed forfeited by the Participant on [ ] unlessprior to such date the Participant shall have (i) executed and delivered to the Partnership this Agreement and (except for Participants who already have enteredinto (a) a written employment agreement with the Partnership, one of its subsidiaries or USA Compression Management Services, LLC or (b) aNondisclosure and Assignment of Inventions Agreement in form satisfactory to the Partnership (a “Form NDA and Assignment”)) (ii) of an NDA andAssignment in favor of the Partnership. [Signature page follows] 9 The Participant’s signature below indicates the Participant’s agreement with and understanding that this award is subject to all of the terms andconditions contained in the Plan and in this Agreement, and that, in the event that there are any inconsistencies between the terms of the Plan and the terms ofthis Agreement, the terms of this Agreement shall control. The Participant further acknowledges that the Participant has read and understands the Plan andthis Agreement, which contains the specific terms and conditions of this grant of Phantom Units. The Participant hereby agrees to accept as binding,conclusive and final all decisions or interpretations of the Committee upon any questions arising under the Plan or this Agreement. USA Compression Partners, LPa Delaware limited partnership By:USA Compression GP, LLCIts:General Partner By:Name: Eric D. LongTitle: President and CEO “PARTICIPANT” [ ] 10 Exhibit 10.12 USA COMPRESSION PARTNERS, LP ANNUAL CASH INCENTIVE PLAN Set forth below is a description of the Annual Cash Incentive Plan (the “Plan”) of USA Compression Partners, LP (the “Partnership”) and its, and itsgeneral partner’s, subsidiaries (collectively, “USAC”). The Plan includes management personnel (at or above director level) plus other selected key personnelof USAC. For each Plan participant who also maintains an employment agreement with USAC, their potential Plan bonus will be governed both by the Planand their respective employment agreement. The compensation committee (the “Committee”) of the Board of Directors (the “Board”) of USA CompressionGP, LLC, the general partner of the Partnership (the “General Partner”), will act as the administrator of the Plan under the supervision of the full Board,and will have the discretion to amend, modify or terminate the Plan at any time upon approval by the Board. The Board will set a target bonus amount (the “Target Bonus”) for each eligible individual (as indentified by the Chief Executive Officer of the GeneralPartner) prior to or during the first quarter of the calendar year. The Target Bonus will be subject to the satisfaction of both a Partnership performance goaland an individual performance goal. Fifty percent (50%) of the Target Bonus will be subject to the Partnership’s achievement of its budgeted adjusteddistributable cash flow level (“Adjusted DCF”) for the year, as determined by the Board. Payouts with respect to the portion of the bonus subject to AdjustedDCF (the “Adjusted DCF Bonus”) will not occur unless the Partnership has satisfied the threshold set for Adjusted DCF. The threshold, target andmaximum requirements for the Adjusted DCF target for each year, as well as the portion of the Adjusted DCF Bonus that would become payable ifperformance was satisfied for the year, are set forth below: Levels of AdjustedDCF BonusAdjusted DCF as aPercentage of BudgetedAdjusted DCF forthe 2014 YearPercentage ofAdjusted DCFBonus that wouldbe PaidThreshold80%50%Target100%100%Maximum110%200% If Adjusted DCF performance falls in between threshold and target, or between target and maximum, the amounts payable will be adjusted ratably usingstraight line interpolation. If Adjusted DCF is satisfied above maximum levels, the potential payment of the Adjusted DCF Bonus will be capped at themaximum level of 200%. The remaining fifty percent (50%) of the Target Bonus will be subject to individual objectives specific to each eligible individual’s role at USAC (the“Individual Bonus”). The individual objectives will be agreed upon in advance between the employee and his/her immediate supervisor (or, with respect tothe Chief Executive Officer, between the Board and the Chief Executive Officer) that address the key priorities for that individual’s position. They mayinclude key operating objectives as well as personal development criteria. The Individual Bonus will be subject to a maximum payout of 100% of the targetedIndividual Bonus amount, although the Board will have discretion to pay out smaller amounts ranging from 0% to 100%, at their sole discretion, afteranalyzing the individual’s personal performance for the year. In the aggregate, the maximum amount payable with respect to a Target Bonus under the Plan will be 150%, as the Adjusted DCF Bonus will be capped at200% of target and the Individual Bonus will be capped at 100% of target. Target Bonuses, if any, shall be paid within one week following delivery by thePartnership’s independent auditor of the audit of the Partnership’s financial statements for the year in which the Target Bonus relates, but in no case later thanMarch 15 of the year following the year in which the Target Bonus relates. Exhibit 21.1 List of Subsidiaries USA Compression Finance Corp., a Delaware corporation USA Compression Partners, LLC, a Delaware limited liability company USAC Leasing, LLC, a Delaware limited liability company USAC OpCo 2, LLC, a Texas limited liability company USAC Leasing 2, LLC, a Texas limited liability company Exhibit 23.1 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The PartnersUSA Compression Partners, LP: We consent to the incorporation by reference in the Registration Statements on Form S-8 (No. 333-187166) and Form S-3 (Reg. No. 333-193724) of USACompression Partners, LP of our report dated February 20, 2014, with respect to the consolidated balance sheets of USA Compression Partners, LP as ofDecember 31, 2013 and 2012, and the related consolidated statements of operations, partners’ capital and cash flows for each of the years in the three-yearperiod ended December 31, 2013, which report appears in the December 31, 2013 annual report on Form 10-K of USA Compression Partners, LP. /s/ KPMG LLP Dallas, TexasFebruary 20, 2014 Exhibit 31.1 CERTIFICATION I, Eric D. Long, certify that: 1. I have reviewed this Annual Report on Form 10-K of USA Compression Partners, LP (the “registrant”); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for theregistrant and have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared; b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles; c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recentfiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely tomaterially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controlover financial reporting. /s/ Eric D. LongName:Eric D. LongTitle:President and Chief Executive Officer Dated: February 20, 2014 Exhibit 31.2 CERTIFICATION I, Joseph C. Tusa, Jr., certify that: 1. I have reviewed this Annual Report on Form 10-K of USA Compression Partner, LP (the “registrant”); 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make thestatements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects thefinancial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined inExchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for theregistrant and have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, toensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within thoseentities, particularly during the period in which this report is being prepared; b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles; c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recentfiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely tomaterially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to theregistrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonablylikely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controlover financial reporting. /s/ Joseph C. Tusa, Jr.Name:Joseph C. Tusa, Jr.Title:Vice President, Chief Financial Officer and Treasurer Dated: February 20, 2014 Exhibit 32.1 USA COMPRESSION PARTNERS, LPCERTIFICATION PURSUANT TO18 U.S.C. §1350,AS ADOPTED PURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report on Form 10-K of USA Compression Partners, LP (the “Partnership”) for the year ended December 31, 2013 as filedwith the Securities and Exchange Commission on the date hereof (the “Report”), Eric D. Long, as President and Chief Executive Officer of the Partnership’sgeneral partner, hereby certifies, pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to hisknowledge: (1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of thePartnership. /s/ Eric D. LongEric D. LongPresident and Chief Executive Officer Dated: February 20, 2014 A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signaturethat appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Partnership and will beretained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request. Exhibit 32.2 USA COMPRESSION PARTNERS, LPCERTIFICATION PURSUANT TO18 U.S.C. §1350,AS ADOPTED PURSUANT TOSECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report on Form 10-K of USA Compression Partners, LP (the “Partnership”) for the year ended December 31, 2013 as filedwith the Securities and Exchange Commission on the date hereof (the “Report”), Joseph C. Tusa, Jr., as Vice President, Chief Financial Officer and Treasurerof the general partner of the Partnership’s general partner, hereby certifies, pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge: (1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of thePartnership. /s/ Joseph C. Tusa, Jr.Joseph C. Tusa, Jr.Vice President, Chief Financial Officer and Treasurer Dated: February 20, 2014 A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signaturethat appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Partnership and will beretained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.
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