USA Compression Partners
Annual Report 2018

Plain-text annual report

Table of ContentsX` UNITED STATES SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549 Form 10-K (Mark One) ☒☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2018 or ☐☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT 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) Delaware 75-2771546(State or Other Jurisdiction of Incorporation or Organization) (I.R.S. Employer Identification No.) 100 Congress Avenue, Suite 450Austin, TX 78701(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 class Name of each exchange on which registeredCommon Units Representing Limited Partner Interests New 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 ☒ No ☐ 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 ☐ No ☒ Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 duringthe preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for thepast 90 days. Yes ☒ No ☐ Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of RegulationS-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ 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 the best ofthe registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerginggrowth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” or an “emerging growth company” in Rule 12b-2 ofthe Exchange Act. Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new orrevised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ The aggregate market value of common units held by non-affiliates of the registrant as of June 29, 2018, the last business day of the registrant’s most recentlycompleted second fiscal quarter was $831,898,973. This calculation does not reflect a determination that such persons are affiliates for any other purpose. As of February 14, 2019, there were 90,000,504 common units and 6,397,965 Class B Units outstanding. DOCUMENTS INCORPORATED BY REFERENCE: NONE Table of ContentsTable of Contents PART I 1 Item 1.Business1 Item 1A.Risk Factors16 Item 1B.Unresolved Staff Comments39 Item 2.Properties39 Item 3.Legal Proceedings39 Item 4.Mine Safety Disclosures39 PART II 40 Item 5.Market For Registrant’s Common Equity, Related Stockholder Matters and IssuerPurchases of Equity Securities40 Item 6.Selected Financial Data41 Item 7.Management’s Discussion and Analysis of Financial Condition and Results ofOperations47 Item 7A.Quantitative and Qualitative Disclosures About Market Risk64 Item 8.Financial Statements and Supplementary Data64 Item 9.Changes in and Disagreements With Accountants on Accounting and FinancialDisclosure64 Item 9A.Controls and Procedures64 Item 9B.Other Information67 PART III 68 Item 10.Directors, Executive Officers and Corporate Governance68 Item 11.Executive Compensation75 Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters100 Item 13.Certain Relationships and Related Transactions, and Director Independence103 Item 14.Principal Accountant Fees and Services105 PART IV 107 Item 15.Exhibits and Financial Statement Schedules107 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 inthis report are forward-looking statements, including, without limitation, statements regarding our plans, strategies, prospectsand expectations concerning our business, results of operations and financial condition. You can identify many of thesestatements by looking for words such as “believe,” “expect,” “intend,” “project,” “anticipate,” “estimate,” “continue,” “if,”“outlook,” “will,” “could,” “should,” or similar words or the negatives thereof. Known material factors that could cause our actual results to differ from those in these forward-looking statements aredescribed below, in Part I, Item 1A (“Risk Factors”) and in Part II, Item 7 (“Management’s Discussion and Analysis ofFinancial Condition and Results of Operations”). Important factors that could cause our actual results to differ materiallyfrom the expectations reflected in these forward-looking statements include, among other things: ·changes in general economic conditions and changes in economic conditions of the crude oil and natural gasindustries specifically; ·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 existingfleet, including the CDM Acquisition (as defined below); ·actions taken by our customers, competitors and third-party operators; ·the deterioration of the financial condition of our customers; ·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 reportand speak only as of the date of this report. Except as required by law, we undertake no obligation to publicly update orrevise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequentwritten and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in theirentirety by the foregoing cautionary statements. ITEM 1.Business Following the transactions described in further detail below, CDM Resource Management LLC and CDM Environmental& Technical Services LLC, which together represent the CDM Compression Business (the “USA Compression Predecessor”),has been determined to be the historical predecessor of USA Compression Partners, LP (the “Partnership”) for financialreporting purposes. The USA Compression Predecessor is considered the predecessor of the Partnership because EnergyTransfer Equity, L.P. (“ETE”), through its wholly owned subsidiary Energy Transfer Partners, L.L.C., controlled the USACompression Predecessor prior to the transactions described below and obtained control of the Partnership through itsacquisition of USA Compression GP, LLC, the general partner of the Partnership (the “General Partner”). 1 Table of ContentsThe closing of the Transactions occurred on April 2, 2018 (the “Transactions Date”) and has been reflected in theconsolidated financial statements of the Partnership. In October 2018, ETE and Energy Transfer Partners, L.P. (“ETP”) completed the merger of ETP with a wholly ownedsubsidiary of ETE in a unit-for-unit exchange (the “ETE Merger”). Following the closing of the ETE Merger, ETE changedits name to “Energy Transfer LP” and ETP changed its name to “Energy Transfer Operating, L.P.” (“ETO”). Upon theclosing of the ETE Merger, ETE contributed to ETP 100% of the limited liability company interests in the General Partner.References herein to “ETP” refer to Energy Transfer Partners, L.P. for periods prior to the ETE Merger and ETO followingthe ETE Merger, and references to “ETE” refer to Energy Transfer Equity, L.P. for periods prior to the ETE Merger andEnergy Transfer LP following the ETE Merger. All references in this report to the USA Compression Predecessor, as well as the terms “our,” “we,” “us” and “its” referto the USA Compression Predecessor when used in a historical context or in reference to the periods prior to theTransactions Date, unless the context otherwise requires or where otherwise indicated. All references in this section to thePartnership, as well as the terms “our,” “we,” “us” and “its” refer to USA Compression Partners, LP, together with itsconsolidated subsidiaries, including the USA Compression Predecessor, when used in the present or future tense and forperiods subsequent to the Transactions Date, unless the context otherwise requires or where otherwise indicated. Overview We are a growth-oriented Delaware limited partnership, and we believe that we are one of the largest independentproviders of compression services in the United States (“U.S.”) in terms of total compression fleet horsepower. USACompression Partners, LP has been providing compression services since 1998 and completed its initial public offering inJanuary 2013. The USA Compression Predecessor has been providing compression services since 1997 and was a whollyowned indirect subsidiary of ETP prior to the Transactions Date. As of December 31, 2018, we had 3,597,097 horsepower inour fleet and 131,750 horsepower on order for expected delivery during 2019. We provide compression services to ourcustomers primarily in connection with infrastructure applications, including both allowing for the processing andtransportation of natural gas through the domestic pipeline system and enhancing crude oil production through artificial liftprocesses. As such, our compression services play a critical role in the production, processing and transportation of bothnatural gas and crude oil. We provide compression services in a number of shale plays throughout the U.S., including the Utica, Marcellus,Permian Basin, Delaware Basin, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, Haynesville, Niobrara andFayetteville shales. Demand for our services is driven by the domestic production of natural gas and crude oil; as such, wehave focused our activities in areas with attractive natural gas and crude oil production growth, which are generally found inthese shale and unconventional resource plays. According to studies promulgated by the Energy Information Agency(“EIA”), the production and transportation volumes in these shale plays are expected to increase over the long term due tothe comparatively attractive economic returns versus returns achieved in many conventional basins. Furthermore, thechanges in production volumes and pressures of shale plays over time require a wider range of compression services than inconventional basins. We believe we are well-positioned to meet these changing operating conditions due to the flexibility ofour compression units. While our business focuses largely on compression services serving infrastructure applications,including centralized natural gas gathering systems and processing facilities, which utilize large horsepower compressionunits, typically in shale plays, we also provide compression services in more mature conventional basins, including gas liftapplications on crude oil wells targeted by horizontal drilling techniques. Gas lift, a process by which natural gas is injectedinto the production tubing of an existing producing well, in order to reduce the hydrostatic pressure and allow the oil to flowat a higher rate, and other artificial lift technologies are critical to the enhancement of oil production from horizontal wellsoperating in tight shale plays. We operate a modern fleet of compression units, with an average age of approximately five years. We acquire ourcompression units from third-party fabricators who build the units to our specifications, utilizing specific components fromoriginal equipment manufacturers and assembling the units in a manner that provides us the ability to meet certain operatingcondition thresholds. Our standard new-build compression units are generally configured for multiple compression stagesallowing us to operate our units across a broad range of operating conditions. The design flexibility of our units, particularlyin midstream applications, allows us to enter into longer-term contracts and reduces the2 Table of Contentsredeployment 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 toachieve average service run times consistently at or above the levels required by our customers and maintain high overallutilization rates for our fleet. As part of our services, we engineer, design, operate, service and repair our compression units and maintain relatedsupport inventory and equipment. The compression units in our modern fleet are designed to be easily adaptable to fit ourcustomers’ changing compression requirements. Focusing on the needs of our customers and providing them with reliableand flexible compression services in geographic areas of attractive growth helps us to generate stable cash flows for ourunitholders. We provide compression services to our customers under fixed-fee contracts with initial contract terms typically betweensix months and five years, depending on the application and location of the compression unit. We typically continue toprovide compression services at a specific location beyond the initial contract term, either through contract renewal or on amonth-to-month or longer basis. We primarily enter into take-or-pay contracts whereby our customers are required to pay ourmonthly fee even during periods of limited or disrupted throughput, which enhances the stability and predictability of ourcash flows. We are not directly exposed to commodity price risk because we do not take title to the natural gas or crude oilinvolved in our services and because the natural gas used as fuel by our compression units is supplied by our customerswithout cost to us. We provide compression services to major oil companies and independent producers, processors, gatherers andtransporters of natural gas and crude oil. Regardless of the application for which our services are provided, our customersrely upon the availability of the equipment used to provide compression services and our expertise to maximize thethroughput of product, reduce fuel costs and minimize emissions. While we significantly expanded our geographic footprintwith our acquisition of the USA Compression Predecessor from ETP (the “CDM Acquisition”), our customers may havecompression demands in areas of the U.S. in conjunction with their field development projects where we are not currentlyoperating. We continually consider further expansion of our geographic areas of operation in the U.S. based upon the level ofcustomer demand. Our modern, flexible fleet of compression units, which have been designed to be rapidly deployed andredeployed throughout the country, provides us with opportunities to expand into other areas with both new and existingcustomers. We also own and operate a fleet of equipment used to provide natural gas treating services, such as carbon dioxide andhydrogen sulfide removal, natural gas cooling and dehydration, to natural gas producers and midstream companies. Our assets and operations are organized into a single reportable segment and are all located and conducted in the U.S.See our consolidated financial statements, and the notes thereto, included elsewhere in this report for financial informationon our operations and assets; such information is incorporated herein by reference. Recent Developments Senior Notes Issuance On March 23, 2018, USA Compression Partners, LP and its wholly-owned subsidiary, USA Compression Finance Corp., aDelaware corporation (“Finance Corp.” and, together with USA Compression Partners, LP, the “Issuers”) co-issued $725million in aggregate principal amount of 6.875% senior notes due 2026 (the “Senior Notes”) and entered into an Indenture(the “Indenture”), among the Issuers, the Guarantors (as defined below) and Wells Fargo Bank, National Association, astrustee. The Senior Notes are guaranteed (the “Guarantees”), jointly and severally, on a senior unsecured basis by all of thePartnership’s existing subsidiaries (other than Finance Corp.) and will be guaranteed by each of its future restrictedsubsidiaries that either borrows under, or guarantees, the Credit Agreement (as defined below) or guarantees certain of thePartnership’s other indebtedness (collectively, the “Guarantors”). The Senior Notes accrue interest at the rate of 6.875% peryear, and interest on the Senior Notes is payable semi-annually in arrears on April 1 and October 1, with the first suchpayment having occurred on October 1, 2018. 3 Table of ContentsOn January 14, 2019, the Partnership completed an exchange offer whereby holders of the Senior Notes exchanged all ofthe Senior Notes for an equivalent amount of senior notes registered under the Securities Act of 1933 (the “ExchangeNotes”). The Exchange Notes are substantially identical to the Senior Notes, except that the Exchange Notes have beenregistered with the Securities and Exchange Commission (“SEC”) and do not contain the transfer restrictions, restrictivelegends, registration rights or additional interest provisions of the Senior Notes. The Indenture contains customary terms, events of default and covenants relating to, among other things, the incurrenceof debt, the payment of distributions or similar restricted payments, undertaking transactions with affiliates and limitationson asset sales. CDM Acquisition and Issuance of Class B Units On the Transactions Date, we completed the CDM Acquisition for aggregate consideration to ETP of approximately $1.7billion, consisting of (i) 19,191,351 common units, (ii) 6,397,965 Class B units representing limited partner interests in us(the “Class B Units”) and (iii) $1.2 billion in cash (including customary closing adjustments). The Class B Units are a class ofpartnership interests in the Partnership that have substantially all of the rights and obligations of our common units, exceptthat the Class B Units do not receive any quarterly distributions paid on our common units until the Class B Unitsautomatically convert into common units following the record date attributable to the quarter ending June 30, 2019. General Partner Purchase Agreement On the Transactions Date and in connection with the closing of the CDM Acquisition, pursuant to that certain PurchaseAgreement, dated as of January 15, 2018, by and among ETE, Energy Transfer Partners, L.L.C. (together with ETE, the “GPPurchasers”), USA Compression Holdings, LLC (“USAC Holdings”) and, solely for certain purposes therein, R/C IV USACPHoldings, L.P. and ETP, the GP Purchasers acquired from USAC Holdings (i) all of the outstanding limited liability companyinterests in the General Partner and (ii) 12,466,912 common units of the Partnership for cash consideration equal to $250million. Upon the closing of the ETE Merger, ETE contributed all of the outstanding limited liability company interests inthe General Partner and the 12,466,912 common units to ETP. Equity Restructuring Agreement On the Transactions Date and in connection with the closing of the CDM Acquisition, we consummated the transactionscontemplated by the Equity Restructuring Agreement dated January 15, 2018, by and among us, the General Partner andETE, including, among other things, the cancellation of the Incentive Distribution Rights (as defined in the SecondAmended and Restated Agreement of Limited Partnership of the Partnership (the “Partnership Agreement”)) in thePartnership and conversion of the General Partner’s General Partner Interest (as defined in the Partnership Agreement) into anon-economic general partner interest, in exchange for our issuance of 8,000,000 common units to the General Partner. Inaddition, at any time after one year following the Transactions Date, ETE has the right to contribute (or cause any of itssubsidiaries to contribute) to us all of the outstanding equity interests in any of its subsidiaries that owns the general partnerinterest in us in exchange for $10 million (the “GP Contribution”); provided that the GP Contribution will occurautomatically if at any time following the Transactions Date (i) ETE or one of its subsidiaries (including ETP) owns, directlyor indirectly, the general partner interest in us and (ii) ETE and its subsidiaries (including ETP) collectively own less than12,500,000 of our common units. Series A Preferred Unit and Warrant Private Placement On the Transactions Date, we also consummated the transactions contemplated by the Series A Preferred Unit and WarrantPurchase Agreement (the “Purchase Agreement”), dated January 15, 2018, between the Partnership and certain investmentfunds managed or sub-advised by EIG Global Energy Partners (“EIG”) and FS Energy and Power Fund (collectively, the“Purchasers”), whereby the Partnership issued and sold in a private placement $500 million in the aggregate of (i) newlyauthorized and established Series A Preferred Units representing limited partner interests in us (the “Preferred Units”) and(ii) two tranches of warrants to purchase our common units (collectively, the “Warrants”). Pursuant to the terms of thePurchase Agreement, on the Transactions Date, we issued (i) 500,000 Preferred Units to the4 Table of ContentsPurchasers at a price of $1,000 per Preferred Unit, (ii) Warrants to purchase 5,000,000 common units with a strike price of$17.03 per unit and (iii) Warrants to purchase 10,000,000 common units with a strike price of $19.59 per unit. The Warrantsmay be exercised by the holders thereof at any time beginning on the one year anniversary of the Transactions Date andbefore the tenth anniversary of the Transactions Date. Upon exercise of the Warrants, we may, at our option, elect to settle theWarrants in common units on a net basis. Credit Agreement Amendment and Restatement On the Transactions Date, we entered into the Sixth Amended and Restated Credit Agreement (the “Credit Agreement”)by and among the Partnership, as borrower, USAC OpCo 2, LLC, USAC Leasing 2, LLC, USA Compression Partners, LLC,USAC Leasing, LLC, CDM Resource Management LLC, CDM Environmental & Technical Services LLC and Finance Corp.,the lenders party thereto from time to time, JPMorgan Chase Bank, N.A., as agent and an LC issuer, JPMorgan Chase Bank,N.A., Barclays Bank PLC, Regions Capital Markets, a division of Regions Bank, RBC Capital Markets and Wells FargoBank, N.A., as joint lead arrangers and joint book runners, Barclays Bank PLC, Regions Bank, RBC Capital Markets andWells Fargo Bank, N.A., as syndication agents, and MUFG Union Bank, N.A., SunTrust Bank and The Bank of Nova Scotia,as senior managing agents. The Credit Agreement amended and restated that certain Fifth Amended and Restated CreditAgreement, dated as of December 13, 2013, as amended (the “Fifth A&R Credit Agreement”). The Credit Agreement amended the Fifth A&R Credit Agreement to, among other things, (i) increase the borrowingcapacity under the Credit Agreement from $1.1 billion to $1.6 billion (subject to availability under a borrowing base),(ii) extend the termination date (and the maturity date of the obligations thereunder) from January 6, 2020 to April 2, 2023,(iii) subject to the terms of the Credit Agreement, permit up to $400 million of future increases in borrowing capacity,(iv) modify the leverage ratio covenant to be 5.75 to 1.0 through the end of the fiscal quarter ending March 31, 2019, 5.5 to1.0 through the end of the fiscal quarter ending December 31, 2019, and 5.0 to 1.0 thereafter and (v) increase the applicablemargin for eurodollar borrowings to range from 2.00% to 2.75%, depending on our leverage ratio, all as more fully set forthin the Credit Agreement. Amounts borrowed and repaid under the Credit Agreement may be re-borrowed. Please read Part II,Item 7 (“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and CapitalResources—Description of Revolving Credit Facility.”) Business Strategies Our principal business objective is to maintain or increase the quarterly cash distributions that we pay to our commonunitholders over time while ensuring the ongoing stability and growth of our business. We expect to achieve this objectiveby executing on the following strategies: ·Capitalize on the increased need for natural gas compression in conventional and unconventional plays. Weexpect additional demand for compression services to result from the continuing shift of natural gas production todomestic shale plays as well as the declining production pressures of aging conventional basins. The EIA continuesto expect overall natural gas production and transportation volumes, and in particular volumes from domestic shaleplays, to increase over the long term. Furthermore, the changes in production volumes and pressures of shale playsover time require a wider range and increased level of compression services than in conventional basins. Our fleet ofmodern, flexible compression units is capable of being rapidly deployed and redeployed and is designed to operatein multiple compression stages, which will enable us to capitalize on these opportunities in both emerging shaleplays and conventional basins. ·Continue to execute on attractive organic growth opportunities. Prior to the CDM Acquisition, the Partnershipgrew the horsepower in its fleet of compression units and its compression revenues each at a compound annualgrowth rate of 15%, which the Partnership executed primarily through organic growth. We believe organic growthopportunities will be a source of near-term growth, which we seek to achieve by (i) increasing our business withexisting customers, (ii) obtaining new customers in our existing areas of operations and (iii) expanding ouroperations into new geographic areas. ·Partner with customers who have significant compression needs. We actively seek to identify customers withmeaningful acreage positions or significant infrastructure development in active and growing areas. We work5 Table of Contentswith 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 andtransporting natural gas and crude oil. Our proactive and collaborative approach positions us to serve as ourcustomers’ compression service provider of choice. ·Pursue accretive acquisition opportunities. While our principal growth strategy is to continue to grow organically,we may pursue accretive acquisition opportunities, including the acquisition of complementary businesses,participation in joint ventures or the purchase of compression units from existing or new customers in conjunctionwith providing compression services to them. We consider opportunities that (i) are in our existing geographic areasof operations or new, high-growth regions, (ii) meet internally established economic thresholds and (iii) may befinanced on reasonable terms. ·Focus on asset utilization. We seek to actively manage our business in a manner that allows us to continue toachieve high utilization rates at attractive service rates while providing us with the most financial flexibilitypossible. From time to time, we expect the crude oil and natural gas industry to be impacted by the cyclicality ofcommodity prices. During downturns in commodity prices, producers and midstream operators may reduce theircapital spending, which in turn can hinder the demand for compression services. We have the ability, in response toindustry conditions, to drastically and rapidly reduce our capital spending, which allows us to avoid financingorganic growth with outside capital and aligns our capital spending with the demand for compression services. Byreducing organic growth and avoiding new unit deliveries during downturns, we are able to conserve capital andinstead focus on the deployment and re-deployment of our existing asset base. With higher utilization, we are betterpositioned to continue to generate attractive rates of return on our already-deployed capital. ·Maintain financial flexibility. We intend to maintain financial flexibility to enable us to take advantage of growthopportunities. Historically, we have utilized our cash flow from operations, borrowings under the Credit Agreementand issuances of equity securities to fund capital expenditures to expand our compression services business. Thisapproach has allowed us to significantly grow our fleet and the amount of cash we generate, while maintaining debtlevels that we believe are manageable for our business. We believe the appropriate management of our financialposition, and the resulting access to capital, positions us to take advantage of future growth opportunities as theyarise. Our Operations Compression Services We provide compression services for a monthly service fee. As part of our services, we engineer, design, operate, serviceand repair our fleet of compression units and maintain related support inventory and equipment. In certain instances, we alsoengineer, design, install, operate, service and repair certain ancillary equipment used in conjunction with our compressionservices. We have consistently provided average service run times at or above the levels required by our customers. Ingeneral, our team of field service technicians services only our compression fleet and ancillary equipment. In limitedcircumstances and for established customers, we will agree to service third-party owned equipment. We do not own anycompression fabrication facilities. Our Compression Fleet The fleet of compression units that we own and use to provide compression services consists of specially engineeredcompression units that utilize standardized components, principally engines manufactured by Caterpillar, Inc. andcompressor frames and cylinders manufactured by Ariel Corporation. Our units can be rapidly and cost effectively modifiedfor specific customer applications. As of December 31, 2018, the average age of our compression units was approximatelyfive years. Our modern, standardized compression unit fleet is powered primarily by the Caterpillar 3400, 3500 and 3600engine classes, which range from 401 to 5,000 horsepower per unit. These larger horsepower units, which we define as 400horsepower per unit or greater, represented 85.8% of our total fleet horsepower (including compression units on order) as ofDecember 31, 2018. In addition, a portion of our fleet consists of smaller horsepower units ranging from 40 horsepower to399 horsepower that are primarily used in gas lift applications. We believe the young age and6 Table of Contentsoverall composition of our compressor fleet result in fewer mechanical failures, lower fuel usage, and reduced environmentalemissions. The following table provides a summary of our compression units by horsepower as of December 31, 2018: Unit Horsepower FleetHorsepower NumberofUnits Horsepoweron Order (1) Numberof Unitson Order TotalHorsepower NumberofUnits Percent ofTotalHorsepower Percent ofTotalUnits Small horsepower <400 528,084 3,101 900 4 528,984 3,105 14.2% 56.0%Large horsepower >400 and <1,000 429,203 735 — — 429,203 735 11.5% 13.3%>1,000 2,639,810 1,650 130,850 55 2,770,660 1,705 74.3% 30.7%Total 3,597,097 5,486 131,750 59 3,728,847 5,545 100.0% 100.0% (1)As of December 31, 2018, we had 131,750 horsepower on order for delivery during 2019. The following table sets forth certain information regarding our compression fleet as of the dates and for the periodsindicated and excludes certain gas treating assets for which horsepower is not a relevant metric: Year Ended Percent December 31, Change Operating Data: 2018 2017 (8) 2016 (8) 2018 2017 Fleet horsepower (at period end) (1) 3,597,097 1,730,820 1,600,842 107.8% 8.1% Total available horsepower (at period end) (2) 3,675,447 1,780,893 1,606,424 106.4% 10.9% Revenue generating horsepower (at period end) (3) 3,262,470 1,395,328 1,227,899 133.8% 13.6% Average revenue generating horsepower (4) 2,760,029 1,293,864 1,203,487 113.3% 7.5% Revenue generating compression units (at period end) 4,753 2,076 1,789 128.9% 16.0% Average horsepower per revenue generatingcompression unit (5) 674 681 668 (1.0)%1.9% Horsepower utilization (6): At period end 94.0% 87.5% 77.7% 7.4% 12.6% Average for the period (7) 91.9% 82.4% 77.0% 11.5% 7.0% (1)Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order). As of December 31,2018, we had 131,750 horsepower on order for delivery during 2019.(2)Total available horsepower is revenue generating horsepower under contract for which we are billing a customer, horsepower in our fleetthat is under contract but is not yet generating revenue, horsepower not yet in our fleet that is under contract but not yet generatingrevenue and that is subject to a purchase order and idle horsepower. Total available horsepower excludes new horsepower on order forwhich 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 revenue generating horsepower per revenue generating compression unit for each of themonths in the period.(6)Horsepower utilization is calculated as (i) the sum of (a) revenue generating horsepower, (b) horsepower in our fleet that is undercontract, but is not yet generating revenue and (c) horsepower not yet in our fleet that is under contract, not yet generating revenue andthat is subject to a purchase order, divided by (ii) total available horsepower less idle horsepower that is under repair. Horsepowerutilization based on revenue generating horsepower and fleet horsepower was 90.7%, 80.6% and 76.7% at December 31, 2018, 2017and 2016, 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. Averagehorsepower utilization based on revenue generating horsepower and fleet horsepower was 88.0%, 76.9% and 75.9% for the years endedDecember 31, 2018, 2017 and 2016, respectively.7 Table of Contents(8)Certain historical metrics attributable to the USA Compression Predecessor have been conformed to the Partnership’s calculationmethodology. A growing number of our compression units contain electronic control systems that enable us to monitor the unitsremotely by satellite or other means to supplement our technicians’ on-site monitoring visits. We intend to continue toselectively add remote monitoring systems to our fleet during 2019 where beneficial from an operational and financialstandpoint. All of our compression units are designed to automatically shut down if operating conditions deviate from a pre-determined range. While we retain the care, custody, ongoing maintenance and control of our compression units, we allowour customers, subject to a defined protocol, to start, stop, accelerate and slow down compression units in response to fieldconditions. We adhere to routine, preventive and scheduled maintenance cycles. Each of our compression units is subjected torigorous sizing and diagnostic analyses, including lubricating oil analysis and engine exhaust emission analysis. We haveproprietary field service automation capabilities that allow our service technicians to electronically record and trackoperating, technical, environmental and commercial information at the discrete unit level. These capabilities allow our fieldtechnicians to identify potential problems and often act on them before such problems result in down-time. Generally, we expect each of our compression units to undergo a major overhaul between service deployment cycles.The timing of these major overhauls depends on multiple factors, including run time and operating conditions. A majoroverhaul involves the periodic rebuilding of the unit to materially extend its economic useful life or to enhance the unit’sability to fulfill broader or more diversified compression applications. Because our compression fleet is comprised of units ofvarying horsepower that have been placed into service with staggered initial on-line dates, we are able to schedule overhaulsin a way that avoids excessive annual maintenance capital expenditures and minimizes the revenue impact of down-time. We believe that our customers, by outsourcing their compression requirements, can achieve higher compression run-times, which translates into increased volumes of either natural gas or crude oil production and, therefore, increased revenues.Utilizing our compression services also allows our customers to reduce their operating, maintenance and equipment costs byallowing us to efficiently manage their changing compression needs. In many of our service contracts, we guarantee ourcustomers availability (as described below) ranging from 95% to 98%, depending on field- level requirements. General Compression Service Contract Terms The following discussion describes the material terms generally common to our compression service contracts. Wegenerally have separate contracts for each distinct location for which we will provide compression services. Term and termination. Our contracts typically have an initial term of between six months and five years, depending onthe application and location of the compression unit. After the expiration of the initial term, the contract continues on amonth-to-month or longer basis until terminated by us or our customer upon notice as provided for in the applicable contract.As of December 31, 2018, approximately 47% of our compression services on a revenue basis were provided on a month-to-month basis to customers who continue to utilize our services following expiration of the primary term of their contracts withus. Availability. Our contracts often provide a guarantee of specified availability. We define availability as the percentageof time in a given period that our compression services are being provided or are capable of being provided. Availability isreduced by instances of “down-time” that are attributable to anything other than events of force majeure or acts or failures toact by the customer. Down-time under our contracts usually begins when our services stop being provided or when wereceive notice from the customer of the problem. Down-time due to scheduled maintenance is excluded from our availabilitycommitment. Our failure to meet a stated availability guarantee may result in a service fee credit to the customer. As aconsequence of our availability guarantee, we are incentivized to perform predictive and preventive maintenance on our fleetas well as promptly respond to a problem to meet our contractual commitments and ensure our customers the compressionavailability on which their business and our service relationship are based. 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.8 Table of Contents Fees and expenses. Our customers pay a fixed monthly fee for our services. Compression services generally are billedmonthly in advance of the service period, except for certain customers whom we bill at the beginning of the service month;and payments are generally due 30 days from the date of the invoice. We are not responsible for acts of force majeure, and ourcustomers 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,although certain fees and expenses are the responsibility of our customers under the terms of their contracts. For example, allfuel gas is provided by our customers without cost to us, and in many cases customers are required to provide all water andelectricity. At the customer’s option, we can provide fluids necessary to run the unit to the customer for an additional fee. Weprovide such fluids for a substantial majority of the compression units deployed in gas lift applications. We are alsoreimbursed by our customers for certain ancillary expenses such as trucking and crane operation, depending on the termsagreed to in the applicable contract, resulting in little to no impact to gross operating margin. Service standards and specifications. We commit to provide compression services under service contracts that typicallyprovide that we will supply all compression equipment, tools, parts, field service support and engineering in order to meetour customers’ requirements. Our contracts do not specify the specific compression equipment we will use; instead, inconsultation with the customer, we determine what equipment is necessary to perform our contractual commitments. Title; Risk of loss. We own all of the compression equipment in our fleet that we use to provide compression services,and we normally bear the risk of loss or damage to our equipment and tools and injury or death to our personnel. Insurance. Our contracts typically provide that both we and our customers are required to carry general liability,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 team and field technicians.Salespeople, applications engineers and field technicians qualify, analyze and scope new compression applications as well asregularly visit our customers to ensure customer satisfaction, determine a customer’s needs related to existing services beingprovided and determine the customer’s future compression service requirements. This ongoing communication allows us toquickly identify and respond to our customers’ compression requirements. Customers Our customers consist of more than 400 companies in the energy industry, including major integrated oil companies,public and private independent exploration and production companies and midstream companies. Our ten largest customersaccounted for approximately 33% and 43% of our revenue for the year ended December 31, 2018 and 2017, respectively. Suppliers and Service Providers The principal manufacturers of components for our natural gas compression equipment include Caterpillar, Inc.,Cummins Inc., and Arrow Engine Company for engines, Air-X-Changers and Alfa Laval (US) for coolers, and ArielCorporation, GE Oil & Gas Gemini products and Arrow Engine Company for compressor frames and cylinders. We also relyprimarily on four vendors, A G Equipment Company, Alegacy Equipment, LLC, Standard Equipment Corp. and GenisHoldings LLC, to package and assemble our compression units. Although we rely primarily on these suppliers, we believealternative sources for natural gas compression equipment are generally available if needed. However, relying on alternativesources may increase our costs and change the standardized nature of our fleet. We have not experienced any material supplyproblems to date. Although lead-times for new Caterpillar engines and new Ariel compressor frames have in the past been inexcess of one year due to increased demand and supply allocations imposed on equipment packagers and end-users,currently lead-times for such engines and frames are approximately one year or shorter. Please9 Table of Contentsread Part I, 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 andgreater financial and other resources than we do. On a regional basis, we experience competition from numerous smallercompanies that may be able to more quickly adapt to changes within our industry and changes in economic conditions as awhole, more readily take advantage of available opportunities and adopt more aggressive pricing policies. Additionally, thehistorical availability of attractive financing terms from financial institutions and equipment manufacturers has made thepurchase of individual compression units affordable to our customers. We believe that we compete effectively on the basis ofprice, equipment availability, customer service, flexibility in meeting customer needs, quality and reliability of ourcompressors and related services. Please read Part I, Item 1A (“Risk Factors—Risks Related to Our Business—We facesignificant competition that may cause us to lose market share and reduce our cash available for distribution”). Seasonality Our results of operations have not historically been materially affected by seasonality, and we do not currently havereason to believe that seasonal fluctuations will have 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 inthe energy services industry, we review our safety equipment and procedures and carry insurance against most, but not all,risks of our business. Losses and liabilities not covered by insurance would increase our costs. The compression business canbe hazardous, involving unforeseen circumstances such as uncontrollable flows of gas or well fluids, fires and explosions orenvironmental 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 other coverage, although coverage for environmental and pollution related losses is subjectto significant limitations. Under the terms of our standard compression services contract, we are responsible for maintaininginsurance coverage on our compression equipment. Please read Part I, Item 1A (“Risk Factors—Risks Related to Our Business—We do not insure against all potential losses and could be seriously harmed by unexpected liabilities”). Environmental and Safety Regulations We are subject to stringent and complex federal, state and local laws and regulations governing the discharge ofmaterials into the environment or otherwise relating to protection of human health, safety and the environment. Theseregulations include compliance obligations for air emissions, water quality, wastewater discharges and solid and hazardouswaste disposal, as well as regulations designed for the protection of human health and safety and threatened or endangeredspecies. Compliance with these environmental laws and regulations may expose us to significant costs and liabilities andcause us to incur significant capital expenditures in our operations. We are often obligated to assist customers in obtainingpermits or approvals in our operations from various federal, state and local authorities. Permits and approvals can be deniedor delayed, which may cause us to lose potential and current customers, interrupt our operations and limit our growth andrevenue. Moreover, failure to comply with these laws and regulations may result in the assessment of administrative, civiland criminal penalties, imposition of remedial obligations and the issuance of injunctions delaying or prohibitingoperations. Private parties may also have the right to pursue legal actions to enforce compliance as well as to seek damagesfor non-compliance with environmental laws and regulations or for personal injury or property damage. While we believethat 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, we cannot predict whether our cost ofcompliance will materially increase in the future. Any changes in, or more stringent enforcement of, existing environmentallaws and regulations, or passage of additional10 Table of Contentsenvironmental 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 financialposition. We do not believe that compliance with federal, state or local environmental laws and regulations will have a materialadverse effect on our business, financial position or results of operations or cash flows. We cannot assure you, however, thatfuture events such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations, or thedevelopment or discovery of new facts or conditions or unforeseen incidents will not cause us to incur significant costs. Thefollowing 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. Please read Part I, Item 1A (“Risk Factors—Risks Related to Our Business—We are subject to substantial environmental regulation, and changes in these regulationscould increase our costs or liabilities”). Air emissions. The Clean Air Act (“CAA”) and comparable state laws regulate emissions of air pollutants from variousindustrial sources, including natural gas compressors, and impose certain monitoring and reporting requirements. Suchemissions are regulated by air emissions permits, which are applied for and obtained through various state or federalregulatory agencies. Our standard natural gas compression contract provides that the customer is responsible for obtaining airemissions permits and assuming the environmental risks related to site operations. In some instances, our customers may berequired to aggregate emissions from a number of different sources on the theory that the different sources should beconsidered a single source. Any such determinations could have the effect of making projects more costly than our customersexpected and could require the installation of more costly emissions controls, which may lead some of our customers not topursue certain projects. Increased obligations of operators to reduce air emissions of nitrogen oxides and other pollutants from internalcombustion engines in transmission service have been enacted by governmental authorities. For example, in 2010, the U.S.Environmental Protection Agency (“EPA”) published new regulations under the CAA to control emissions of hazardous airpollutants from existing stationary reciprocal internal combustion engines, also known as Quad Z regulations. Therule requires us to undertake certain expenditures and activities, including purchasing and installing emissions controlequipment on certain compressor engines and generators. In recent years, the EPA has lowered the National Ambient Air Quality Standards (“NAAQS”) for several air pollutants.For example, in 2015, the EPA finalized a rule strengthening the primary and secondary standards for ground level ozone,both of which are 8-hour concentration standards of 70 parts per billion. After the EPA revises a NAAQS standard, the statesare expected to establish revised attainment/non-attainment regions. State implementation of the revised NAAQS couldresult in stricter permitting requirements, delay or prohibit our customers’ ability to obtain such permits, and result inincreased expenditures for pollution control equipment, which could impact our customers’ operations, increase the cost ofadditions to property, plant, and equipment, and negatively impact our business. In 2012, the EPA finalized rules that establish new air emissions controls for oil and natural gas production and naturalgas processing operations. Specifically, the EPA’s rule package included New Source Performance Standards to addressemissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emissions standards to addresshazardous air pollutants frequently associated with oil and natural gas production and processing activities. Therules established 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 gaswells that are hydraulically fractured. In June 2016, the EPA took steps to expand on these regulations when it publishedNew Source Performance Standards, known as Subpart OOOOa, that require certain new, modified or reconstructed facilitiesin the oil and natural gas sector to reduce methane gas and VOC emissions. These Subpart OOOOa standards would expandthe 2012 New Source Performance Standards by using certain equipment-specific emissions control practices, requiringadditional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repairrequirements for natural gas compressor and booster stations. However, the EPA announced in April 2017 that it intended toreconsider certain aspects of the 2016 New Source Performance Standards, and in May 2017, the EPA issued anadministrative stay of key provisions of the rule, but was promptly ordered by the D.C. Circuit to implement the rule. TheEPA also proposed 60-day and two-year stays of certain provisions in June 2017 and published a Notice of Data Availabilityin November 2017 seeking comment and providing clarification regarding11 Table of Contentsthe agency’s legal authority to stay the rule. In March 2018, EPA finalized narrow amendments to the rule, and in October2018, EPA proposed further reconsideration amendments to the rule. Among other things, these amendments would alterfugitive emissions requirements, monitoring frequencies, and well site pneumatic pump standards. Depending upon whether EPA finalizes these further amendments, Subpart OOOOa and any additional regulation of airemissions from the oil and gas sector could result in increased expenditures for pollution control equipment, which couldimpact our customers’ operations and negatively impact our business. We are also subject to air regulation at the state level. For example, the Texas Commission on Environmental Quality(“TCEQ”) has finalized revisions to certain air permit programs that significantly increase the air permitting requirements fornew 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 enginesby requiring the use of alternative engines, compressor packages or the installation of aftermarket emissions controlequipment. The rule became effective for the Barnett Shale production area in April 2011, with the lower emissions standardsbecoming applicable between 2015 and 2030 depending on the type of engine and the permitting requirements. The cost tocomply 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 complywith such requirements if the geographic scope is expanded. There can be no assurance that future requirements compelling the installation of more sophisticated emissions controlequipment would not have a material adverse impact on our business, financial condition, results of operations and cashavailable for distribution. Climate change. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning ofnatural gas, are examples of greenhouse gases (“GHGs”). In recent years, the U.S. Congress has considered legislation toreduce GHG emissions. It presently appears unlikely that comprehensive climate legislation will be passed in the near future,although energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues.For example, such initiatives could include a carbon tax or cap and trade program. Further, although Congress has not passedsuch legislation, almost half of the states have begun to address GHG emissions, primarily through the planned developmentof emissions inventories or regional GHG cap and trade programs. Depending on the particular program, we could be requiredto control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations. Independent of Congress, the EPA undertook to adopt regulations controlling GHG emissions under its existing CAAauthority. For example, in 2009, the EPA officially published its findings that emissions of carbon dioxide, methane andother GHGs endanger human health and the environment, allowing the agency to proceed with the adoption of regulationsthat restrict emissions of GHG under existing provisions of the CAA. In 2009 and 2010, the EPA adopted rules regardingregulation of GHG emissions from motor vehicles and requiring the reporting of GHG emissions in the U.S. from specifiedlarge GHG emissions sources, including petroleum and natural gas facilities such as natural gas transmission compressionfacilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year. In 2015, the EPA published standards of performance for GHG emissions from new power plants. The final ruleestablishes a performance standard for integrated gasification combined cycled units and utility boilers based on the use ofthe best system of emissions reduction that the EPA has determined has been adequately demonstrated for each type of unit.The rule also sets limits for stationary natural gas combustion turbines based on the use of natural gas combined cycletechnology. The EPA also promulgated the Clean Power Plan rule (“CPP”), which is intended to reduce carbon emissions fromexisting power plants by 32 percent from 2005 levels by 2030. In February 2016, the U.S. Supreme Court granted a stay ofthe implementation of the CPP, which will remain in effect throughout the pendency of the appeals process, including at theU.S. Court of Appeals for the D.C. Circuit and the Supreme Court through any certiorari petition that may be granted. Thestay suspends the rule, including the requirement that states must start submitting implementation plans. It is not yet clearhow the courts will ultimately rule on the legality of the CPP. Additionally, in October 2017, the EPA proposed to repeal theCPP, and in August 2018, the EPA proposed the Affordable Clean Energy rule (“ACE”) to12 Table of Contentsreplace the CPP. If the effort to replace the CPP with the ACE rule is unsuccessful and rules similar to the CPP are upheld tocontrol GHG emissions from electric utility generating units, demand for the oil and natural gas our customers produce maydecrease. In addition, the costs of electricity for our operations may also increase, thereby adversely impacting our business. In addition to the EPA, the Bureau of Land Management (“BLM”) has also promulgated rules to regulate hydraulicfracturing. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the rock formation tostimulate gas production. In 2015, the BLM promulgated new requirements relating to well construction, water management,and chemical disclosure for companies drilling on federal and tribal land, but subsequently finalized a rule in December2017 rescinding the 2015 rule. This rescission has been challenged and that litigation is ongoing. If this rescission is notupheld, it could increase the costs of operation for our customers who operate on BLM land, and negatively impact ourbusiness. Additionally, on November 15, 2016, the BLM also finalized a rule to reduce the flaring, venting and leaking ofmethane from oil and gas operations on federal and Indian lands (the “Venting Rule”). The Venting Rule requires operatorsto use certain technologies and equipment to reduce flaring and to periodically inspect their operations for leaks. TheVenting Rule also specifies when operators owe the government royalties for flared gas. In December 2017, BLM finalized adecision to delay implementation of key requirements in the Venting Rule for one year. The agency subsequently finalized arule in September 2018 to revise the 2016 Venting rule (the “Revised Venting Rule”) by rescinding certain requirements,such as the requirement to use certain technologies and equipment, as well as the leak detection and repair requirement. TheRevised Venting Rule also specifies that BLM will defer to the appropriate State or tribal authorities in determining whetherroyalties are owed for flared gas. Challenges to the Venting Rule and the Revised Venting Rule are pending in court. If theRevised Venting Rule is not upheld, and the Venting Rule is fully implemented, it could increase the costs of operations forour customers who operate on BLM land, and negatively impact our business.At the international level, nearly 200 nations entered into an international climate agreement at the 2015 United NationsFramework Convention on Climate Change in Paris, under which participating countries did not assume any bindingobligation to reduce future emissions of GHGs but instead pledged to voluntarily limit or reduce future emissions. Althoughthe U.S. became a party to the Paris Agreement in April 2016, the Trump administration announced in June 2017 its intentionto either withdraw from the Paris Agreement or renegotiate more favorable terms. However, the Paris Agreement stipulatesthat participating countries must wait four years before withdrawing from the agreement. Despite the planned withdrawal,certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under theParis Agreement.Although it is not currently possible to predict with specificity how any proposed or future GHG legislation, regulation,agreements or initiatives will impact our business, any legislation or regulation of GHG emissions that may be imposed inareas in which we conduct business or on the assets we operate could result in increased compliance or operating costs oradditional operating restrictions or reduced demand for our services, and could have a material adverse effect on ourbusiness, financial condition and results of operations. Notwithstanding potential risks related to climate change, theInternational Energy Agency estimates that oil and gas will continue to represent a major share of global energy use through2040, and other private sector studies project continued growth in demand for the next two decades. However, recentactivism directed at shifting funding away from companies with energy-related assets could result in limitations orrestrictions on certain sources of funding for the energy sector. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in Earth’satmosphere may produce climate changes that have significant weather-related effects, such as increased frequency andseverity of storms, droughts, floods and other climatic events. If any of those effects were to occur, they could have anadverse effect on our assets and operations. Water discharge. The Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls withrespect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States.The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by theEPA or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredgeand fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit.The CWA also requires the development and implementation of spill prevention, control and countermeasures, including theconstruction and maintenance of containment berms and similar structures, if13 Table of Contentsrequired, to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture orleak 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 imposeadministrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with dischargepermits or other requirements of the CWA and analogous state laws and regulations. Our compression operations do not generate process wastewaters that are discharged to waters of the United States. Inany event, our customers assume responsibility under the majority of our standard natural gas compression contracts forobtaining any permits that may be required under the CWA, whether for discharges or developing property by fillingwetlands. Considerable legal uncertainty exists surrounding the standard for what constitutes jurisdictional waters andwetlands subject to the protections and requirements of the CWA. A 2015 rulemaking by the EPA that would significantlyexpand the scope of jurisdictional waters has been enjoined in a significant number of states by various district courts. As aresult, while the 2015 rule is currently implemented in some states, in other states, the EPA continues to implement the pre-2015 definition of waters of the United States as determined by the preexisting regulatory definition, the Supreme Court’sholding in Rapanos v. United States, and the agency’s post-Rapanos guidance. In 2018, the Supreme Court held thatchallenges to the rule must be heard in district courts before appeals to the circuit courts can be made; litigation is ongoingregarding substantive challenges to the rule. EPA has also proposed two separate rulemakings to repeal and replace the 2015Rule, both of which are likely to be challenged if finalized. Should the 2015 rule take effect nationwide, or should a differentrule expand the jurisdictional reach of the CWA, our customers could face increased costs and delays due to additionalpermitting and regulatory requirements and possible challenges to permitting decisions. Safe Drinking Water Act. A significant portion of our customers’ natural gas production is developed fromunconventional sources that require hydraulic fracturing as part of the completion process. Legislation to amend the SafeDrinking Water Act (“SDWA”) to repeal the exemption for hydraulic fracturing from the definition of “undergroundinjection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals torequire disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed and the U.S.Congress continues to consider legislation to amend the SDWA. Scrutiny of hydraulic fracturing activities continues in otherways, with the EPA having commenced a multi-year study of the potential environmental impacts of hydraulic fracturing. InDecember 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources.The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking waterresources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- orregional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals forfracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals orproduced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluidsdirectly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposalor storage of fracturing wastewater in unlined pits. The EPA has also announced that it believes hydraulic fracturing usingfluids containing diesel fuel can be regulated under the SDWA notwithstanding the SDWA’s general exemption for hydraulicfracturing. Several states have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing,including prohibitions on the practice. We cannot predict the future of such legislation and what additional, if any,provisions would be included. If additional levels of regulation, restrictions and permits were required through the adoptionof new laws and regulations at the federal or state level or if the agencies that issue the permits develop new interpretations ofthose requirements, that could lead to delays, increased operating costs and process prohibitions that could reduce demandfor our compression services, which could materially adversely affect our revenue and results of operations. Solid waste. The Resource Conservation and Recovery Act (“RCRA”) and comparable state laws control themanagement and disposal of hazardous and non-hazardous waste. These laws and regulations govern the generation, storage,treatment, transfer and disposal of wastes that we generate including, but not limited to, used oil, antifreeze, filters, sludges,paint, solvents and sandblast materials. The EPA and various state agencies have limited the approved methods of disposalfor these types of wastes. Site remediation. The Comprehensive Environmental Response Compensation and Liability Act (“CERCLA”) andcomparable state laws impose strict, joint and several liability without regard to fault or the legality of the original14 Table of Contentsconduct on certain classes of persons that contributed to the release of a hazardous substance into the environment. Thesepersons include the owner and operator of a disposal site where a hazardous substance release occurred and any company thattransported, disposed of or arranged for the transport or disposal of hazardous substances released at the site. Under CERCLA,such persons may be liable for the costs of remediating the hazardous substances that have been released into theenvironment, for damages to natural resources, and for the costs of certain health studies. In addition, where contaminationmay be present, it is not uncommon for the neighboring landowners and other third parties to file claims for personal injury,property damage and recovery of 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 cleanupcosts under CERCLA at any site. While we do not currently own or lease any material facilities or properties for storage or maintenance of our inactivecompression units, we may use third party properties for such storage and possible maintenance and repair activities. Inaddition, our active compression units typically are installed on properties owned or leased by third party customers andoperated by us pursuant to terms set forth in the natural gas compression services contracts executed by those customers.Under most of our natural gas compression services contracts, our customers must contractually indemnify us for certaindamages we may suffer as a result of the release into the environment of hazardous and toxic substances. We are not currentlyresponsible for any remedial activities at any properties we use; however, there is always the possibility that our future use ofthose properties may result in spills or releases of petroleum hydrocarbons, wastes or other regulated substances into theenvironment 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 ofsuch remedial obligations upon us would not have a material adverse effect on our operations or financial position. Safety and health. The Occupational Safety and Health Act (“OSHA”) and comparable state laws strictly govern theprotection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and, as necessary, discloseinformation about hazardous materials used or produced in our operations to various federal, state and local agencies, as wellas employees. Employees USAC Management Services, LLC (“USAC Management”), a wholly owned subsidiary of the General Partner, performscertain management and other administrative services for us, such as accounting, corporate development, finance and legal.All of our employees, including our executive officers, are employees of USAC Management. As of December 31, 2018,USAC Management had 864 full time employees. None of our employees are subject to collective bargaining agreements.We consider our employee relations to be good. Available Information Our website address is usacompression.com. We make available, free of charge at the “Investor Relations” section of ourwebsite, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and allamendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, asamended (the “Exchange Act”), as soon as reasonably practicable after such reports are electronically filed with, or furnishedto, the SEC. The information contained on our website does not constitute part of this report. The SEC maintains a website that contains these reports at sec.gov. 15 Table of Contents ITEM 1A.Risk Factors As described in Part I (“Disclosure Regarding Forward-Looking Statements”), this report contains forward-lookingstatements regarding us, our business and our industry. The risk factors described below, among others, could cause ouractual results to differ materially from the expectations reflected in the forward-looking statements. If any of the followingrisks were to materialize, our business, financial condition or results of operations could be materially and adverselyaffected. In that case, we might not be able to continue to pay our current quarterly distribution on our common units orincrease the level of such distributions in the future, 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 andexpenses, including cost reimbursements to the General Partner, to enable us to make cash distributions on our commonunits at the current level. In order to make cash distributions at our current distribution rate of $0.525 per common unit per quarter, or $2.10 percommon unit per year, we will require available cash of $47.2 million per quarter, or $189.0 million per year, based on thenumber of common units outstanding as of February 14, 2019. In addition, each Class B Unit will automatically convert toone common unit of the Partnership following the record date attributable to the quarter ending June 30, 2019. Distributionson the newly converted Class B Units will require additional available cash of $3.4 million per quarter, or $13.4 million peryear at our current distribution rate. Furthermore, the Partnership Agreement prohibits us from paying distributions on our common units unless we have firstpaid the quarterly distribution on the Preferred Units, including any previously accrued but unpaid distributions on thePreferred Units. The Preferred Unit distributions require $12.2 million quarterly, or $48.8 million annually, based on thenumber of Preferred Units outstanding and the distribution rate of $24.375 per Preferred Unit per quarter, or $97.50 perPreferred Unit per year. Under our cash distribution policy, the amount of cash we can distribute to our unitholders principally depends upon theamount 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 inthe regions where we provide compression 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 ability to effectively integrate any assets or businesses we acquire; ·the level of competition from other companies; and ·prevailing global and regional economic and regulatory conditions, and their impact on us and 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 and expansion capital expenditures; ·the level of our operating costs and expenses; ·our debt service requirements and other liabilities; 16 Table of Contents·fluctuations in our working capital needs; ·restrictions contained in the Credit Agreement or the Indenture governing the Senior Notes; ·the cost of acquisitions; ·fluctuations in interest rates; ·the financial condition of our customers; ·our ability to borrow funds and access the capital markets; and ·the amount of cash reserves established by the General Partner. A long-term reduction in the demand for, or production of, natural gas or crude oil could adversely affect the demand forour services or the prices we charge for our services, which could result in a decrease in our revenues and cash availablefor distribution to unitholders. The demand for our compression services depends upon the continued demand for, and production of, natural gas andcrude oil. Demand may be affected by, among other factors, natural gas prices, crude oil prices, weather, availability ofalternative energy sources, governmental regulation and the overall demand for energy. Any prolonged, substantialreduction in the demand for natural gas or crude oil would likely depress the level of production activity and result in adecline in the demand for our compression services, which could result in a reduction in our revenues and our cash availablefor distribution. In particular, lower natural gas or crude oil prices over the long term could result in a decline in the production of naturalgas or crude oil, respectively, resulting in reduced demand for our compression services. For example, the North American rigcount, as measured by Baker Hughes, hit a 2014 peak of 1,931 rigs on September 12, 2014, and at that time, Henry Hubnatural gas spot prices were $3.82 per MMBtu and West Texas Intermediate (“WTI”) crude oil spot prices were $92.18 perbarrel. By contrast, the North American rig count hit a modern low of 404 rigs on May 20, 2016, and at that time, Henry Hubnatural gas spot prices were $1.81 per MMBtu and WTI crude oil spot prices were $47.67 per barrel. This slowdown in newdrilling activity caused some pressure on service rates for new and existing services and contributed to a decline in ourutilization during 2015 and into 2016. By the end of December 2018, the North American rig count was 1,083 rigs, the priceof WTI crude oil was $45.15 per barrel and Henry Hub natural gas spot prices were $3.25 per MMBtu. Although commodityprices and our utilization generally increased during 2016, 2017 and 2018, the increased activity resulting from suchincreased commodity prices may not continue. In addition, a small portion of our fleet is used in gas lift applications inconnection with crude oil production using horizontal drilling techniques. During the period of low crude oil prices, weexperienced pressure on service rates from our customers in gas lift applications; if commodity prices decline from currentlevels, we may again experience pressure on service rates. Additionally, an increasing percentage of natural gas and crude oil production comes from unconventional sources, suchas shales, tight sands and coalbeds. Such sources can be less economically feasible to produce in low commodity priceenvironments, in part due to costs related to compression requirements, and a reduction in demand for natural gas or gas liftfor crude oil may cause such sources of natural gas or crude oil to become uneconomic to drill and produce, which could inturn negatively impact the demand for our services. Further, if demand for our services decreases, we may be asked torenegotiate our service contracts at lower rates. In addition, governmental regulation and tax policy may impact the demandfor natural gas or crude oil or impact the economic feasibility of the development of new fields or production of existingfields, which are important components of our ability to expand. We have several key customers. The loss of any of these customers would result in a decrease in our revenues and cashavailable for distribution. We provide compression services under contracts with several key customers. The loss of one of these key customersmay have a greater effect on our financial results than for a company with a more diverse customer base. Our17 Table of Contentsten largest customers accounted for approximately 33% and 43% of our revenue for the years ended December 31, 2018 and2017, respectively. The loss of all or even a portion of the compression services we provide to our key customers, as a resultof competition or otherwise, could have a material adverse effect on our business, results of operations, financial conditionand cash available for distribution. The deterioration of the financial condition of our customers could adversely affect our business. During times when the natural gas or crude oil markets weaken, our customers are more likely to experience financialdifficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’spending for our services. For example, our customers could seek to preserve capital by using lower cost providers, notrenewing month-to-month contracts or determining not to enter into any new compression service contracts. A significantdecline in commodity prices may cause certain of our customers to reconsider their near-term capital budgets, which mayimpact large-scale natural gas infrastructure and crude oil production activities. Reduced demand for our services couldadversely affect our business, results of operations, financial condition and cash flows. We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, suppliers or vendors couldreduce our revenues, increase our expenses and otherwise have a negative impact on our ability to conduct our business,operating results, cash flows and ability to make distributions to our unitholders. Weak economic conditions and widespread financial distress could reduce the liquidity of our customers, suppliers orvendors, making it more difficult for them to meet their obligations to us. We are therefore subject to risks of loss resultingfrom nonpayment or nonperformance by our customers. Severe financial problems encountered by our customers could limitour ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractualarrangements. In the event that any of our customers was to enter into bankruptcy, we could lose all or a portion of theamounts owed to us by such customer, and we may be forced to cancel all or a portion of our service contracts with suchcustomer at significant expense to us. In addition, nonperformance by suppliers or vendors who have committed to provide us with critical products or servicescould raise our costs or interfere with our ability to successfully conduct our business. We face significant competition that may cause us to lose market share and reduce our cash available for distribution. The natural gas compression business is highly competitive. Some of our competitors have a broader geographic scopeand greater financial and other resources than we do. Our ability to renew or replace existing contracts with our customers atrates sufficient to maintain current revenue and cash flows could be adversely affected by the activities of our competitorsand our customers. If our competitors substantially increase the resources they devote to the development and marketing ofcompetitive 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,which would create additional competition for us. All of these competitive pressures could have a material adverse effect onour business, results of operations, financial condition and cash available for distribution. Our customers may choose to vertically integrate their operations by purchasing and operating their own compressionfleet, increasing the number of compression units they currently own or using alternative technologies for enhancing crudeoil production. Our customers that are significant producers, processors, gatherers and transporters of natural gas and crude oil maychoose to vertically integrate their operations by purchasing and operating their own compression fleets in lieu of using ourcompression services. The historical availability of attractive financing terms from financial institutions and equipmentmanufacturers facilitates this possibility by making the purchase of individual compression units increasingly affordable toour customers. In addition, there are many technologies available for the artificial enhancement of crude oil production, andour customers may elect to use these alternative technologies instead of the gas lift compression services we provide. Suchvertical integration, increases in vertical integration or use of alternative technologies could result in18 Table of Contentsdecreased demand for our compression services, which may have a material adverse effect on our business, results ofoperations, financial condition and reduce our cash available for distribution. A significant portion of our services are provided to customers on a month-to-month basis, and we cannot be sure that suchcustomers will continue to utilize our services. Our contracts typically have an initial term of between six months and five years, depending on the application andlocation of the compression unit. After the expiration of the initial term, the contract continues on a month-to-month orlonger basis until terminated by us or our customers upon notice as provided for in the applicable contract. As ofDecember 31, 2018, approximately 47% of our compression services on a revenue basis were provided on a month-to-monthbasis to customers who continue to utilize our services following expiration of the primary term of their contracts. Thesecustomers 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 substantially lower rates, it could have a material adverse effect on our business, results of operations,financial condition and cash available for distribution. We may be unable to grow our cash flows if we are unable to expand our business, which could limit our ability tomaintain or increase the level of distributions to our common unitholders. A principal focus of our strategy is to increase our per common unit distribution by expanding our business over time.Our future growth will depend upon a number of factors, some of which we cannot control. These factors include our abilityto: ·develop new business and enter into service contracts with new customers; ·retain our existing customers and maintain or expand the services we provide them; ·maintain or increase the fees we charge, and the margins we realize, from our compression services; ·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 on favorable terms 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 maintain or increase the level of distributions on ourcommon units, in which event the market price of our common units will likely decline. We may be unable to grow successfully through acquisitions, which may negatively impact our operations and limit ourability to maintain or increase the level of distributions on our common units. From time to time, we may choose to make business acquisitions, such as the CDM Acquisition, to pursue marketopportunities, increase our existing capabilities and expand into new geographic areas of operations. While we havereviewed acquisition opportunities in the past and will continue to do so in the future, we may not be able to identifyattractive acquisition opportunities or successfully acquire identified targets. Any acquisitions we do complete may require us to issue a substantial amount of equity or incur a substantial amount ofindebtedness. If we consummate any future material acquisitions, our capitalization may change significantly,19 Table of Contentsand unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we willconsider in connection with any future acquisition. Furthermore, competition for acquisition opportunities may escalate,increasing our costs of pursuing acquisitions or causing us to refrain from making acquisitions. Also, our reviews of proposed business or asset acquisitions are inherently imperfect because it is generally not feasibleto perform an in-depth review of each such proposal given time constraints imposed by sellers. Even if performed, a detailedreview of assets and businesses may not reveal existing or potential problems, and may not provide sufficient familiarity withsuch business or assets to fully assess their deficiencies and potential. Inspections may not be performed on every asset, andenvironmental problems, such as groundwater contamination, may not be observable even when an inspection is undertaken. Integration of assets acquired in past acquisitions or future acquisitions with our existing business can be a complex, time-consuming and costly process, particularly in the case of material acquisitions such as the CDM Acquisition, whichsignificantly increased our size and expanded the geographic areas in which we operate. A failure to successfully integratethe acquired assets with our existing business in a timely manner may have a material adverse effect on our business,financial condition, results of operations or cash available for distribution to our unitholders. The difficulties of integrating past and future acquisitions with our business include, among other things: ·operating a larger combined organization in new geographic areas and new lines of business; ·hiring, training or retaining qualified personnel to manage and operate our growing business and assets; ·integrating management teams and employees into existing operations and establishing effective communicationand information exchange with such management teams and employees; ·diversion of management’s attention from our existing business; ·assimilation of acquired assets and operations, including additional regulatory programs; ·loss of customers; ·loss of key employees; ·maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002 as well asother regulatory compliance and corporate governance matters; and ·integrating new technology systems for financial reporting. If any of these risks or other unanticipated liabilities or costs were to materialize, we may not realize the desired benefitsfrom past and future acquisitions, resulting in a negative impact on our results of operations. For example, subsequent to theCDM Acquisition the attrition rate of specialized field technicians exceeded our projections and, as a result, we incurredunanticipated costs to utilize third-party contractors to service our compression units at a greater cost than we would haveincurred to compensate employees to perform the same work. We may not be successful in integrating acquisitions, including the CDM Acquisition, into our existing operationswithin our anticipated timeframe, which may result in unforeseen operational difficulties or diminished financialperformance or require a disproportionate amount of our management’s attention. In addition, acquired assets may perform atlevels below the forecasts used to evaluate their acquisition, due to factors beyond our control. If the acquired assets performat levels below the forecasts, then our future results of operations could be negatively impacted. 20 Table of ContentsOur ability to fund purchases of additional compression units and complete acquisitions in the future is dependent on ourability to access external expansion capital. The Partnership Agreement requires us to distribute all of our available cash to our unitholders (excluding prudentoperating reserves). We expect that we will rely primarily upon cash generated by operating activities and, where necessary,borrowings under the Credit Agreement and the issuance of debt and equity securities, to fund expansion capitalexpenditures. However, we may not be able to obtain equity or debt financing on terms favorable to us or at all. To the extentwe are unable to efficiently finance growth through external sources, our ability to maintain or increase the level ofdistributions on our common units could be significantly impaired. In addition, because we distribute all of our availablecash, excluding prudent operating reserves, we may not grow as quickly as businesses that are able to reinvest their availablecash to expand ongoing operations. There are no limitations in the Partnership Agreement on our ability to issue additional equity securities, includingsecurities ranking senior to the common units, subject to certain restrictions in the Partnership Agreement limiting our abilityto issue units senior to or pari passu with the Preferred Units. To the extent we issue additional equity securities, includingcommon units and preferred units, the payment of distributions on those additional securities may increase the risk that wewill be unable to maintain or increase our per common unit distribution level. Similarly, our incurrence of borrowings orother debt to finance our growth strategy would increase our interest expense, which in turn would decrease our cashavailable for distribution. Our debt level may limit our flexibility in obtaining additional financing, pursuing other business opportunities andpaying distributions. The Credit Agreement is a $1.6 billion revolving credit facility that matures in April 2023. In addition, we have theoption to increase the amount of total commitments under the Credit Agreement by up to $400.0 million, subject to receiptof lender commitments and satisfaction of other conditions. As of December 31, 2018, we had outstanding borrowings underthe Credit Agreement of $1.1 billion and a leverage ratio of 4.33x, borrowing base availability (based on our borrowing base)of $550.5 million and, subject to compliance with the applicable financial covenants, available borrowing capacity underthe Credit Agreement of $550.5 million. Financial covenants in the Credit Agreement permit a maximum leverage ratio of(A) 5.75 to 1.0 through the end of the fiscal quarter ending March 31, 2019, (B) 5.50 to 1.0 through the end of the fiscalquarter ending December 31, 2019 and (C) 5.00 to 1.0 thereafter. As of February 14, 2019, we had outstanding borrowingsunder the Credit Agreement of $1.1 billion. Our ability to incur additional debt is also subject to limitations in the Credit Agreement, including certain financialcovenants. Our level of debt could have important consequences to us, including the following: ·our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions orother purposes may not be available or such 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 wouldotherwise be available for operating activities, future business opportunities and distributions; and ·our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or adownturn in our business or the economy generally. Additionally, in March 2018, the Issuers co-issued $725.0 million of Senior Notes. The Senior Notes mature in 2026 andaccrue interest at the rate of 6.875% per year. Interest on the Senior Notes is payable semiannually in arrears on April 1 andOctober 1. Our ability to service our debt will depend upon, among other things, our future financial and operating performance,which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some ofwhich are beyond our control. In addition, our ability to service our debt under the Credit Agreement could be impacted bymarket interest rates, as all of our outstanding borrowings under the Credit Agreement are subject to variable interest ratesthat fluctuate with changes in market interest rates. A substantial increase in the interest rates21 Table of Contentsapplicable to our outstanding borrowings could have a material negative impact on our cash available for distribution. If ouroperating results are not sufficient to service our current or future indebtedness, we could be forced to take actions such asreducing the level of distributions on our common units, curtailing or delaying our business activities, acquisitions,investments or capital expenditures, selling assets, restructuring or refinancing our debt or seeking additional equity capital.We may be unable to effect any of these actions on terms satisfactory to us or at all. The terms of the Credit Agreement and the Indenture restrict our current and future operations, particularly our abilityto respond to changes or to take certain actions, may limit our ability to pay distributions and may limit our ability tocapitalize on acquisitions and other business opportunities. The Credit Agreement and the Indenture governing the Senior Notes contain a number of restrictive covenants thatimpose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in ourlong-term best interest, including restrictions on our ability to: ·incur additional indebtedness; ·pay dividends or make other distributions or repurchase or redeem equity interests; ·prepay, redeem or repurchase certain debt; ·issue certain preferred units or similar equity securities; ·make investments; ·sell assets; ·incur liens; ·enter into transactions with affiliates; ·alter the businesses we conduct; ·enter into agreements restricting our subsidiaries’ ability to pay dividends; and ·consolidate, merge or sell all or substantially all of our assets. In addition, the Credit Agreement contains certain operating and financial covenants and requires us to maintainspecified financial ratios and satisfy other financial condition tests. Our ability to comply with those covenants and meetthose financial ratios and tests can be affected by events beyond our control, including prevailing economic, financial andindustry conditions. If market or other conditions deteriorate, our ability to comply with these covenants may be impaired. A breach of the covenants or restrictions under the Credit Agreement or the Indenture could result in an event of default,in which case a significant portion of our indebtedness may become immediately due and payable and any other debt towhich a cross-acceleration or cross-default provision applies may also be accelerated, our lenders’ commitment to makefurther loans to us may terminate, and we may be prohibited from making distributions to our unitholders. We might nothave, or be able to obtain, sufficient funds to make these accelerated payments. If we were unable to repay amounts due andpayable under the Credit Agreement, those lenders could proceed against the collateral securing that indebtedness. We maynot be able to replace the Credit Agreement, or if we are, any subsequent replacement of the Credit Agreement or any newindebtedness could be equally or more restrictive. These restrictions may negatively affect our ability to grow in accordance with our strategy. In addition, our financialresults, substantial indebtedness and credit ratings could adversely affect the availability and terms of our22 Table of Contentsfinancing. Please read Part II, Item 7 (“Management’s Discussion and Analysis of Financial Condition and Results ofOperations—Liquidity and Capital Resources—Revolving Credit Facility and— Senior Notes”). The Preferred Units have rights, preferences and privileges that are not held by, and are preferential to the rights of,holders of our common units. The Preferred Units rank senior to all of our other classes or series of equity securities with respect to distribution rightsand rights upon liquidation. These preferences could adversely affect the market price for our common units, or could make itmore difficult for us to sell our common units in the future. In addition, distributions on the Preferred Units accrue and are cumulative, at the rate of 9.75% per annum on theoriginal issue price, which amounts to a quarterly distribution of $24.375 per Preferred Unit. If we do not pay the requireddistributions on the Preferred Units, we will be unable to pay distributions on our common units. Additionally, becausedistributions on the Preferred Units are cumulative, we will have to pay all unpaid accumulated distributions on the PreferredUnits before we can pay any distributions on our common units. Also, because distributions on our common units are notcumulative, if we do not pay distributions on our common units with respect to any quarter, our common unitholders will notbe entitled to receive distributions covering any prior periods if we later recommence paying distributions on our commonunits. The Preferred Units are convertible into common units by the holders of the Preferred Units or by us in certaincircumstances. Our obligation to pay distributions on the Preferred Units, or on the common units issued following theconversion of the Preferred Units, could impact our liquidity and reduce the amount of cash flow available for workingcapital, capital expenditures, growth opportunities, acquisitions, and other general Partnership purposes. Our obligations tothe holders of the Preferred Units could also limit our ability to obtain additional financing or increase our borrowing costs,which could have an adverse effect on our financial condition. See Note 11 to our consolidated financial statements. Restrictions in the Partnership Agreement related to the Preferred Units may limit our ability to make distributions to ourcommon unitholders and our ability to capitalize on acquisition and other business opportunities. The operating and financial restrictions and covenants in the Partnership Agreement related to the Preferred Units couldrestrict our ability to finance future operations or capital needs or to expand or pursue our business activities. The PartnershipAgreement restricts or limits our ability (subject to certain exceptions) to: ·pay distributions on any junior securities, including our common units, prior to paying the quarterly distributionpayable to the holders of the Preferred Units, including any previously accrued and unpaid distributions; ·issue any securities that rank senior to or pari passu with the Preferred Units; however, we will be able to issue anunlimited number of securities ranking junior to the Preferred Units, including junior preferred units and additionalcommon units; and ·incur Indebtedness (as defined in the Credit Agreement) if, after giving pro forma effect to such incurrence, theLeverage Ratio (as defined in the Credit Agreement) determined as of the last day of the most recently ended fiscalquarter would exceed 6.5x, subject to certain exceptions. A prolonged downturn in the economic environment could cause an impairment of goodwill or other intangible assets andreduce our earnings. We have recorded $619.4 million of goodwill and $392.6 million of other intangible assets as of December 31, 2018.Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separatelymeasurable intangible net assets. Generally accepted accounting principles of the United States (“GAAP”) requires us to testgoodwill 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 of23 Table of Contentsour estimates of future cash flows and growth rates in our business. These events could cause us to record impairments ofgoodwill or other intangible assets. If we determine that any of our goodwill or other intangible assets are impaired, we will be required to take an immediatecharge to earnings with a corresponding reduction of partners’ capital resulting in an increase in balance sheet leverage asmeasured by debt to total capitalization. For example, for the year ended December 31, 2017, the USA CompressionPredecessor recognized a $223.0 million impairment of goodwill (see Note 7 to our consolidated financial statements). Impairment in the carrying value of long-lived assets could reduce our earnings. We have a significant number of long-lived assets on our consolidated balance sheet. Under GAAP, we are required toreview our long-lived assets for impairment when events or circumstances indicate that the carrying value of such assets maynot be recoverable or such assets will no longer be utilized in the operating fleet. 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 dispositionof the asset. If business conditions or other factors cause the expected undiscounted cash flows to decline, we may berequired to record non-cash impairment charges. Events and conditions that could result in impairment in the value of ourlong-lived assets include changes in the industry in which we operate, competition, advances in technology, adverse changesin the regulatory environment, or other factors leading to a reduction in our expected long-term profitability. For example,during the fiscal year ended December 31, 2018, we evaluated the future deployment of our idle fleet under then-currentmarket conditions and determined to retire and re-utilize key components of 103 compressor units, or approximately 33,000horsepower, that were previously used to provide services in our business. As a result, we recognized impairments of $8.7million during the year ended December 31, 2018. The USA Compression Predecessor did not recognize any impairment oflong-lived assets during the years ended December 31, 2017 or 2016. Our ability to manage and grow our business effectively may be adversely affected if we lose key management oroperational personnel. We depend on the continuing efforts of our executive officers and the departure of any of our executive officers couldhave a significant negative effect on our business, operating results, financial condition and on our ability to competeeffectively in the marketplace. Additionally, our ability to hire, train and retain qualified personnel will continue to be important and could becomemore challenging as we grow and to the extent energy industry market conditions are competitive. When general industryconditions are favorable, the competition for experienced operational and field technicians increases as other energy andmanufacturing companies’ needs for the same personnel increases. Our ability to grow or even to continue our current levelof service to our current customers could be adversely impacted if we are unable to successfully hire, train and retain theseimportant personnel. We depend on a limited number of suppliers and are vulnerable to product shortages and price increases, which could havea negative impact on our results of operations. The substantial majority of the components for our natural gas compression equipment are supplied by Caterpillar Inc.,Cummins Inc. and Arrow Engine Company for engines, Air-X-Changers and Alfa Laval (US) for coolers, and ArielCorporation, GE Oil & Gas Gemini products and Arrow Engine Company for compressor frames and cylinders. Our relianceon these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply ofrequired components in a timely manner. We also rely primarily on four vendors, A G Equipment Company, AlegacyEquipment, LLC, Standard Equipment Corp. and Genis Holdings LLC, to package and assemble our compression units. Wedo not have long-term contracts with these suppliers or packagers, and a partial or complete loss of any of these sources couldhave a negative impact on our results of operations and could damage our customer relationships. Some of these suppliersmanufacture the components we purchase in a single facility, and any damage to that facility could lead to significant delaysin delivery of completed compression units to us. 24 Table of ContentsWe are subject to substantial environmental regulation, and changes in these regulations could increase our costs orliabilities. We are subject to stringent and complex federal, state and local laws and regulations, including laws and regulationsregarding the discharge of materials into the environment, emissions controls and other environmental protection andoccupational health and safety concerns, as discussed in detail in Item 1 (“Business—Our Operations—Environmental andSafety Regulations”). Environmental laws and regulations may, in certain circumstances, impose strict liability forenvironmental contamination, which may render us liable for remediation costs, natural resource damages and other damagesas 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 landowners and other third parties to file claims for personal injury, property damage and recovery of response costs. Remediationcosts and other damages arising as a result of environmental laws and regulations, and costs associated with new information,changes in existing environmental laws and regulations or the adoption of new environmental laws and regulations could besubstantial and could negatively impact our financial condition or results of operations. Moreover, failure to comply withthese environmental laws and regulations may result in the imposition of administrative, civil and criminal penalties and theissuance of injunctions delaying or prohibiting operations. We conduct operations in a wide variety of locations across the continental U.S. These operations require U.S. federal,state or local environmental permits or other authorizations. Our operations may require new or amended facility permits orlicenses from time to time with respect to storm water discharges, waste handling or air emissions relating to equipmentoperations, which subject us to new or revised permitting conditions that may be onerous or costly to comply with.Additionally, the operation of compression units may require individual air permits or general authorizations to operateunder various air regulatory programs established by rule or regulation. These permits and authorizations frequently containnumerous compliance requirements, including monitoring and reporting obligations and operational restrictions, such asemissions limits. Given the wide variety of locations in which we operate, and the numerous environmental permits and otherauthorizations that are applicable to our operations, we may occasionally identify or be notified of technical violations ofcertain requirements existing under various permits or other authorizations. We could be subject to penalties for anynoncompliance in the future. In our business, we routinely deal with natural gas, oil and other petroleum products at our worksites. Hydrocarbons orother hazardous substances or wastes may have been disposed or released on, under or from properties used by us to providecompression services or inactive compression unit storage or on or under other locations where such substances or wasteshave been taken for disposal. These properties may be subject to investigatory, remediation and monitoring requirementsunder federal, state and local environmental laws and regulations. The modification or interpretation of existing environmental laws or regulations, the more vigorous enforcement ofexisting environmental laws or regulations, or the adoption of new environmental laws or regulations may also negativelyimpact oil and natural gas exploration and production, gathering and pipeline companies, including our customers, which inturn could have a negative impact on us. New regulations, proposed regulations and proposed modifications to existing regulations under the Clean Air Act, ifimplemented, could result in increased compliance costs. New regulations or proposed modifications to existing regulations under the Clean Air Act (“CAA”), as discussed indetail in Item 1 (“Business—Our Operations—Environmental and Safety Regulations”), may lead to adverse impacts on ourbusiness, financial condition, results of operations, and cash available for distribution. For example, in 2015, the EPAfinalized a rule strengthening the primary and secondary National Ambient Air Quality Standards (“NAAQS”) for groundlevel ozone, both of which are 8-hour concentration standards of 70 parts per billion. After the EPA revises a NAAQSstandard, the states are expected to establish revised attainment/non-attainment regions. State implementation of the revisedNAAQS could result in stricter permitting requirements, delay or prohibit our customers’ ability to obtain such permits, andresult in increased expenditures for pollution control equipment, which could negatively impact our customers’ operations,increase the cost of additions to property, plant, and equipment, and negatively impact our business. 25 Table of ContentsIn 2012, the EPA finalized rules that establish new air emissions controls for oil and natural gas production and naturalgas processing operations. Specifically, the EPA’s rule package included New Source Performance Standards to addressemissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emissions standards to addresshazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rulesestablished 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 thatare hydraulically fractured. In June 2016, the EPA took steps to expand on these regulations when it published New SourcePerformance Standards, known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil andnatural gas sector to reduce methane gas and VOC emissions. These Subpart OOOOa standards would expand the 2012 NewSource Performance Standards by using certain equipment-specific emissions control practices, requiring additional controlsfor pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for naturalgas compressor and booster stations. However, the EPA announced in April 2017 that it intended to reconsider certainaspects of the 2016 New Source Performance Standards, and in May 2017, the EPA issued an administrative stay of keyprovisions of the rule, but was promptly ordered by the D.C. Circuit to implement the rule. The EPA also proposed 60-dayand two-year stays of certain provisions in June 2017 and published a Notice of Data Availability in November 2017 seekingcomment and providing clarification regarding the agency’s legal authority to stay the rule. In March 2018, the EPAfinalized narrow amendments to the rule, and in October 2018, the EPA proposed further reconsideration amendments to therule. Among other things, these amendments would alter fugitive emissions requirements, monitoring frequencies and wellsite pneumatic pump standards. Depending on whether the EPA finalizes these further amendments, Subpart OOOOa and any additional regulation of airemissions from the oil and gas sector could result in increased expenditures for pollution control equipment, which couldimpact our customers’ operations and negatively impact our business. Climate change legislation and regulatory initiatives could result in increased compliance costs. Climate change continues to attract considerable public and scientific attention. Methane, a primary component ofnatural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases (“GHGs”). Inrecent years, the U.S. Congress has considered legislation to reduce GHG emissions. It presently appears unlikely thatcomprehensive climate legislation will be passed in the near future, although energy legislation and other initiatives areexpected to be proposed that may be relevant to GHG emissions issues. For example, such initiatives could include a carbontax or cap and trade program. Further, although Congress has not passed such legislation, almost half of the states have begunto address GHG emissions, primarily through the planned development of emissions inventories or regional GHG cap andtrade programs. Depending on the particular program, we could be required to control GHG emissions or to purchase andsurrender allowances for GHG emissions resulting from our operations. Independent of Congress, and as discussed in detail in Item 1 (“Business—Our Operations—Environmental and SafetyRegulations”), the EPA undertook to adopt regulations controlling GHG emissions under its existing CAA authority. Forexample, in 2015, the EPA published standards of performance for GHG emissions from new power plants. The final ruleestablishes a performance standard for integrated gasification combined cycled units and utility boilers based on the use ofthe best system of emissions reduction that the EPA has determined has been adequately demonstrated for each type of unit.The rule also sets limits for stationary natural gas combustion turbines based on the use of natural gas combined cycletechnology. The EPA also promulgated the Clean Power Plan rule (“CPP”), which is intended to reduce carbon emissionsfrom existing power plants by 32 percent from 2005 levels by 2030. In February 2016, the U.S. Supreme Court granted a stayof the implementation of the CPP, which will remain in effect throughout the pendency of the appeals process, including atthe United States Court of Appeals for the D.C. Circuit and the Supreme Court through any certiorari petition that may begranted. The stay suspends the rule, including the requirement that states must start submitting implementation plans. It isnot yet clear how the courts will ultimately rule on the legality of the CPP. Additionally, in October 2017, the EPA proposedto repeal the CPP, and in August 2018, the EPA proposed the Affordable Clean Energy rule (“ACE”) to replace the CPP. If theeffort to replace the CPP with the ACE is unsuccessful and rules similar to the CPP are upheld to control GHG emissions fromelectric utility generating units, demand for the oil and natural gas our customers produce may decrease. 26 Table of ContentsAlthough it is not currently possible to predict with specificity how any proposed or future GHG legislation, regulation,agreements or initiatives will impact our business, any legislation or regulation of GHG emissions that may be imposed inareas in which we conduct business or on the assets we operate could result in increased compliance or operating costs oradditional operating restrictions or reduced demand for our services, and could have a material adverse effect on ourbusiness, financial condition and results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in Earth’satmosphere may produce climate changes that have significant weather-related effects, such as increased frequency andseverity of storms, droughts, floods and other climatic events. If any of those effects were to occur, they could have anadverse effect on our assets and operations. Also, recent activism directed at shifting funding away from companies withenergy-related assets could result in a reduction of funding for the energy sector overall, which could have an adverse effecton our ability to obtain external financing. Increased regulation of hydraulic fracturing could result in reductions of, or delays in, natural gas production by ourcustomers, which could adversely impact our revenue. A significant portion of our customers’ natural gas production is developed from unconventional sources that requirehydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand andchemicals under pressure into the rock formation to stimulate gas production. Legislation to amend the Safe Drinking WaterAct (“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 thechemical constituents of the fluids used in the fracturing process, have been proposed and the U.S. Congress continues toconsider legislation to amend the SDWA. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPAhaving commenced a multi-year study of the potential environmental impacts of hydraulic fracturing. In December 2016, theEPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final reportconcluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “undersome circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factorsare more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times orareas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water;injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly intogroundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage offracturing wastewater in unlined pits. In addition to the EPA, the Bureau of Land Management (“BLM”) has also promulgated rules to regulate hydraulicfracturing. In 2015, the BLM promulgated new requirements relating to well construction, water management, and chemicaldisclosure for companies drilling on federal and tribal land, but subsequently finalized a rule in December 2017 rescindingthe 2015 rule. This rescission has been challenged, and that litigation is ongoing. If this rescission is not upheld, it couldincrease the costs of operation for our customers who operate on BLM land, and negatively impact our business.Additionally, on November 15, 2016, the BLM also finalized a rule to reduce the flaring, venting and leaking of methanefrom oil and gas operations on federal and Indian lands. The Venting Rule requires operators to use certain technologies andequipment to reduce flaring and to periodically inspect their operations for leaks. The Venting Rule also specifies whenoperators owe the government royalties for flared gas. In December 2017, BLM finalized a decision to delay implementationof key requirements in the Venting Rule for one year. The agency subsequently finalized a rule in September 2018 to revisethe 2016 Venting rule by rescinding certain requirements, such as the requirement to use certain technologies andequipment, as well as the leak detection and repair requirement. The Revised Venting Rule also specifies that the BLM willdefer to the appropriate State or tribal authorities in determining whether royalties are owed for flared gas. Challenges to theVenting Rule and the Revised Venting Rule are pending in court. If the Revised Venting Rule is not upheld, and the VentingRule is fully implemented, it could increase the costs of operations for our customers who operate on BLM land, and in turnnegatively impact our business.State and federal regulatory agencies have also recently focused on a possible connection between the operation ofinjection wells used for oil and gas waste disposal and seismic activity. Similar concerns have been raised that hydraulicfracturing may also contribute to seismic activity. When caused by human activity, such events are called inducedseismicity. Developing research suggests that the link between seismic activity and wastewater disposal may vary by27 Table of Contentsregion, and that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been,the likely cause of induced seismicity. In March 2016, the United States Geological Survey identified six states with the mostsignificant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. Inlight of these concerns, some state regulatory agencies have modified their regulations or issued orders to address inducedseismicity. Increased regulation and attention given to induced seismicity could lead to greater opposition to, and litigationconcerning, oil and gas activities utilizing hydraulic fracturing or injection wells for waste disposal, which could indirectlyimpact our business, financial condition and results of operations. In addition, these concerns may give rise to private tortsuits against our customers from individuals who claim they are adversely impacted by seismic activity they allege wasinduced. Such claims or actions could result in liability to our customers for property damage, exposure to waste and otherhazardous materials, nuisance or personal injuries, and require our customers to expend additional resources or incursubstantial costs or losses. This could in turn adversely affect the demand for our services. We cannot predict the future of any such legislation or tort liability. If additional levels of regulation, restrictions andpermits were required through the adoption of new laws and regulations at the federal or state level or the development ofnew interpretations of those requirements by the agencies that issue the required permits, that could lead to operationaldelays, increased operating costs and process prohibitions that could reduce demand for our compression services, whichwould materially adversely affect our revenue and results of operations. The CDM Acquisition could expose us to additional unknown and contingent liabilities. The CDM Acquisition could expose us to additional unknown and contingent liabilities. We performed due diligence inconnection with the CDM Acquisition and attempted to verify the representations made by ETP in connection therewith, butthere may be unknown and contingent liabilities of which we are currently unaware. ETP has agreed to indemnify us forlosses or claims relating to the operation of the business or otherwise only to a limited extent and for a limited period of time.There is a risk that we could ultimately be liable for obligations relating to the CDM Acquisition for which indemnificationis not available, which could materially adversely affect our business, results of operations and cash flow. 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, malfunctions and failures, and natural disastersthat can result in uncontrollable flows of gas or well fluids, fires and explosions. These risks could expose us to substantialliability for personal injury, death, property damage, pollution and other environmental damages. Our insurance may beinadequate to cover our liabilities. Further, insurance covering the risks we face or in the amounts we desire may not beavailable in the future or, if available, the premiums may not be commercially justifiable. If we were to incur substantialliability and such damages were not covered by insurance or were in excess of policy limits, or if we were to incur liability ata time when we are not able to obtain liability insurance, our business, results of operations and financial condition could beadversely affected. Cybersecurity breaches and other disruptions of our information systems could compromise our information andoperations and expose us to liability, which would cause our business and reputation to suffer. We rely on our information technology infrastructure to process, transmit and store electronic information critical to ourbusiness activities. In recent years, there has been a rise in the number of cyberattacks on other companies’ network andinformation systems by both state-sponsored and criminal organizations, and as a result, the risks associated with such anevent continue to increase. A significant failure, compromise, breach or interruption of our information systems could resultin a disruption of our operations, customer dissatisfaction, damage to our reputation, a loss of customers or revenues andpotential regulatory fines. If any such failure, interruption or similar event results in improper disclosure of informationmaintained in our information systems and networks or those of our customers, suppliers or vendors, including personnel,customer, pricing and other sensitive information, we could also be subject to liability under relevant contractual obligationsand laws and regulations protecting personal data and privacy. Our financial results could also be adversely affected if ourinformation systems are breached or an employee causes our information systems to fail, either as a result of inadvertent erroror by deliberately tampering with or manipulating such systems. 28 Table of ContentsTerrorist attacks, the threat of terrorist attacks or other sustained military campaigns may adversely impact our results ofoperations. The long-term impact of terrorist attacks and the magnitude of the threat of future terrorist attacks on the energy industryin general and on us in particular are not known at this time. Uncertainty surrounding sustained military campaigns mayaffect our operations in unpredictable ways, including disruptions of crude oil and natural gas supplies and markets for crudeoil, natural gas and natural gas liquids and the possibility that infrastructure facilities could be direct targets of, or indirectcasualties of, an act of terror. Changes in the insurance markets attributable to terrorist attacks may make insurance againstsuch attacks more difficult for us to obtain, if we choose to do so. Moreover, the insurance that may be available to us may besignificantly more expensive than our existing insurance coverage. Instability in the financial markets resulting fromterrorism or war could also negatively affect our ability to raise capital. If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial resultsaccurately or prevent fraud, which would likely have a negative impact on the market price of our common units. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operatesuccessfully as a publicly traded partnership. Although we continuously evaluate the effectiveness of and improve upon ourinternal controls, 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 underSection 404 of the Sarbanes Oxley Act of 2002 (“Section 404”). For example, Section 404 requires us to, among other things,review and report annually on the effectiveness of our internal control over financial reporting. In addition, our independentregistered public accountants are now required to assess the effectiveness of our internal control over financial reportingsince we ceased to be an emerging growth company under the Jumpstart Our Business Startups Act (the “JOBS Act”) onDecember 31, 2018, which means that we will no longer benefit from the reduced reporting requirements afforded toemerging growth companies under the JOBS Act. 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 andoperation of internal controls over financial reporting, we can provide no assurance as to our independent registered publicaccounting firm’s conclusions about the effectiveness of our internal controls, and we may incur significant costs in ourefforts to comply with Section 404. Ineffective internal controls will subject us to regulatory scrutiny and may result in a lossof confidence in our reported financial information, which could have an adverse effect on our business and would likelyhave a negative effect on the trading 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 the General Partner or its directors. Unlike the holders of common stock in a corporation, our common unitholders have only limited voting rights onmatters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business.Common unitholders have no right to elect the General Partner or the board of directors of the General Partner (the “Board”).ETO is the sole member of the General Partner and has the right to appoint the majority of the members of the Board,including all but one of its independent directors. Also, pursuant to that certain Board Representation Agreement enteredinto by us, the General Partner, ETE and EIG Veteran Equity Aggregator, L.P. (along with its affiliated funds, “EIG”) inconnection with our private placement of Preferred Units and Warrants to EIG, EIG Management Company, LLC has the rightto designate one of the members of the Board for so long as the holders of the Preferred Units hold more than 5% of thePartnership’s outstanding common units in the aggregate (taking into account the common units that would be issuable uponconversion of the Preferred Units and exercise of the Warrants). If our common unitholders are dissatisfied with the General Partner’s performance, they have little ability to remove theGeneral Partner. As a result of these limitations, the price of our common units may decline because of the absence orreduction of a takeover premium in the trading price. Furthermore, the Partnership Agreement contains provisions29 Table of Contentslimiting the ability of common unitholders to call meetings or to obtain information about our operations, as well as otherprovisions limiting our common unitholders’ ability to influence the manner or direction of management. ETO owns and controls the General Partner, and the General Partner has sole responsibility for conducting our businessand managing our operations. The General Partner and its affiliates, including ETO, have conflicts of interest with us andlimited fiduciary duties, and they may favor their own interests to the detriment of us and our unitholders. ETO owns and controls the General Partner and appointed all of the officers and a majority of the directors of the GeneralPartner, some of whom are also officers and directors of ETO. Although the General Partner has a fiduciary duty to manage usin a manner that is beneficial to us and our unitholders, the directors and officers of the General Partner also have a fiduciaryduty to manage the General Partner in a manner that is beneficial to its owner. Conflicts of interest will arise between theGeneral Partner and its owner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts ofinterest, the General Partner may favor its own interests and the interests of its owner over our interests and the interests of ourunitholders. These conflicts include the following situations, among others: ·neither the Partnership Agreement nor any other agreement requires ETO to pursue a business strategy that favors us; ·ETO and its affiliates are not prohibited from engaging in businesses or activities that are in direct competition withus or from offering business opportunities or selling assets to our competitors; ·the General Partner is allowed to take into account the interests of parties other than us, such as its owner, inresolving conflicts of interest; ·the Partnership Agreement limits the liability of and reduces the fiduciary duties owed by the General Partner, andalso restricts the remedies available to our unitholders for actions that, without such limitations, might constitutebreaches of fiduciary duty; ·except in limited circumstances, the General Partner has the power and authority to conduct our business withoutunitholder approval; ·the General Partner determines the amount and timing of asset purchases and sales, borrowings, issuance ofadditional partnership interests and the creation, reduction or increase of reserves, each of which can affect theamount of cash that is distributed to our unitholders; ·the General Partner determines the amount and timing of any capital expenditures and whether a capital expenditureis classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capitalexpenditure, which does not reduce operating surplus. This determination can affect the amount of cash that isdistributed to our unitholders; ·the General Partner determines which costs it incurs are reimbursable by us; ·the General Partner may cause us to borrow funds in order to permit the payment of cash distributions; ·the Partnership Agreement permits us to classify up to $36.6 million as operating surplus, even if it is generated fromasset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus; ·the Partnership Agreement does not restrict the General Partner from causing us to pay it or its affiliates for anyservices rendered to us or entering into additional contractual arrangements with any of these entities on our behalf; 30 Table of Contents·the General Partner currently limits, and intends to continue limiting, its liability for our contractual and otherobligations; ·the General Partner may exercise its right to call and purchase all of our common units not owned by it and itsaffiliates if together those entities at any time own more than 80% of our common units; ·the General Partner controls the enforcement of the obligations that it and its affiliates owe to us; and ·the General Partner decides whether to retain separate counsel, accountants or others to perform services for us. The General Partner’s liability for our obligations is limited. The General Partner has included, and will continue to include, provisions in its and our contractual arrangements thatlimit its liability under such contractual arrangements so that the counterparties to such arrangements have recourse onlyagainst our assets, and not against the General Partner or its assets. The General Partner may therefore cause us to incurindebtedness or other obligations that are nonrecourse to it. The Partnership Agreement provides that any action taken by theGeneral Partner to limit its liability is not a breach of the General Partner’s fiduciary duties, even if we could have obtainedmore favorable terms without such limitation on liability. In addition, we are obligated to reimburse or indemnify the GeneralPartner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments wouldreduce our amount of cash otherwise available for distribution. The Partnership Agreement limits the General Partner’s fiduciary duties to our unitholders. The Partnership Agreement contains provisions that modify and reduce the fiduciary standards to which the GeneralPartner would otherwise be held by state fiduciary duty law. For example, the Partnership Agreement permits the GeneralPartner to make a number of decisions in its individual capacity, as opposed to its capacity as the General Partner, orotherwise free of fiduciary duties to us and our unitholders. This entitles the General Partner to consider only the interests andfactors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting,us, our affiliates or our limited partners. Examples of decisions that the General Partner may make in its individual capacityinclude: ·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 common units it owns; and ·whether or not to consent to any merger or consolidation of the Partnership or amendment to the PartnershipAgreement. By purchasing a unit, a unitholder agrees to become bound by the provisions of the Partnership Agreement, includingthe provisions discussed above. Even if holders of our common units are dissatisfied, they currently cannot remove the General Partner without ETO’sconsent. Common unitholders are currently unable to remove the General Partner because the General Partner and its affiliatesown sufficient number of our common units to prevent its removal. The vote of the holders of at least 662/3% of alloutstanding common units is required to remove the General Partner, and ETO currently owns over 331/3% of ouroutstanding common units. 31 Table of ContentsThe Partnership Agreement restricts the remedies available to holders of our common units for actions taken by theGeneral Partner that might otherwise constitute breaches of fiduciary duty. The Partnership Agreement contains provisions that restrict the remedies available to common unitholders for actionstaken by the General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. Forexample, the Partnership Agreement: ·provides that whenever the General Partner makes a determination or takes, or declines to take, any other action inits capacity as the General Partner, the General Partner is required to make such determination, or take or decline totake such other action, in good faith, and will not be subject to any higher standard imposed by the PartnershipAgreement, Delaware law, or any other law, rule or regulation, or at equity; ·provides that the General Partner will not have any liability to us or our unitholders for decisions made in itscapacity as general partner so long as such decisions are made in good faith, meaning that it believed that thedecisions were in the best interest of the Partnership; ·provides that the General Partner and its officers and directors will not be liable for monetary damages to us, ourlimited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the General Partner or its officersand directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of acriminal matter, acted with knowledge that the conduct was criminal; and ·provides that the General Partner will not be in breach of its obligations under the Partnership Agreement or itsfiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is: (a)approved by the conflicts committee of the Board, although the General Partner is not obligated to seeksuch approval; (b)approved by the vote of a majority of our outstanding common units, excluding any common units ownedby the General Partner and its affiliates; (c)on terms no less favorable to us than those generally being provided to or available from unrelated thirdparties; or (d)fair and reasonable to us, taking into account the totality of the relationships among the parties involved,including other transactions that may be particularly favorable or advantageous to us. In a situation involving a transaction with an affiliate or a conflict of interest, any determination by the General Partnermust be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by ourcommon unitholders or the conflicts committee and the Board determines that the resolution or course of action taken withrespect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in subclauses (c) or (d) above,then it will conclusively be deemed that, in making its decision, the Board acted in good faith. The Partnership Agreement restricts the voting rights of unitholders owning 20% or more of our common units. Common unitholders’ voting rights are further restricted by a provision of the Partnership Agreement providing that anyunits held by a person or group that owns 20% or more of such class of units then outstanding, other than, with respect to ourcommon units, the General Partner, its affiliates, their direct transferees and their indirect transferees approved by the GeneralPartner (which approval may be granted in its sole discretion) and persons who acquired such common units with the priorapproval of the General Partner, cannot vote on any matter.32 Table of ContentsThe general partner interest or the control of the General Partner may be transferred to a third party without unitholderconsent. The General Partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantiallyall of its assets without the consent of the common unitholders. Furthermore, the Partnership Agreement does not restrict theability of ETO to transfer all or a portion of its ownership interest in the General Partner to a third party. The new owner of theGeneral Partner would then be in a position to replace the majority of the Board, and all of the officers, of the General Partnerwith its own designees and thereby exert significant control over the decisions made by the Board and the officers of theGeneral Partner. An increase in interest rates may cause the market price of our common units to decline. The market price of master limited partnership units, like other yield-oriented securities, may be affected by, amongother factors, implied distribution yield. The distribution yield is often used by investors to compare and rank yield-orientedsecurities for investment decision-making purposes. Therefore, increases or decreases in interest rates may affect whether ornot certain investors decide to invest in master limited partnership units, including ours, and a rising interest rateenvironment could have an adverse impact on our common unit price and impair our ability to issue additional equity orincur debt to fund growth or for other purposes, including distributions. We may issue additional limited partner interests without the approval of the common unitholders, which would dilute thecommon unitholders’ existing ownership interests and may increase the risk that we will not have sufficient available cashto maintain or increase our per common unit distribution level. The Partnership Agreement does not limit the number or timing of additional limited partner interests that we may issue,including limited partner interests that are convertible into our common units, without the approval of our commonunitholders. Also, for the first four full calendar quarters following the Transactions Date, we are permitted to pay a portion ofthe quarterly distribution on the Preferred Units with additional Preferred Units, and the Preferred Units are convertible intocommon units in the future at the option of the holders of the Preferred Units, or under certain circumstances, at our option. If a substantial portion of the Preferred Units are converted into common units, common unitholders could experiencesignificant dilution. Furthermore, if holders of such converted Preferred Units were to dispose of a substantial portion of thesecommon units in the public market, whether in a single transaction or series of transactions, it could adversely affect themarket price of our common units. In addition, these sales, or the possibility that these sales may occur, could make it moredifficult for us to sell our common units in the future. Our issuance of additional common units, including pursuant to our Distribution Reinvestment Plan (“DRIP”), or otherequity securities of equal or senior rank, such as additional preferred units, will have the following effects: ·our existing common unitholders’ proportionate ownership interest in us will decrease; ·our amount of cash available for distribution to common unitholders may decrease; ·our ratio of taxable income to distributions may increase; ·the relative voting strength of each previously outstanding common unit may be diminished; and ·the market price of our common units may decline. 33 Table of ContentsETO and the holders of the Preferred Units may sell our common units in the public or private markets, and such salescould have an adverse impact on the trading price of our common units. As of December 31, 2018, ETO holds an aggregate of 46,056,228 common units in us (after giving effect to theconversion of 6,397,965 Class B Units to common units). We have granted certain registration rights to ETO and its affiliateswith respect to any common units they own, and have filed a registration statement with the SEC for the benefit of theholders of the Preferred Units with respect to any common units they may own upon conversion of the Preferred Units orexercise of the Warrants. The sale of these common units in the public or private markets could have an adverse impact onthe price of our common units or on any trading market that may develop. The General Partner has a call right that may require you to sell your common units at an undesirable time or price. If at any time the General Partner and its affiliates own more than 80% of our outstanding common units, the GeneralPartner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but notless than all, of our common units held by unaffiliated persons at a price that is not less than their then-current market price,as calculated pursuant to the terms of the Partnership Agreement. As a result, you may be required to sell your common unitsat an undesirable time or price. You may also incur a tax liability upon a sale of your common units. ETO currently owns anaggregate of approximately 44% of our outstanding common units (before giving effect to the conversion of the Class BUnits into common units). 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 thosecontractual obligations of the partnership that are expressly made without recourse to the general partner. The Partnership isorganized under Delaware law and conducts business in a number of other states, and in some of those states, the limitationson the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearlyestablished. You could be liable for any and all of our obligations as if you were a general partner if a court or governmentalagency were to determine that: ·we were conducting business in a state but had not complied with that particular state’s partnership statute; or ·your right to act with other unitholders to remove or replace the General Partner, to approve some amendments to thePartnership Agreement or to take other actions under the 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. UnderSection 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make adistribution if the distribution would cause our liabilities to exceed the fair value of our assets. The Delaware Act providesthat for a period of three years from the date of an impermissible distribution, limited partners who received the distributionand who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for thedistribution amount. Liabilities to partners on account of their interest in the Partnership and liabilities that are nonrecourseto the Partnership are not counted for purposes of determining whether a distribution is permissible. The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governancerequirements. Our common units are listed on the NYSE. Because we are a publicly traded partnership, the NYSE does not require us tohave a majority of independent directors on the Board or to establish a compensation committee or a nominating andcorporate governance committee. Accordingly, unitholders do not have the same protections afforded to investors in certaincorporations that are subject to all of the NYSE corporate governance requirements. Please read Part III, Item 10 (“Directors,Executive Officers and Corporate Governance”). 34 Table of ContentsTax 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 acorporation for federal income tax purposes, then our cash available for distribution would be substantially reduced. The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treatedas a partnership for federal income tax purposes. We have not requested a ruling from the IRS on this or any other tax matteraffecting us. Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for apartnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe basedupon our current operations that we are or will be so treated, a change in our business or a change in current law could causeus to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxableincome at the corporate tax rate, and would likely pay state and local income tax at varying rates. Distributions wouldgenerally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and noincome, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as acorporation, our cash available for distribution would be substantially reduced. Therefore, if we were treated as a corporationfor 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. The Partnership Agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner thatsubjects us to taxation as a corporation or otherwise subjects us to entity level taxation for federal, state or local income taxpurposes, the level of distributions on our common units may be adjusted to reflect the impact of that law or interpretation onus. If we were subjected to a material amount of additional entity level taxation by individual states, it would reduce our cashavailable for distribution. Changes in current state law may subject us to additional entity level taxation by individual states. Because ofwidespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity leveltaxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to paythe Texas Franchise Tax each year at a maximum effective rate of 0.75% of our “margin”, as defined in the law, apportionedto Texas in the prior year. Imposition of any similar taxes by any other state may substantially reduce the cash available fordistribution 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 potentiallegislative, judicial or administrative 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 commonunits, may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time totime, members of the U.S. Congress have proposed and considered substantive changes to the existing federal income taxlaws that would affect publicly traded partnerships, including a prior legislative proposal that would have eliminated thequalifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for ourtreatment as a partnership for U.S. federal income tax purposes. In addition, the Treasury Department has issued, and in thefuture may issue, regulations interpreting those laws that affect publicly traded partnerships. Although there are no suchcurrent legislative or administrative proposals, there can be no assurance that there will not be further changes to U.S. federalincome tax laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact ourability to qualify as a publicly traded partnership in the future. Any modification to the federal income tax laws may be applied retroactively and could make it more difficult orimpossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal35 Table of Contentsincome tax purposes. We are unable to predict whether any changes or other proposals will ultimately be enacted. Any futurelegislative changes could negatively impact the value of an investment in our common units. You are urged to consult withyour own tax advisor with respect to the status of regulatory or administrative developments and proposals and theirpotential effect on your investment in our common units. Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receiveany cash distributions from us. Because a unitholder will be treated as a partner to whom we will allocate taxable income that could be different inamount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which mayrequire the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxableincome even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal totheir share of our taxable income or even equal to the actual tax liability that results from that income. We may engage in transactions to de-lever the Partnership and manage our liquidity that may result in income and gainto our unitholders. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, youmay be allocated taxable income and gain resulting from the sale. Further, taking advantage of opportunities to reduce ourexisting debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation ofindebtedness income” (also referred to as “COD income”) being allocated to our unitholders as taxable income. Unitholdersmay be allocated COD income, and income tax liabilities arising therefrom may exceed cash distributions. The ultimateeffect of any such allocations will depend on the unitholder’s individual tax position with respect to its units. Unitholders areencouraged to consult their tax advisors with respect to the consequences of potential COD income or other transactions thatmay result in income and gain to unitholders. If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impactedand the cost of any IRS contest will reduce our cash available for distribution. We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income taxpurposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take, and the IRS’spositions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. Acourt may not agree with some or all of the positions we take. Any contest with the IRS, and the outcome of any IRS contest,may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, ourcosts of any contest with the IRS will be borne indirectly by our unitholders and the General Partner because the costs willreduce our cash available for distribution. If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and somestates) may assess and collect any taxes (including any applicable penalties and interest) resulting from such auditadjustments directly from us, in which case our cash available for distribution to our unitholders might be substantiallyreduced. Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes auditadjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicablepenalties and interest) resulting from such audit adjustments directly from us. To the extent possible under the new rules, theGeneral Partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if weare eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited andadjusted return. Although the General Partner may elect to have our unitholders and former unitholders take such auditadjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with theirinterests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible oreffective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from suchaudit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any suchaudit adjustment, we are required to make payments of taxes,36 Table of Contentspenalties and interest, our cash available for distribution to our unitholders might be reduced. These rules are not applicablefor tax years beginning on or prior to December 31, 2017. 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 thedifference between the amount realized and their tax basis in those common units. Because distributions in excess of theirallocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such priorexcess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to theunitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price receivedis less than its original cost. 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 thesale.A substantial portion of the amount realized from a unitholder’s sale of our units, whether or not representing gain, maybe taxed as ordinary income to such unitholder due to potential recapture items, including depreciation recapture. Thus, aunitholder may recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of suchunits is less than such unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the caseof individuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells its units, suchunitholder may recognize ordinary income from our allocations of income and gain to such unitholder prior to the sale andfrom recapture items that generally cannot be offset by any capital loss recognized upon the sale of units. Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us. In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade orbusiness during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31,2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjustedtaxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any businessinterest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, anydeduction allowable for depreciation, amortization, or depletion. Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences tothem. Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirementaccounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizationsthat are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxableincome and will be taxable to them. With respect to taxable years beginning after December 31, 2017, subject to theproposed aggregation rules for certain similarly situated businesses or activities issued by the Treasury Department, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership suchas ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect toeach such trade or business (including for purposes of determining any net operating loss deduction). As a result, for yearsbeginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in ourpartnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exemptentities should consult a tax advisor before investing in our common units.Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning ourunits. Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on incomeeffectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders andany gain from the sale of our units will generally be considered to be “effectively connected” with a U.S.37 Table of Contentstrade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicableeffective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federalincome tax on the gain realized from the sale or disposition of that unit. The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a non-U.S.unitholder’s sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due tochallenges of administering a withholding obligation applicable to open market trading and other complications, the IRS hastemporarily suspended the application of this withholding rule to open market transfers of interests in publicly tradedpartnerships pending promulgation of regulations or other guidance that resolves the challenges. It is not clear if or whensuch regulations or other guidance will be issued. Non-U.S. unitholders should consult a tax advisor before investing in ourcommon units. We treat each purchaser of our common units as having the same tax benefits without regard to the actual common unitspurchased. The IRS may challenge this treatment, which could adversely affect the value of our common units. Because we cannot match transferors and transferees of common units, we have adopted certain methods for allocatingdepreciation and amortization deductions that may not conform to all aspects of existing Treasury Regulations. A successfulIRS challenge to the use of these methods could adversely affect the amount of tax benefits available to you. It also couldaffect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negativeimpact on the value of our common units or result in audit adjustments to your tax returns. We generally prorate our items of income, gain, loss and deduction for federal income tax purposes between transferorsand transferees of our units each month based upon the ownership of our units on the first day of each month, instead of onthe basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change theallocation of items of income, gain, loss and deduction among our unitholders. We generally prorate our items of income, gain, loss and deduction for federal income tax purposes between transferorsand transferees of our units each month based upon the ownership of our units on the first day of each month (the “AllocationDate”), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate (i) certaindeductions for depreciation of capital additions, (ii) gain or loss realized on a sale or other disposition of our assets, and (iii)in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownershipon the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do notspecifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may berequired to change the allocation of items of income, gain, loss and deduction among our unitholders. A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale ofcommon units) may be considered as having disposed of those common units. If so, he would no longer be treated forfederal income tax purposes as a partner with respect to those common units during the period of the loan and mayrecognize gain or loss from the disposition. Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, aunitholder whose common units are the subject of a securities loan may be considered to have disposed of the loanedcommon units. In that case, the unitholder may no longer be treated for federal income tax purposes as a partner with respectto those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss fromsuch disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to thosecommon units may not be reportable by the unitholder and any cash distributions received by the unitholder as to thosecommon units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid therisk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable tomodify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units. 38 Table of ContentsWe have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss anddeduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adverselyaffect the value of our common units. In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determinethe fair market value of our assets. Although we may from time to time consult with professional appraisers regardingvaluation matters, we make many fair market value estimates using a methodology based on the market value of our commonunits as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and theresulting allocations of income, gain, loss and deduction. A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxableincome or loss being allocated to our unitholders. It also could affect the amount of gain recognized from our unitholders’sale of common units, have a negative impact on the value of the common units, or result in audit adjustments to ourunitholders’ tax returns without the benefit of additional deductions. As a result of investing in our common units, you will likely become subject to state and local taxes and income tax returnfiling requirements in jurisdictions where we operate or own or acquire properties. In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes,unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions inwhich we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Ourunitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some orall of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with state andlocal filing requirements. We currently conduct business and control assets in several states, many of which currently impose a personal incometax on individuals. Many of these states also impose an income tax on corporations and other entities. As we makeacquisitions or expand our business, we may control assets or conduct business in additional states or foreign jurisdictionsthat impose a personal income tax. It is your responsibility to file all foreign, federal, state and local tax returns and pay anytaxes due in these jurisdictions. Unitholders should consult with their own tax advisors regarding the filing of such taxreturns, the payment of such taxes, and the deductibility of any taxes paid. 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 compressionunits. As of December 31, 2018, our headquarters consisted of 12,342 square feet of leased space located at 100 CongressAvenue, Austin, Texas 78701. ITEM 3.Legal Proceedings From time to time, we and our subsidiaries may be involved in various claims and litigation arising in the ordinarycourse of business. In management’s opinion, the resolution of such matters is not expected to have a material adverse effecton our consolidated financial position, results of operations or cash flows. ITEM 4.Mine Safety Disclosures None. 39 Table of Contents PART II ITEM 5.Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of EquitySecurities Our Partnership Interests As of February 14, 2019, we had 90,000,504 common units outstanding. ETO owns 100% of the membership interests inthe General Partner. As of February 14, 2019, ETO owned approximately 44% of our outstanding common units (beforegiving effect to the conversion of the Class B Units into common units). As of February 14, 2019, we had outstanding 6,397,965 Class B Units which represent limited partner interests in thePartnership, all of which were held by ETO. Each Class B Unit will automatically be converted into one common unitfollowing the record date attributable to the quarter ending June 30, 2019. Each Class B Unit has all of the rights andobligations of a common unit except the right to participate in distributions made prior to conversion into common units. As of February 14, 2019, we had outstanding 500,000 Preferred Units representing limited partner interests in thePartnership, all of which were held by certain investment funds managed or advised by EIG Global Energy Partners and FSEnergy and Power Fund (collectively, the “Preferred Unitholders”). The Preferred Units rank senior to the common units withrespect to distributions and rights upon liquidation. The Preferred Unitholders are entitled to receive cumulative quarterlydistributions equal to $24.375 per Preferred Unit, which may be paid in cash or, subject to certain limits, a combination ofcash and additional Preferred Units as determined by the General Partner with respect to any quarter ending on or prior toJune 30, 2019. The Preferred Units are convertible, at the option of the Preferred Unitholders, into common units as follows: one third onor after April 2, 2021, two thirds on or after April 2, 2022, and the remainder on or after April 2, 2023. On or after April 2,2023, we have the option to redeem all or any portion of the Preferred Units then outstanding. On or after April 2, 2028, thePreferred Unitholders have the right to require us to redeem all or a portion of the Preferred Units then outstanding, thepurchase price for which we may elect to pay up to 50% in common units, subject to certain additional limits. Our common units, which represent limited partner interests in us, are listed on the New York Stock Exchange (“NYSE”)under the symbol “USAC.” Holders At the close of business on February 14, 2019, based on information received from the transfer agent of the commonunits, we had 58 holders of record of our common units. The number of record holders does not include holders of commonunits held in “street name” or persons, partnerships, associations, corporations or other entities identified in security positionlistings maintained by depositories. There is no established public trading market for the Preferred Units, all of which areowned by the Preferred Unitholders. Please read Part II, Item 8 (“Financial Statements and Supplementary Data—Note 11—Preferred Units and Warrants and –Note 12—Partners’ Capital”). Selected Information from the Partnership Agreement Set forth below is a summary of the significant provisions of the Partnership Agreement that relate to available cash. Available Cash The Partnership Agreement requires that, within 45 days after the end of each quarter, we distribute all of our availablecash to unitholders of record on the applicable record date, first to the holders of the Preferred Units and then to the commonunitholders. The Partnership Agreement generally defines available cash, for each quarter, as cash on hand at the end of aquarter plus cash on hand resulting from working capital borrowings made after the end of the quarter less the amount ofreserves established by the General Partner to provide for the proper conduct of our business, comply with40 Table of Contentsapplicable law, the Credit Agreement or other agreements; and provide funds for distributions to our unitholders for any oneor more of the next four quarters. Working capital borrowings are borrowings made under a credit facility, commercial paperfacility or other similar financing arrangement, and in all cases are used solely for working capital purposes or to paydistributions to partners and with the intent of the borrower to repay such borrowings within twelve months from sourcesother than working capital borrowings. Issuer Purchases of Equity Securities None. Sales of Unregistered Securities; Use of Proceeds from Sale of Securities None. Equity Compensation Plan For disclosures regarding securities authorized for issuance under equity compensation plans, see Part III, Item 12(“Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters”). 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 and the USACompression Predecessor for each of the years in the five-year period ended December 31, 2018, which has been derived fromour audited consolidated financial statements for the years ended December 31, 2018, 2017, 2016 and 2015. The financialdata for the year ended December 31, 2014 is unaudited. For periods prior to the Transactions Date, the table presentsselected financial data for the USA Compression Predecessor and periods after the Transactions Date refer to the Partnership.The following information should be read together with Management’s Discussion and Analysis of Financial Condition andResults of Operations and the Financial Statements contained in Part II, Item 7. Our operating results incorporate a number of significant estimates and uncertainties. Such matters could cause the dataincluded herein not to be indicative of our future financial condition or results of operations. A discussion of our criticalaccounting estimates and how these estimates could impact our future financial condition and results of operations isincluded in “Management's Discussion and Analysis of Financial Condition and Results of Operations” contained in Part II,Item 7 of this report. In addition, a discussion of the risk factors that could affect our business and future financial conditionand results of operations is included under Part I, Item 1A (“Risk Factors”) of this report. Additionally, Note 2 – Basis ofPresentation and Significant Accounting Policies and Note 17 – Commitments and Contingencies under Part II, Item8 (“Financial Statements and Supplementary Data”) of this report provide descriptions of areas where estimates andjudgments and contingent liabilities could result in different amounts being recognized in our accompanying consolidatedfinancial statements. We believe that investors benefit from having access to the same financial measures utilized by management. Thefollowing table includes the non-GAAP financial measures of gross operating margin, Adjusted EBITDA and DistributableCash Flow (or “DCF”). For definitions of gross operating margin, Adjusted EBITDA and DCF, and reconciliations of suchmeasures to their most directly comparable financial measures calculated and presented in accordance with GAAP, pleaseread “Non-GAAP Financial Measures” below.41 Table of Contents Year Ended December 31, 2018 2017 2016 2015 2014 (in thousands, except per unit amounts) Revenues: Contract operations $546,896 $249,346 $239,143 $281,589 $243,371 Parts and service 20,402 10,085 7,921 27,686 56,108 Related party 17,054 17,240 16,873 15,200 20,688 Total revenues 584,352 276,671 263,937 324,475 320,167 Costs of operations: Costs of operations, exclusive of depreciation andamortization 214,724 125,204 112,898 139,301 154,448 Gross operating margin (1) 369,628 151,467 151,039 185,174 165,719 Other operating and administrative costs and expenses: Selling, general and administrative 68,995 24,944 22,739 33,961 23,339 Depreciation and amortization 213,692 166,558 155,134 148,930 134,477 Loss (gain) on disposition of assets 12,964 (367) 120 (603) 986 Impairment of compression equipment 8,666 — — — — Impairment of goodwill — 223,000 — — — Total other operating and administrative costs andexpenses 304,317 414,135 177,993 182,288 158,802 Operating income (loss) 65,311 (262,668) (26,954) 2,886 6,917 Other income (expense): Interest expense, net (78,377) — — — — Other 41 (223) (153) (140) (114) Total other expense (78,336) (223) (153) (140) (114) Net income (loss) before income tax expense (benefit) (13,025) (262,891) (27,107) 2,746 6,803 Income tax expense (benefit) (2,474) 1,843 (163) (1,445) 1,678 Net income (loss) $(10,551) $(264,734) $(26,944) $4,191 $5,125 Adjusted EBITDA (1) $320,475 $130,348 $131,686 $155,045 $145,168 DCF (1) $177,757 $109,326 $123,442 $147,192 $136,774 Basic and diluted net loss per common unit (2) $(0.43) Basic and diluted net loss per Class B Unit (2) $(2.33) Cash distributions declared per common unit (2) $1.575 Other Financial Data: Capital expenditures $241,179 $175,508 $59,234 $249,788 $318,099 Cash flows provided by (used in): Operating activities $226,340 $135,956 $130,063 $164,324 $141,292 Investing activities $(779,663) $(142,458) $(36,767) $(249,805) $(346,869) Financing activities $549,409 $(3,666) $(90,367) $96,733 $205,577 Balance Sheet Data (at period end): Working capital (3) $68,141 $27,091 $62,424 $55,519 $9,550 Total assets $3,774,649 $1,718,953 $1,960,416 $2,102,933 $2,037,977 Long-term debt $1,759,058 $ — $ — $ — $ — Partners' capital and predecessor parent company netinvestment $1,378,856 $1,664,870 $1,929,223 $2,042,996 $1,930,817 (1)Please refer to “—Non-GAAP Financial Measures” below.(2)Earnings per unit is not applicable to the USA Compression Predecessor as the USA Compression Predecessor had no outstandingcommon units prior to the Transactions.(3)Working capital is defined as current assets minus current liabilities. 42 Table of ContentsNon-GAAP Financial Measures Gross Operating Margin The table above includes gross operating margin, which is a non-GAAP financial measure, and a reconciliation tooperating income (loss), its most directly comparable GAAP financial measure. We define gross operating margin as revenueless cost of operations, exclusive of depreciation and amortization expense. We believe that gross operating margin is usefulas a supplemental measure of our operating profitability. Gross operating margin is impacted primarily by the pricing trendsfor service operations and cost of operations, including labor rates for service technicians, volume and per unit costs forlubricant oils, quantity and pricing of routine preventative maintenance on compression units and property tax rates oncompression units. Gross operating margin should not be considered an alternative to, or more meaningful than, operatingincome (loss) or any other measure of financial performance presented in accordance with GAAP. Moreover, gross operatingmargin as presented may not be comparable to similarly titled measures of other companies. Because we capitalize assets,depreciation and amortization of equipment is a necessary element of our costs. To compensate for the limitations of grossoperating margin as a measure of our performance, we believe that it is important to consider operating income (loss)determined under GAAP, as well as gross operating margin, to evaluate our operating profitability. Adjusted EBITDA We define EBITDA as net income (loss) before net interest expense, depreciation and amortization expense, and incometax expense (benefit). We define Adjusted EBITDA as EBITDA plus impairment of compression equipment, impairment ofgoodwill, interest income on capital lease, unit-based compensation expense, severance charges, certain transaction fees, loss(gain) on disposition of assets and other. We view Adjusted EBITDA as one of management’s primary tools for evaluatingour results of operations, and we track this item on a monthly basis both as an absolute amount and as a percentage ofrevenue compared to the prior month, year-to-date, prior year and budget. Adjusted EBITDA is used as a supplementalfinancial measure by our management and external users of our financial statements, such as investors and commercial banks,to assess: ·the financial performance of our assets without regard to the impact of financing methods, capital structure orhistorical 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 offinancing methods and capital structure. We believe that Adjusted EBITDA provides useful information to investors because, when viewed with our GAAP resultsand the accompanying reconciliations, it may provide a more complete understanding of our performance than GAAP resultsalone. We also believe that external users of our financial statements benefit from having access to the same financialmeasures 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 (loss), operatingincome (loss), cash flows from operating activities or any other measure of financial performance or liquidity presented inaccordance with GAAP as measures of operating performance and liquidity. Moreover, our Adjusted EBITDA as presentedmay not be comparable to similarly titled measures of other companies. Because we use capital assets, depreciation, impairment of compression equipment and the interest cost of acquiringcompression equipment are also necessary elements of our costs. Unit-based compensation expense related to equity awardsto employees is also a necessary component of 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 (loss) and netcash provided by operating activities determined under GAAP, as well as Adjusted EBITDA, to evaluate43 Table of Contentsour financial performance and our liquidity. Our Adjusted EBITDA excludes some, but not all, items that affect net income(loss) and net cash provided by operating activities, and these measures may vary among companies. Managementcompensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the most closely comparable GAAPmeasures, understanding the differences between the measures and incorporating this knowledge into their decision makingprocesses. The following table reconciles Adjusted EBITDA to net income (loss) and net cash provided by operating activities, itsmost directly comparable GAAP financial measures, for each of the periods presented (in thousands): Year Ended December 31, 2018 2017 2016 2015 2014Net income (loss) $(10,551) $(264,734) $(26,944) $4,191 $5,125Interest expense, net 78,377 — — — —Depreciation and amortization 213,692 166,558 155,134 148,930 134,477Income tax expense (benefit) (2,474) 1,843 (163) (1,445) 1,678EBITDA $279,044 $(96,333) $128,027 $151,676 $141,280Impairment of compression equipment (1) 8,666 — — — —Impairment of goodwill (2) — 223,000 — — —Interest income on capital lease 709 — — — —Unit-based compensation expense (3) 11,740 4,048 3,539 3,972 2,902Transaction expenses for acquisitions (4) 4,181 — — — —Severance charges 3,171 — — — —Loss (gain) on disposition of assets 12,964 (367) 120 (603) 986Adjusted EBITDA $320,475 $130,348 $131,686 $155,045 $145,168Interest expense, net (78,377) — — — —Income tax expense (benefit) 2,474 (1,843) 163 1,445 (1,678)Interest income on capital lease (709) — — — —Non-cash interest expense 5,080 — — — —Transaction expenses for acquisitions (4,181) — — — —Severance charges (3,171) — — — —Other (2,030) 24 (748) 3,380 2,433Changes in operating assets and liabilities (13,221) 7,427 (1,038) 4,454 (4,631)Net cash provided by operating activities $226,340 $135,956 $130,063 $164,324 $141,292(1)Represents non-cash charges incurred to write down long-lived assets with recorded values that are not expected to be recovered throughfuture cash flows.(2)For further discussion of the goodwill impairment the USA Compression Predecessor recognized for the year ended December 31, 2017,please refer to Item 7 (“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical AccountingPolicies and Estimates—Goodwill Impairment Assessments”).(3)For the year ended December 31, 2018, unit-based compensation expense included $1.3 million of cash payments related to quarterlypayments of distribution equivalent rights on outstanding phantom unit awards and $3.7 million related to the cash portion of anysettlement of phantom unit awards upon vesting. The remainder of the unit-based compensation expense is related to non-cashadjustments to the unit-based compensation liability.(4)Represents certain transaction expenses related to potential and completed acquisitions and other items. We believe it is useful to investorsto exclude these fees. Distributable Cash Flow We define DCF as net income (loss) plus non-cash interest expense, non-cash income tax expense (benefit), depreciationand amortization expense, unit-based compensation expense, impairment of compression equipment, impairment ofgoodwill, certain transaction fees, severance charges, loss (gain) on disposition of assets, proceeds from insurance recoveryand other, less distributions on Preferred Units and maintenance capital expenditures. 44 Table of ContentsWe believe DCF is an important measure of operating performance because it allows management, investors and othersto compare basic cash flows we generate (after distributions on our Preferred Units but prior to any retained cash reservesestablished by the General Partner and the effect of the DRIP) to the cash distributions we expect to pay our commonunitholders. Using DCF, management can quickly compute the coverage ratio of estimated cash flows to planned cashdistributions. DCF should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss),cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP asmeasures of operating performance and liquidity. Moreover, our DCF as presented may not be comparable to similarly titledmeasures of other companies. Because we use capital assets, depreciation and impairment of compression equipment, (gain) loss on disposition ofassets, and maintenance capital expenditures are necessary elements of our costs. Unit-based compensation expense relatedto equity awards to employees is also a necessary component of our business. Therefore, measures that exclude theseelements have material limitations. To compensate for these limitations, we believe that it is important to consider both netincome (loss) and net cash provided by operating activities determined under GAAP, as well as DCF, to evaluate ourfinancial performance and our liquidity. Our DCF excludes some, but not all, items that affect net income (loss) and net cashprovided by operating activities, and these measures may vary among companies. Management compensates for thelimitations of DCF as an analytical tool by reviewing the comparable GAAP measures, understanding the differences betweenthe measures and incorporating this knowledge into their decision making processes. The following table reconciles DCF to net income (loss) and net cash provided by operating activities, its most directlycomparable GAAP financial measures, for each of the periods presented (in thousands): Year Ended December 31, 2018 2017 2016 2015 2014Net income (loss) $(10,551) $(264,734) $(26,944) $4,191 $5,125Non-cash interest expense 5,080 — — — —Non-cash income tax expense (benefit) (2,663) 1,801 (155) (1,461) 1,683Depreciation and amortization 213,692 166,558 155,134 148,930 134,477Unit-based compensation expense (1) 11,740 4,048 3,539 3,972 2,902Impairment of compression equipment (2) 8,666 — — — —Impairment of goodwill (3) — 223,000 — — —Transaction expenses for acquisitions (4) 4,181 — — — —Severance charges 3,171 — — — —Proceeds from insurance recovery 409 — — — —Loss (gain) on disposition of assets 12,964 (367) 120 (603) 986Distributions on Preferred Units (36,430) — — — —Maintenance capital expenditures (5) (32,502) (20,980) (8,252) (7,837) (8,399)DCF $177,757 $109,326 $123,442 $147,192 $136,774Maintenance capital expenditures 32,502 20,980 8,252 7,837 8,399Changes in operating assets and liabilities (13,221) 7,427 (1,038) 4,454 (4,631)Transaction expenses for acquisitions (4,181) — — — —Severance charges (3,171) — — — —Distributions on Preferred Units 36,430 — — — —Other 224 (1,777) (593) 4,841 750Net cash provided by operating activities $226,340 $135,956 $130,063 $164,324 $141,292(1)For the year ended December 31, 2018, unit-based compensation expense includes $1.3 million of cash payments related to quarterlypayments of distribution equivalent rights on outstanding phantom unit awards and $3.7 million related to the cash portion of anysettlement of phantom unit awards upon vesting. The remainder of the unit-based compensation expense is related to non-cashadjustments to the unit-based compensation liability.45 Table of Contents(2)Represents non-cash charges incurred to write down long-lived assets with recorded values that are not expected to be recovered throughfuture cash flows.(3)For further discussion of the goodwill impairment the USA Compression Predecessor recognized for the year ended December 31, 2017,please refer to Item 7 (“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical AccountingPolicies and Estimates—Goodwill Impairment Assessments”).(4)Represents certain transaction expenses related to potential and completed acquisitions and other items. We believe it is useful to investorsto exclude these fees.(5)Reflects actual maintenance capital expenditures for the period presented. Maintenance capital expenditures are capital expenditures madeto maintain the operating capacity of our assets and extend their useful lives, replace partially or fully depreciated assets, or other capitalexpenditures that are incurred in maintaining our existing business and related operating income. Coverage Ratios DCF Coverage Ratio is defined as DCF divided by distributions declared to common unitholders in respect of suchperiod. Cash Coverage Ratio is defined as DCF divided by cash distributions expected to be paid to common unitholders inrespect of such period, after taking into account the non-cash impact of the DRIP. We believe DCF Coverage Ratio and CashCoverage Ratio are important measures of operating performance because they allow management, investors and others togauge our ability to pay cash distributions to common unitholders using the cash flows that we generate. Our DCF CoverageRatio and Cash Coverage Ratio as presented may not be comparable to similarly titled measures of other companies. The following table summarizes our coverage ratios for the periods presented (dollars in thousands): Year Ended December 31, 2018 (4) 2017 (5) 2016 (5) 2015 (5) 2014 (5)DCF $177,757 $109,326 $123,442 $147,192 $136,774 Distributions for DCF coverage ratio (1) $141,699 Distributions reinvested in the DRIP (2) 688 Distributions for Cash Coverage Ratio (3) $141,011 DCF Coverage Ratio 1.25 Cash Coverage Ratio 1.26 (1)Represents distributions to the holders of our common units as of the record date.(2)Represents estimated distributions to holders enrolled in the DRIP as of the record date.(3)Represents cash distributions declared on our common units not participating in the DRIP.(4)Distributions for the year ended December 31, 2018 reflect only three quarters of distributions as the USA Compression Predecessor didnot pay distributions prior to the Transactions Date. DCF, however, reflects a full year of DCF. On a pro forma basis, both the DCFCoverage Ratio and Cash Coverage Ratio for the year ended December 31, 2018 was 1.10x when using comparable three quarters ofDCF and three quarters of distributions.(5)DCF Coverage Ratio and Cash Coverage Ratio are not applicable to the USA Compression Predecessor as the USA CompressionPredecessor had no outstanding common units for each period. 46 Table of Contents ITEM 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations Following the transactions described in further detail below, CDM Resource Management LLC and CDM Environmental& Technical Services LLC, which together represent the CDM Compression Business (the “USA Compression Predecessor”),has been determined to be the historical predecessor of USA Compression Partners, LP (the “Partnership”) for financialreporting purposes. The USA Compression Predecessor is considered the predecessor of the Partnership because EnergyTransfer Equity, L.P. (“ETE”), through its wholly owned subsidiary Energy Transfer Partners, L.L.C., controlled the USACompression Predecessor prior to the transactions described below and obtained control of the Partnership through itsacquisition of USA Compression GP, LLC, the general partner of the Partnership (the “General Partner”). The closing of the Transactions occurred on April 2, 2018 (the “Transactions Date”) and has been reflected in theconsolidated financial statements of the Partnership. In October 2018, ETE and Energy Transfer Partners, L.P. (“ETP”) completed the merger of ETP with a wholly ownedsubsidiary of ETE in a unit-for-unit exchange (the “ETE Merger”). Following the closing of the ETE Merger, ETE changedits name to “Energy Transfer LP” and ETP changed its name to “Energy Transfer Operating, L.P.” (“ETO”). Upon theclosing of the ETE Merger, ETE contributed to ETP 100% of the limited liability company interests in the General Partner.References herein to “ETP” refer to Energy Transfer Partners, L.P. for periods prior to the ETE Merger and ETO followingthe ETE Merger, and references to “ETE” refer to Energy Transfer Equity, L.P. for periods prior to the ETE Merger andEnergy Transfer LP following the ETE Merger. The following discussion and analysis of our financial condition and results of operations should be read inconjunction with our consolidated financial statements, the notes thereto, and the other financial information appearingelsewhere in this report. The following discussion includes forward-looking statements that involve certain risks anduncertainties. See Part I (“Disclosure Regarding Forward-Looking Statements”) and Part I, Item 1A (“Risk Factors”). Allreferences in this section to the USA Compression Predecessor, as well as the terms “our,” “we,” “us” and “its” refer to theUSA Compression Predecessor when used in a historical context or in reference to the periods prior to the TransactionsDate, unless the context otherwise requires or where otherwise indicated. All references in this section to the Partnership, aswell as the terms “our,” “we,” “us” and “its” refer to USA Compression Partners, LP, together with its consolidatedsubsidiaries, including the USA Compression Predecessor, when used in the present or future tense and for periodssubsequent to the Transactions Date, unless the context otherwise requires or where otherwise indicated. Overview We provide compression services in a number of shale plays throughout the U.S., including the Utica, Marcellus,Permian Basin, Delaware Basin, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, Haynesville, Niobrara andFayetteville shales. Demand for our services is driven by the domestic production of natural gas and crude oil; as such, wehave focused our activities in areas of attractive natural gas and crude oil production growth, which are generally found inthese shale and unconventional resource plays. According to studies promulgated by the Energy Information Agency(“EIA”), the production and transportation volumes in these shale plays are expected to increase over the long term due tothe comparatively attractive economic returns versus returns achieved in many conventional basins. Furthermore, thechanges in production volumes and pressures of shale plays over time require a wider range of compression services than inconventional basins. We believe we are well-positioned to meet these changing operating conditions due to the flexibility ofour compression units. While our business focuses largely on compression services serving infrastructure applications,including centralized natural gas gathering systems and processing facilities, which utilize large horsepower compressionunits, typically in shale plays, we also provide compression services in more mature conventional basins, including gas liftapplications on crude oil wells targeted by horizontal drilling techniques. Gas lift, a process by which natural gas is injectedinto the production tubing of an existing producing well, in order to reduce the hydrostatic pressure and allow the oil to flowat a higher rate, and other artificial lift technologies are critical to the enhancement of oil production from horizontal wellsoperating in tight shale plays. 47 Table of ContentsCDM Acquisition and Issuance of Class B Units On the Transactions Date, we consummated the transactions contemplated by the Contribution Agreement dated January15, 2018, pursuant to which, among other things, we acquired all of the issued and outstanding membership interests of theUSA Compression Predecessor from ETP (the “CDM Acquisition”) in exchange for aggregate consideration of approximately$1.7 billion, consisting of (i) 19,191,351 common units representing limited partner interests in us (ii) 6,397,965 Class Bunits representing limited partner interests in us (“Class B Units”) and (iii) $1.2 billion in cash (including customary closingadjustments). General Partner Purchase Agreement On the Transactions Date and in connection with the closing of the CDM Acquisition, we consummated the transactionscontemplated by the Purchase Agreement dated January 15, 2018, by and among ETE, ETP LLC, USA CompressionHoldings, LLC (“USA Compression Holdings”) and, solely for certain purposes therein, R/C IV USACP Holdings, L.P. andETP, pursuant to which, among other things, ETE acquired from USA Compression Holdings (i) all of the outstanding limitedliability company interests in the General Partner and (ii) 12,466,912 common units for cash consideration paid by ETE toUSA Compression Holdings equal to $250.0 million (the “GP Purchase”). Upon the closing of the ETE Merger, ETEcontributed all of the interests in the General Partner and the 12,466,912 common units to ETP. Equity Restructuring Agreement On the Transactions Date and in connection with the closing of the CDM Acquisition, we consummated the transactionscontemplated by the Equity Restructuring Agreement dated January 15, 2018, pursuant to which, among other things, thePartnership, the General Partner and ETE agreed to cancel the Partnership’s Incentive Distribution Rights (“IDRs”) andconvert the General Partner Interest (as defined in the Equity Restructuring Agreement) into a non-economic general partnerinterest, in exchange for the Partnership’s issuance of 8,000,000 common units to the General Partner (the “EquityRestructuring”). The CDM Acquisition, GP Purchase and Equity Restructuring are collectively referred to as the “Transactions.” Series A Preferred Unit and Warrant Private Placement On the Transactions Date, we completed a private placement of $500 million in the aggregate of (i) newly authorized andestablished Preferred Units and (ii) warrants to purchase common units (the “Warrants”) pursuant to a Series A Preferred Unitand Warrant Purchase Agreement dated January 15, 2018, between the Partnership and certain investment funds managed oradvised by EIG Global Energy Partners and FS Energy and Power Fund (collectively, the “Preferred Unitholders”). We issued500,000 Preferred Units with a face value of $1,000 per Preferred Unit and issued two tranches of Warrants to the PreferredUnitholders, which included Warrants to purchase 5,000,000 common units with a strike price of $17.03 per unit and10,000,000 common units with a strike price of $19.59 per unit. The Warrants may be exercised by the holders thereof at anytime beginning April 2, 2019 and before April 2, 2028. 48 Table of ContentsSenior Notes Issuance On March 23, 2018, the Partnership and its wholly-owned subsidiary, USA Compression Finance Corp. (“Finance Corp”),co-issued $725.0 million in aggregate principal amount of the Senior Notes that mature on April 1, 2026. The Senior Notesaccrue interest at the rate of 6.875% per year. Interest on the Senior Notes is payable semi-annually in arrears on April 1 andOctober 1, with the first such payment having occurred on October 1, 2018. On January 14, 2019, the Partnership completed an exchange offer whereby holders of the Senior Notes exchanged all ofthe Senior Notes for an equivalent amount of senior notes registered under the Securities Act of 1933 (the “ExchangeNotes”). The Exchange Notes are substantially identical to the Senior Notes, except that the Exchange Notes have beenregistered with the SEC and do not contain the transfer restrictions, restrictive legends, registration rights or additionalinterest provisions of the Senior Notes. Credit Agreement Amendment and Restatement On the Transactions Date, we entered into the Sixth Amended and Restated Credit Agreement (the “Credit Agreement”)by and among the Partnership, as borrower, USAC OpCo 2, LLC, USAC Leasing 2, LLC, USA Compression Partners, LLC,USAC Leasing, LLC, CDM Resource, CDM E&T and Finance Corp, the lenders party thereto from time to time, JPMorganChase Bank, N.A., as agent and a letter of credit (“LC”) issuer, JPMorgan Chase Bank, N.A., Barclays Bank PLC, RegionsCapital Markets, a division of Regions Bank, RBC Capital Markets and Wells Fargo Bank, N.A., as joint lead arrangers andjoint book runners, Barclays Bank PLC, Regions Bank, RBC Capital Markets and Wells Fargo Bank, N.A., as syndicationagents, and MUFG Union Bank, N.A., SunTrust Bank and The Bank of Nova Scotia, as senior managing agents. The CreditAgreement amended and restated that certain Fifth Amended and Restated Credit Agreement, dated as of December 13, 2013,as amended (the “Fifth A&R Credit Agreement”). The Credit Agreement amended the Fifth A&R Credit Agreement to, among other things, (i) increase the borrowingcapacity under the Credit Agreement from $1.1 billion to $1.6 billion (subject to availability under a borrowing base),(ii) extend the termination date (and the maturity date of the obligations thereunder) from January 6, 2020 to April 2, 2023,(iii) subject to the terms of the Credit Agreement, permit up to $400.0 million of future increases in borrowing capacity,(iv) modify the leverage ratio covenant to be 5.75 to 1.0 through the end of the fiscal quarter ending March 31, 2019, 5.5 to1.0 through the end of the fiscal quarter ending December 31, 2019, and 5.0 to 1.0 thereafter and (v) increase the applicablemargin for eurodollar borrowings to range from 2.00% to 2.75%, depending on our leverage ratio, all as more fully set forthin the Credit Agreement. General Trends and Outlook Natural gas compression is a critical part of the natural gas value chain, facilitating the movement of natural gasthroughout the domestic pipeline system. Our business is driven in part by the increasing volumes of natural gas beingproduced in this country and the areas and conditions in which it is produced. Without compression, natural gas willgenerally not move through a pipeline. A significant amount of our assets are utilized in natural gas infrastructure applications, primarily in centralized naturalgas gathering systems and processing facilities. Rather than being more closely tied to the wellhead impact of commodityprice variability, these applications generally tend to be characterized by a long-term investment horizon on the part of ourcustomers; as such, we have generally experienced stability in rates and higher sustained utilization rates relative to otherbusinesses more tied to drilling activity and wellhead economics. In addition to assets utilized in infrastructure applications,a small portion of our fleet is used for gas lift applications in connection with crude oil production using horizontal drillingtechniques. Increasing levels of domestic natural gas production as a general rule require more installed compression in order tomove the gas through the pipeline system and to the ultimate end user, whether that user be commercial, industrial orresidential in nature. The U.S. Energy Information Administration January 2019 Short-Term Energy Outlook (“EIA Outlook”)expects dry natural gas production to increase to 90.2 billion cubic feet per day (“Bcf/d”) in 2019 (an increase49 Table of Contentsof 8% over the record high production of 83.3 Bcf/d in 2018) and to 92.2 Bcf/d in 2020. The expected growth in natural gasproduction is largely in response to improved drilling efficiency and cost reductions, higher associated gas production fromoil-directed rigs, and increased takeaway pipeline capacity from the highly productive Appalachia and Permian productionregions, which are regions in which we provide compression services. Forecasted natural gas production growth is supportedby planned expansions in liquefied natural gas (“LNG”) capacity and increased pipeline exports to Mexico. The EIAOutlook projects LNG gross exports will increase from 3.0 Bcf/d in 2018 to 5.1 Bcf/d in 2019 and to 6.8 Bcf/d in 2020, asthree new liquefaction projects come online. Also from the EIA Outlook, natural gas pipeline exports to Mexico haveincreased as more infrastructure has been built to transport natural gas both to and within Mexico. U.S. pipeline exports toMexico through October averaged 4.6 Bcf/d, increasing by 10% in 2018 compared with the same period in 2017. Exports toMexico should continue to increase as more natural gas-fired power plants come online in Mexico and more pipelineinfrastructure within Mexico is built. We believe this increasing demand for natural gas will also create increasing demand for compression services, for bothexisting natural gas fields as they age and for the development of new natural gas fields. As such, we expect demand for ourcompression services to continue to increase throughout 2019 although we cannot predict any possible changes in suchdemand with reasonable certainty. Particularly in the Permian and Delaware Basins, natural gas tends to be produced alongside crude oil, and is thus knownas “associated” gas. Due to many factors, the Permian and Delaware Basins have experienced significant activity levels inrecent years, and along with the production of crude oil, the EIA has reported an 81% increase in associated natural gasproduced in those areas since December 2015. Because customers must handle the gas that is produced simultaneously withthe oil, compression has been a critical part of the equation for our customers to be able to produce the desired crude oil andmove it to market. As crude oil production grows in these areas, there will be demand for additional compression to handlethe natural gas. The EIA Outlook forecasts total U.S. crude oil production to average 12.1 million barrels per day (“b/d”) in 2019, up10% from 2018 average production of 10.9 million b/d, which was the highest annual average on record, surpassing theprevious record of 9.6 million b/d set in 1970. Average production in 2020 is expected to increase to 12.9 millionb/d. Increased crude oil production from tight rock formations within the Permian region in Texas and New Mexico accountsfor 0.6 million b/d of the U.S. total growth expected in 2019 and 0.5 million b/d in 2020. The EIA Outlook expects thePermian region to produce 4.8 million b/d of crude oil by the end of 2020, which is about 1.0 million b/d more thanestimated December 2018 levels and would represent about 36% of total U.S. crude oil production at the end of2020. Favorable geology and technological and operational improvements have allowed the Permian to become one of themost economic regions for oil production. The forecasted annual growth rate in 2019 of 0.6 million b/d is 0.4 million b/dslower than in 2018. The flattening of the growth rate reflects increasing pipeline capacity constraints in the Permian region,which is expected to temporarily lower wellhead prices for the region’s oil producers and to have a dampening effect on thePermian’s full production potential in the short term. Pipeline capacity constraints in the Permian are expected to bealleviated in the second half of 2019, with growth expected to accelerate on a monthly basis into 2020. WTI crude oil spotprices are forecast within the EIA Outlook to average $54 per barrel in 2019 and $60 per barrel in 2020, compared with $65per barrel in 2018. Daily and monthly average crude oil prices could vary significantly from annual average forecasts due toglobal economic developments and geopolitical events in the coming months that could have the potential to push oil priceshigher or lower than forecast. Uncertainty remains regarding the duration of, and members’ adherence to, the currentOrganization of the Petroleum Exporting Countries (“OPEC”) production cuts, which could influence prices in eitherdirection. We believe the increase and relative stabilization of crude oil prices allowed for the continued build-out of related large-scale natural gas infrastructure projects, particularly in areas with favorable economics. These projects increased demand forour compression services throughout 2018 as we saw horsepower utilization increase from 87.5% at December 31, 2017 forthe USA Compression Predecessor, to 94.0% at December 31, 2018 for our combined business. We intend to prudently deploy capital for new compressor units in 2019. We have already entered into commitments topurchase all of our large horsepower compressor units in 2019, as the lead time to build these units is approximately one yearor shorter. Most of our 2019 purchases of large horsepower compressor units are already committed to customers or undercontract with customers due to the high demand and limited supply of these units.50 Table of Contents Factors Affecting the Comparability of our Operating Results As described above, the USA Compression Predecessor has been deemed to be the accounting acquirer of the Partnershipin accordance with applicable business combination accounting guidance, and, as a result, the historical financial statementsreflect the balance sheet and results of operations of the USA Compression Predecessor for periods prior to the TransactionsDate. Therefore, the Partnership’s future results of operations may not be comparable to the USA Compression Predecessor’shistorical results of operations for the reasons described below. The revenues generated by the Partnership will consist of the revenues from compression services as well as relatedancillary revenues, including those generated by the USA Compression Predecessor, subsequent to the Transactions Date.The historical revenues included within the Partnership’s financial statements relating to periods prior to the TransactionsDate will only be comprised of those of the USA Compression Predecessor. Additionally, selling, general and administrative expenses will not be comparable to the selling, general andadministrative expenses previously allocated to the USA Compression Predecessor by ETP. The Partnership’s selling, generaland administrative expenses will also not be comparable to the historical USA Compression Predecessor’s selling, generaland administrative expenses because the Partnership’s selling, general and administrative expenses will include the expensesassociated with being a publicly traded master limited partnership whereas the USA Compression Predecessor was operatedas a component of a larger company. In connection with the Transactions, the Partnership and Finance Corp co-issued the Senior Notes and the Partnershipentered into the Credit Agreement. The USA Compression Predecessor held no long-term debt and had no outstandingpublicly traded equity securities. As a result, the Partnership’s long-term debt and related charges will not be comparable tothe USA Compression Predecessor’s historical long-term debt and related charges. We expect ongoing sources of liquidity toinclude cash generated from operating activities, borrowings under the Credit Agreement, and additional issuances of debtand equity securities. During the year ended December 31, 2018, we recorded $4.2 million in transaction expenses, $3.2 million in severanceexpenses and $6.8 million in unit-based compensation expense, all of which related to the CDM Acquisition. Operating Highlights The following table summarizes certain horsepower and horsepower utilization percentages for the periods presented andexcludes certain gas treating assets for which horsepower is not a relevant metric. Year Ended December 31, Percent Change Operating Data: 2018 2017 (9) 2016 (9) 2018 2017 Fleet horsepower (at period end) (1) 3,597,097 1,730,820 1,600,842 107.8%8.1%Total available horsepower (at period end) (2) 3,675,447 1,780,893 1,606,424 106.4%10.9%Revenue generating horsepower (at period end) (3) 3,262,470 1,395,328 1,227,899 133.8%13.6%Average revenue generating horsepower (4) 2,760,029 1,293,864 1,203,487 113.3%7.5%Average revenue per revenue generating horsepower permonth (5) $16.09 $15.84 $16.58 1.6%(4.5)%Revenue generating compression units (at period end) 4,753 2,076 1,789 128.9%16.0%Average horsepower per revenuegenerating compression unit (6) 674 681 668 (1.0)%1.9%Horsepower utilization (7): At period end 94.0% 87.5% 77.7%7.4%12.6%Average for the period (8) 91.9% 82.4% 77.0%11.5%7.0%(1)Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order). As of December 31,2018, we had 131,750 horsepower on order for delivery during 2019.51 Table of Contents(2)Total available horsepower is revenue generating horsepower under contract for which we are billing a customer, horsepower in our fleetthat is under contract but is not yet generating revenue, horsepower not yet in our fleet that is under contract but not yet generatingrevenue and that is subject to a purchase order and idle horsepower. Total available horsepower excludes new horsepower on order forwhich we do not have an executed 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 result of dividing the contractual monthly rate for all units at the end of each month in the period by thesum of the revenue generating horsepower at the end of each month in the period.(6)Calculated as the average of the month-end revenue generating horsepower per revenue generating compression unit for each of themonths in the period.(7)Horsepower utilization is calculated as (i) the sum of (a) revenue generating horsepower, (b) horsepower in our fleet that is undercontract, but is not yet generating revenue and (c) horsepower not yet in our fleet that is under contract, not yet generating revenue andthat is subject to a purchase order, divided by (ii) total available horsepower less idle horsepower that is under repair. Horsepowerutilization based on revenue generating horsepower and fleet horsepower was 90.7%, 80.6% and 76.7% at December 31, 2018, 2017 and2016, respectively.(8)Calculated as the average utilization for the months in the period based on utilization at the end of each month in the period. Averagehorsepower utilization based on revenue generating horsepower and fleet horsepower was 88.0%, 76.9% and 75.9% for the years endedDecember 31, 2018, 2017 and 2016, respectively. (9)Certain historical metrics attributable to the USA Compression Predecessor have been conformed to the Partnership’s calculationmethodology. The 107.8% increase in fleet horsepower as of December 31, 2018 over the fleet horsepower as of December 31, 2017was attributable to the horsepower acquired from the Partnership’s historical assets as well as compression units added to ourfleet to meet incremental demand for our compression services by new and existing customers. The 133.8% increase inrevenue generating horsepower as of December 31, 2018 over December 31, 2017 was primarily due to the addition of thePartnership’s historical assets in addition to organic growth in our large horsepower fleet. The 1.6% increase in averagerevenue per revenue generating horsepower per month for the year ended December 31, 2018 over December 31, 2017 wasprimarily due to contracts on new compression units as well as selective price increases on the existing fleet. The 8.1% increase in fleet horsepower as of December 31, 2017 compared to the fleet horsepower as of December 31,2016 was attributable to new compression units added to the USA Compression Predecessor’s fleet to meet the then-expecteddemand by new and existing customers for compression services. The 13.6% increase in revenue generating horsepower as ofDecember 31, 2017 compared to December 31, 2016 was primarily due to increased customer demand in the Permian,Niobrara and Mid-continent Regions. The 1.9% increase in average horsepower per revenue generating compression unit asof December 31, 2017 compared to December 31, 2016 was primarily due to the redeployment of smaller horsepower unitsthat were previously idle. The 4.5% decrease in average revenue per revenue generating horsepower per month for the yearended December 31, 2017 compared to December 31, 2016 was primarily due to an increase in the average horsepower perrevenue generating compression unit in the current period, resulting from an increase in the number of large horsepowercompression units which typically generate lower average revenue per revenue generating horsepower than do smallhorsepower compression units. The 9.5% increase in average horsepower utilization during the year ended December 31, 2018 compared to the yearended December 31, 2017 was primarily attributable to the higher utilization of the Partnership’s historical fleet that wasadded to the USA Compression Predecessor’s fleet during the year ended December 31, 2018, and resulted in a decrease intotal idle horsepower as a percentage of total available horsepower during the year ended December 31, 2018. The 5.4% increase in average horsepower utilization during the year ended December 31, 2017 compared to the yearended December 31, 2016 was primarily attributable to increased customer demand due to increased operating activity in theoil and gas industry. The fluctuation in utilization components also describes the changes in period end horsepowerutilization as of December 31, 2017 compared to December 31, 2016. The 11.1% increase in average horsepower utilization based on revenue generating horsepower and fleet horsepowerduring the year ended December 31, 2018 compared to December 31, 2017 was primarily attributable to the higher52 Table of Contentsutilization of the Partnership’s fleet that was added to the USA Compression Predecessor’s fleet during the year endedDecember 31, 2018, and resulted in an increase in total active horsepower as a percentage of total fleet horsepower during theyear ended December 31, 2018. The 1.0% increase in average horsepower utilization based on revenue generating horsepower and fleet horsepowerduring the year ended December 31, 2017 compared to December 31, 2016 was primarily attributable to increased customerdemand in the Permian, Niobrara and Mid-continent Regions. The overall decrease in idle horsepower is the result ofincreased customer demand as a result of increased operating activity in the oil and gas industry. These factors also describethe variances in period end horsepower utilization based on revenue generating horsepower and fleet horsepower betweenthe year ended December 31, 2017 and the year ended December 31, 2016. Financial Results of Operations Year ended December 31, 2018 compared to the year ended December 31, 2017 The following table summarizes our results of operations for the periods presented (dollars in thousands): Year Ended December 31, Percent 2018 2017 Change Revenues: Contract operations $546,896 $249,346 119.3%Parts and service 20,402 10,085 102.3%Related party 17,054 17,240 (1.1)%Total revenues 584,352 276,671 111.2%Costs and expenses: Cost of operations, exclusive of depreciation and amortization 214,724 125,204 71.5%Gross operating margin 369,628 151,467 144.0%Other operating and administrative costs and expenses: Selling, general and administrative 68,995 24,944 176.6%Depreciation and amortization 213,692 166,558 28.3%Loss (gain) on disposition of assets 12,964 (367) 3,632.4%Impairment of compression equipment 8,666 — *%Impairment of goodwill — 223,000 (100.0)%Total other operating and administrative costs and expenses 304,317 414,135 (26.5)%Operating income (loss) 65,311 (262,668) (124.9)%Other income (expense): Interest expense, net (78,377) — *%Other 41 (223) (118.4)%Total other expense (78,336) (223) *%Net loss before income tax expense (benefit) (13,025) (262,891) (95.0)%Income tax expense (benefit) (2,474) 1,843 (234.2)%Net loss $(10,551) $(264,734) (96.0)%* Not meaningful. Contract operations revenue. During the year ended December 31, 2018, we increased our operational capability andexpanded our geographic footprint as a result of the addition of the Partnership’s historical assets and experienced a year-to-year increase in demand for our compression services driven by increased operating activity in the oil and gas industry,resulting in a $297.6 million increase in our contract operations revenue. The Partnership’s historical assets accounted for$252.1 million of contract operations revenue for the year ended December 31, 2018. Average revenue generatinghorsepower increased 113.3% during the year ended December 31, 2018 over the year ended December 31, 2017 and averagerevenue per revenue generating horsepower per month increased 1.6% from $15.84 for the year ended December 31, 2017 to$16.09 for the year ended December 31, 2018. 53 Table of ContentsParts and service revenue. The $10.3 million increase in parts and service revenue was primarily attributable to anincrease in maintenance work performed on units at our customers’ locations that are outside the scope of our coremaintenance activities and offered as a courtesy to our customers, and freight and crane charges that are directly reimbursableby customers. Demand for retail parts and services fluctuates from period to period based on the varying needs of ourcustomers. Related party revenue. Related party revenue was materially consistent between periods. The related parties of the USACompression Predecessor remain related parties of the Partnership because the USA Compression Predecessor’s ultimateparent company obtained control of the Partnership through its control of the General Partner. Cost of operations, exclusive of depreciation and amortization. The $89.5 million increase in cost of operations wasdriven by (1) a $38.2 million increase in direct expenses, such as parts, fluids and freight expenses, (2) an $18.2 millionincrease in direct labor expenses, (3) a $9.5 million increase in retail parts and service expenses, which have a correspondingincrease in parts and service revenue, (4) a $9.4 million increase in property and other taxes, (5) a $5.5 million increase inoutside maintenance expenses and (6) a $5.2 million increase in vehicle expenses. The increase in direct parts, fluids, labor,property taxes and vehicle expenses is primarily driven by the increase in average revenue generating horsepower during thecurrent period as a result of the addition of the Partnership’s historical assets. The increase in outside maintenance expenseswas due to greater use of third-party labor during 2018. We do not expect to incur significant amounts of outsidemaintenance expense in future periods. Gross operating margin. The $218.2 million increase in gross operating margin was primarily due to an increase inrevenues, partially offset by an increase in cost of operations, exclusive of depreciation and amortization, during the yearended December 31, 2018 due to the addition of the Partnership’s historical assets. Selling, general and administrative expense. The $44.1 million increase in selling, general and administrative expensefor the year ended December 31, 2018 was primarily attributable to (1) a $19.7 million increase in payroll and benefitsexpenses, (2) a $7.7 million increase in unit-based compensation expense, (3) a $5.6 million increase in professional feesexpenses, (4) $4.2 million of non-recurring advisory, legal and accounting fees, all related to the Transactions, (5) $3.0million of severance charges, all related to the Transactions, and (6) a $2.4 million increase in bad debt expense, primarilydue to a $1.8 million recovery of bad debt expense during the year ended December 31, 2017. Payroll and benefits expensesand professional fees increased due to the addition of the Partnership’s historical assets to the USA CompressionPredecessor’s operations. Unit-based compensation expense increased primarily due to the accelerated vesting of certainoutstanding phantom units as a result of the change in control associated with the Transactions along with the difference inthe number of outstanding unvested phantom units of the USA Compression Predecessor as of December 31, 2017 comparedto the Partnership as of December 31, 2018. Depreciation and amortization expense. The $47.1 million increase in depreciation and amortization expense wasprimarily a result of $66.2 million in depreciation and amortization expense attributable to the addition of the Partnership’shistorical assets, which were adjusted to fair value in connection with the Transactions, offset by a $33.8 million decrease indepreciation expense to conform the useful lives used by the USA Compression Predecessor to those used by the Partnership.The remaining change in depreciation and amortization expense was primarily related to an increase in the USACompression Predecessor’s gross property and equipment balances during the year ended December 31, 2018 compared togross balances during the year ended December 31, 2017. Loss (gain) on disposition of assets. The $13.0 million net loss on disposition of assets during the year ended December31, 2018 was primarily attributable to disposals of various property and equipment by the USA Compression Predecessorprior to the Transactions Date. Impairment of compression equipment. The $8.7 million impairment charge during the year ended December 31, 2018was primarily a result of our evaluation of the future deployment of our idle fleet under then-current market conditions. Ourevaluation determined that due to certain performance characteristics of the impaired equipment, such as excessivemaintenance costs and the inability of the equipment to meet then-current emissions standards without excessive retrofittingcosts, this equipment was unlikely to be accepted by customers under then-current market conditions. As a result of ourevaluation during the year ended December 31, 2018, we determined to retire and re-utilize54 Table of Contentsthe key components of 103 compression units, with a total of approximately 33,000 horsepower that had been previouslyused to provide compression services in our business. Impairment of goodwill. The USA Compression Predecessor recognized a $223.0 million impairment on goodwillduring the year ended December 31, 2017 as a result of its annual goodwill impairment test, for which the USA CompressionPredecessor’s management determined its fair value using a weighted combination of the discounted cash flow method andthe guideline company method. Additionally, the USA Compression Predecessor considered the presence and probability ofsubsequent events on market transactions in estimating the fair value of the company, such as the Transactions discussed inNote 1 to our consolidated financial statements. There was no impairment of goodwill during the year ended December 31,2018. Interest expense, net. The $78.4 million increase in interest expense, net was primarily attributable to interest expenseincurred on the Senior Notes and outstanding borrowings under the Credit Agreement for which there were no comparableborrowings by the USA Compression Predecessor in the prior period. The interest rate on the Credit Agreement was 4.97% atDecember 31, 2018, and the weighted-average interest rate was 4.69% for the period from the Transactions Date to December31, 2018. Average outstanding borrowings under the Credit Agreement was $984.7 million for the period from theTransactions Date to December 31, 2018. Income tax expense (benefit). During the year ended December 31, 2018, we recorded an income tax benefit of $2.5million, primarily related to a decrease in the deferred tax expense booked for the Texas Franchise Tax accrual, while duringthe year ended December 31, 2017, the USA Compression Predecessor recorded an income tax expense of $1.8 million,resulting from an increase in the deferred tax expense booked for the Texas Franchise Tax accrual. Year ended December 31, 2017 compared to the year ended December 31, 2016 The following table summarizes our results of operations for the periods presented (dollars in thousands): Year Ended December 31, Percent 2017 2016 Change Revenues: Contract operations $249,346 $239,143 4.3%Parts and service 10,085 7,921 27.3%Related party 17,240 16,873 2.2%Total revenues 276,671 263,937 4.8%Costs and expenses: Cost of operations, exclusive of depreciation and amortization 125,204 112,898 10.9%Gross operating margin 151,467 151,039 0.3%Other operating and administrative costs and expenses: Selling, general and administrative 24,944 22,739 9.7%Depreciation and amortization 166,558 155,134 7.4%Loss (gain) on disposition of assets (367) 120 (405.8)%Impairment of compression equipment — — *%Impairment of goodwill 223,000 — *%Total other operating and administrative costs and expenses 414,135 177,993 132.7%Operating loss (262,668) (26,954) 874.5%Other income (expense): Interest expense — — *%Other (223) (153) 45.8%Total other expense (223) (153) 45.8%Net loss before income tax expense (benefit) (262,891) (27,107) 869.8%Income tax expense (benefit) 1,843 (163) 1,230.7%Net loss $(264,734) $(26,944) 882.5%* Not meaningful.55 Table of Contents Contract operations revenue. During 2017, the USA Compression Predecessor experienced a year-to-year increase indemand for its compression services driven by increased operating activity in natural gas and crude oil production, resultingin a $10.2 million increase in contract compression and treating revenues. The increase was primarily attributable toincreased customer demand in the Permian, Niobrara and Mid-Continent regions. Parts and service revenue. The $2.2 million increase in installation services revenues was primarily attributable to theconstruction of additional amine plants. Related party revenue. Related party revenues were earned through related party transactions in the ordinary course ofbusiness and at arms’ length with various affiliated entities of ETP, including Regency Intrastate Gas, LP, Edwards LimeGathering LLC and certain wholly owned subsidiaries of ETP. The $0.4 million increase in related party revenues wasprimarily attributable to additional compression service demand from such affiliates. Cost of operations, exclusive of depreciation and amortization. The $12.3 million increase in cost of operations wasprimarily attributable to (1) horsepower growth of approximately 160,000, (2) a corresponding increase in parts and servicerevenue attributable to construction of additional amine plants and (3) an increase in revenue generating horsepower andtreating equipment, labor rates, and the amount of overtime for employees. Gross operating margin. The gross operating margin for the year ended December 31, 2017 was materially consistentwith the year ended December 31, 2016. Selling, general and administrative expense. The $2.2 million increase in general and administrative expense for theyear ended December 31, 2017 was primarily attributable to an increase in salaries, health care, and unit-based compensationexpenses driven by increased headcount and higher health insurance claims. ETP has allocated certain overhead costsassociated with general and administrative services, including salaries and benefits, facilities, insurance,information services, human resources and other support departments to the USA Compression Predecessor. Where costsincurred on the USA Compression Predecessor’s behalf could not be determined by specific identification, the costs wereprimarily allocated to the USA Compression Predecessor based on an average percentage of fixed assets, gross margin,capital, employee costs, and headcount. The USA Compression Predecessor’s management believed these allocations were areasonable reflection of the utilization of services provided. However, the allocations may not fully reflect the expenses thatwould have been incurred had the USA Compression Predecessor been a stand-alone company during the periods presented.During the years ended December 31, 2017 and 2016, ETP allocated general and administrative expenses of $3.6 million and$4.7 million, respectively, to the USA Compression Predecessor. Depreciation and amortization expense. The $11.4 million increase in depreciation and amortization was primarilyrelated to increased make ready cost with a useful life of two years as a result of increased utilization. Loss (gain) on disposition of assets. During the year ended December 31, 2017, the $0.4 million gain was primarilyattributable to the sale of select compression equipment with a sales price greater than book value. During the year endedDecember 31, 2016, the $0.1 million loss was primarily attributable to the sale of select compression equipment with a salesprice less than book value. Goodwill impairment. The $223.0 million impairment on goodwill during the year ended December 31, 2017 was aresult of the USA Compression Predecessor’s annual goodwill impairment test, for which the USA Compression Predecessor’smanagement determined its fair value using a weighted combination of the discounted cash flow method and the guidelinecompany method. Additionally, the USA Compression Predecessor considered the presence and probability of subsequentevents on market transactions in estimating the fair value of the company, such as the Transactions discussed in Note 1 to ourconsolidated financial statements. There was no impairment of goodwill during the year ended December 31, 2016. Income tax expense (benefit). The $2.0 million increase in income tax expense is primarily related to an increase in thedeferred tax expense booked for the Texas Franchise Tax accrual. 56 Table of ContentsOther Financial Data The following table summarizes other financial data for the periods presented (dollars in thousands): Year Ended December 31, Percent Change Other Financial Data: (1) 2018 2017 (3) 2016 (3) 2018 2017 Gross operating margin $369,628 $151,467 $151,039 144.0% 0.3%Gross operating margin percentage (2) 63.3% 54.7% 57.2% 15.7%(4.4)%Adjusted EBITDA $320,475 $130,348 $131,686 145.9%(1.0)%Adjusted EBITDA percentage (2) 54.8% 47.1% 49.9% 16.3%(5.6)%DCF $177,757 $109,326 $123,442 62.6%(11.4)%DCF Coverage Ratio (4) 1.25x Cash Coverage Ratio (4) 1.26x (1)Gross operating margin, Adjusted EBITDA, DCF, DCF Coverage Ratio and Cash Coverage Ratio are all non-GAAP financial measures.Definitions of each measure, as well as reconciliations of each measure to its most directly comparable financial measure(s) calculated andpresented in accordance with GAAP, can be found under the caption “Non-GAAP Financial Measures” in Part II, Item 6.(2)Gross operating margin percentage and Adjusted EBITDA percentage are calculated as a percentage of revenue.(3)Amounts attributed to the USA Compression Predecessor are calculated using the same definitions used by the Partnership. DCFCoverage Ratio and Cash Coverage Ratio are not applicable to the USA Compression Predecessor as the USA Compression Predecessorhad no outstanding common units for each period.(4)Distributions for the year ended December 31, 2018 reflect only three quarters of distributions as the USA Compression Predecessor didnot pay distributions prior to the Transactions Date. DCF, however, reflects a full year of DCF. On a pro forma basis, both the DCFCoverage Ratio and Cash Coverage Ratio for the year ended December 31, 2018 was 1.10x when using comparable three quarters ofDCF and three quarters of distributions. Adjusted EBITDA. The $190.1 million, or 145.9%, increase in Adjusted EBITDA during the year ended December 31,2018 was primarily attributable to the addition of the Partnership’s historical assets which was the primary cause of a $218.2million increase in gross operating margin, offset by a $29.2 million increase in selling, general and administrative expenses,excluding transaction expenses, unit-based compensation expense and other non-recurring charges, during the year endedDecember 31, 2018. The $1.3 million, or 1.0%, decrease in Adjusted EBITDA during the year ended December 31, 2017 was primarilyattributable to a $1.7 million increase in selling, general and administrative expenses, excluding unit-based compensationexpense, offset by a $0.4 million increase in gross operating margin during the year ended December 31, 2017. Distributable Cash Flow. The $68.4 million, or 62.6%, increase in DCF during the year ended December 31, 2018 wasprimarily attributable to the addition of the Partnership’s historical assets which was the primary cause of (1) a $218.2 millionincrease in gross operating margin offset by (2) a $73.3 million increase in cash interest expense, net, (3) $36.4 million ofdistributions on Preferred Units, (4) a $29.2 million increase in selling, general and administrative expenses, excludingtransaction expenses, unit-based compensation expense and other non-recurring charges and (5) an $11.5 million increase inmaintenance capital expenditures during the comparable period. The USA Compression Predecessor had no outstanding debton which cash interest expense was paid in the prior period. The increase in selling, general and administrative expenses andmaintenance capital expenditures was primarily due to additional activity as a result of the combination of the Partnership’slegacy operations with those of the USA Compression Predecessor. The $14.1 million, or 11.4%, decrease in DCF during the year ended December 31, 2017 was primarily due to a $12.7million increase in maintenance capital expenditures and a $1.7 million increase in selling, general and administrativeexpenses, excluding unit-based compensation expense, offset by a $0.4 million increase in gross operating margin duringthe comparable period. Coverage Ratios. Historical coverage ratios are not applicable as the USA Compression Predecessor had no outstandingcommon units for each period. Coverage ratios for the year ended December 31, 2018 reflect a full year of57 Table of ContentsDCF but only three quarters of distributions as the USA Compression Predecessor did not pay any distributions prior to theTransactions Date. Liquidity and Capital Resources Overview We operate in a capital-intensive industry, and our primary liquidity needs are to finance the purchase of additionalcompression units and make other capital expenditures, service our debt, fund working capital, and pay distributions. Ourprincipal sources of liquidity include cash generated by operating activities, borrowings under the Credit Agreement andissuances of debt and equity securities, including under the DRIP. We believe cash generated by operating activities and, where necessary, borrowings under the Credit Agreement will besufficient to service our debt, fund working capital, fund our estimated expansion capital expenditures, fund our maintenancecapital expenditures and pay distributions through 2019. Because we distribute all of our available cash, which excludesprudent operating reserves, we expect to fund any future expansion capital expenditures or acquisitions primarily withcapital from external financing sources, such as borrowings under the Credit Agreement and issuances of debt and equitysecurities, including under the DRIP. To fund a portion of the CDM Acquisition, on March 23, 2018 the Partnership and Finance Corp co-issued $725.0million in aggregate principal amount of the Senior Notes and, on the Transactions Date, the Partnership issued the PreferredUnits and Warrants for aggregate gross consideration of $500.0 million. The transaction fees associated with these issuanceswere financed with borrowings under the Credit Agreement. Also on the Transactions Date, the borrowing capacity under theCredit Agreement was increased from $1.1 billion to $1.6 billion. We are not aware of any regulatory changes or environmental liabilities that we currently expect to have a materialimpact on our current or future operations. Please see “—Capital Expenditures” below. Cash Flows The following table summarizes our sources and uses of cash for the years ended December 31, 2018, 2017 and 2016 (inthousands): Year Ended December 31, 2018 2017 2016Net cash provided by operating activities $226,340 $135,956 $130,063Net cash used in investing activities (779,663) (142,458) (36,767)Net cash provided by (used in) financing activities 549,409 (3,666) (90,367) Net cash provided by operating activities. The $90.4 million increase in net cash provided by operating activities for theyear ended December 31, 2018 was due primarily to a $111.0 million increase in net income, as adjusted for non-cash items,and changes in other working capital. The $5.9 million increase in net cash provided by operating activities for the year ended December 31, 2017 was dueprimarily to net horsepower growth and an increase in treating utilization in 2017. Net cash used in investing activities. Net cash used in investing activities for the year ended December 31, 2018 relatedprimarily to $1.2 billion of cash paid, offset by $710.5 million of cash received, each as part of the CDMAcquisition. Additionally, during the year ended December 31, 2018, net cash used in investing activities of $266.6 millionrelated to purchases of new compression units, reconfiguration costs and related equipment and net cash provided byinvesting activities of $7.5 million and $0.4 million related to proceeds from disposition of property and equipment andproceeds from insurance recoveries, respectively. Net cash used in investing activities for the years ended December 31, 2017 and 2016 related primarily to capitalexpenditures, including net horsepower growth, partially offset by proceeds from asset sales. For the years ended58 Table of ContentsDecember 31, 2017 and 2016, total capital expenditures were $157.3 million and $61.6 million, respectively, and proceedsfrom asset sales were $14.8 million and $24.8 million, respectively. Net cash provided by (used in) financing activities. During the year ended December 31, 2018, we borrowed $230.5million, on a net basis, to support our purchases of new compression units, reconfiguration costs and related equipment aswell as fund certain costs associated with the CDM Acquisition. During the year ended December 31, 2018, we received$479.1 million in net proceeds from the issuance of Preferred Units and Warrants which was used to partially fund the CDMAcquisition and a $28.5 million contribution from the USA Compression Predecessor’s former parent company, ETP.Additionally, and in connection with the CDM Acquisition, we paid various fees of $17.7 million related primarily to theCredit Agreement. During the year ended December 31, 2018, we also paid cash related to the net settlement of unit-basedequity awards under our long-term incentive plan in the amount of $4.4 million, made cash distributions to our commonunitholders of $142.3 million and made cash distributions on the Preferred Units of $24.2 million. For the years ended December 31, 2017 and 2016, net cash used in financing activities reflected the payment of cashdistributions to the USA Compression Predecessor’s former parent company, ETP, of $3.7 million and $90.4 million,respectively. Capital Expenditures The compression services business is capital intensive, requiring significant investment to maintain, expand andupgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate that our capitalrequirements will continue to consist primarily of, the following: ·maintenance capital expenditures, which are capital expenditures made to maintain the operating capacity of ourassets and extend their useful lives, to replace partially or fully depreciated assets, or other capital expenditures thatare incurred in maintaining our existing business and related operating income; and ·expansion capital expenditures, which are capital expenditures made to expand the operating capacity or operatingincome capacity of assets, including by acquisition of compression units or through modification of existingcompression units to increase their capacity, or to replace certain partially or fully depreciated assets that were notcurrently generating operating income. We classify capital expenditures as maintenance or expansion on an individual asset basis. Over the long term, weexpect that our maintenance capital expenditure requirements will continue to increase as the overall size and age of our fleetincreases. Our aggregate maintenance capital expenditures for the years ended December 31, 2018 and 2017 were $32.5million and $21.0 million, respectively. We currently plan to spend approximately $25 million in maintenance capitalexpenditures during 2019, including parts consumed from inventory. Given our growth objectives and anticipated demand from our customers as a result of the increasing natural gas activitydescribed above under the heading “—General Trends and Outlook,” we anticipate that we will continue to make significantexpansion capital expenditures. Without giving effect to any equipment we may acquire pursuant to any future acquisitions,we currently have budgeted between $140 million and $150 million in expansion capital expenditures during 2019. Ourexpansion capital expenditures for the years ended December 31, 2018 and 2017 were $208.7 million and $154.5 million,respectively. Revolving Credit Facility As of December 31, 2018, we were in compliance with all of our covenants under the Credit Agreement. As of December31, 2018, we had outstanding borrowings under the Credit Agreement of $1.1 billion, $550.5 million of borrowing baseavailability and, subject to compliance with the applicable financial covenants, available borrowing capacity of $550.5million. As described in Note 10 to our consolidated financial statements, we entered into the Credit Agreement on theTransactions Date, which amended the Fifth Amended and Restated Credit Agreement to, among other things, (i) increase theborrowing capacity under the Credit Agreement from $1.1 billion to $1.6 billion (subject to59 Table of Contentsavailability under a borrowing base), (ii) extend the termination date (and the maturity date of the obligations thereunder)from January 6, 2020 to April 2, 2023, (iii) subject to the terms of the Credit Agreement, permit up to $400.0 million of futureincreases in borrowing capacity, (iv) modify the leverage ratio covenant to be 5.75 to 1.0 through the end of the fiscal quarterending March 31, 2019, 5.5 to 1.0 through the end of the fiscal quarter ending December 31, 2019, and 5.0 to 1.0 thereafterand (v) increase the applicable margin for eurodollar borrowings to range from 2.00% to 2.75%, depending on our leverageratio, all as more fully set forth in the Credit Agreement. As of February 14, 2019, we had outstanding borrowings of $1.1 billion. We expect to remain in compliance with ourcovenants under the Credit Agreement throughout 2019. If our current cash flow projections prove to be inaccurate, weexpect to be able to remain in compliance with such financial covenants by taking one or more of the following actions:issue debt and equity securities in conjunction with the acquisition of another business; issue equity in a public or privateoffering; request a modification of our covenants from our bank group; reduce distributions from our current distribution rateor obtain an equity infusion pursuant to the terms of the Credit Agreement. For a more detailed description of the Credit Agreement including the covenants and restrictions contained therein,please refer to Note 10 to our consolidated financial statements. Senior Notes See Note 10 to our consolidated financial statements for information regarding the Senior Notes. Distribution Reinvestment Plan During the year ended December 31, 2018, distributions of $0.6 million were reinvested under the DRIP resulting in theissuance of 39,280 common units. Such distributions are treated as non-cash transactions in the accompanying ConsolidatedStatements of Cash Flows included under Part IV, Item 15 of this report. For a more detailed description of the DRIP, please refer to Note 12 to our consolidated financial statements. Total Contractual Cash Obligations The following table summarizes our total contractual cash obligations as of December 31, 2018: Payments Due by Period More than Contractual Obligations Total 1 year 2 - 3 years 4 - 5 years 5 years (in thousands) Long-term debt (1) $1,774,547 $— $ — $1,049,547 $725,000 Interest on long-term debt obligations (2) 591,376 101,964 203,929 169,182 116,302 Equipment/capital purchases (3) 107,457 107,457 — — — Operating and capital lease obligations (4) 7,910 3,773 2,417 1,078 642 Total contractual cash obligations $2,481,290 $213,194 $206,346 $1,219,807 $841,944 (1)We assumed that the amount outstanding under the Credit Agreement at December 31, 2018 would be repaid in April 2023, the maturitydate of the facility. The aggregate principal amount of our Senior Notes outstanding is due April 2026.(2)Represents future interest payments under the Credit Agreement based on the interest rate as of December 31, 2018 of 4.97% and on$725.0 million aggregate principal amount of the Senior Notes.(3)Represents commitments for new compression units that are being fabricated, and is a component of our overall projected expansioncapital expenditures during 2019 of $140 million to $150 million.(4)Represents commitments for future minimum lease payments on noncancelable operating and capital leases. Effects of Inflation. Our revenues and results of operations have not been materially impacted by inflation and changingprices in the past three fiscal years. 60 Table of ContentsOff-Balance Sheet Arrangements We have no off-balance sheet financing activities. Please refer to Note 17 to our consolidated financial statementsincluded in this report for a description of our commitments and contingencies. Critical Accounting Policies and Estimates The discussion and analysis of our financial condition and results of operations is based upon our financial statements.These financial statements were prepared in conformity with GAAP. As such, we are required to make certain estimates,judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statementsand the reported amounts of revenue and expenses during the periods presented. We base our estimates on historicalexperience, available information and various other assumptions we believe to be reasonable under the circumstances. On anongoing basis, we evaluate our estimates; however, actual results may differ from these estimates under different assumptionsor conditions. The accounting policies that we believe require management’s most difficult, subjective or complexjudgments and are the most critical to its reporting of results of operations and financial position are as follows: Revenue Recognition We recognize revenue when obligations under the terms of a contract with our customer are satisfied; generally thisoccurs with the transfer of our services or goods. Revenue is measured at the amount of consideration we expect to receive inexchange for providing services or transferring goods. Sales taxes incurred on behalf of, and passed through to, customers areexcluded from revenue. Incidental items, if any, that are immaterial in the context of the contract are recognized as expense. Contract operations revenue Revenue from contracted compression, station, gas treating and maintenance services is recognized ratably under ourfixed-fee contracts over the term of the contract as services are provided to our customers. Initial contract terms typicallyrange from six months to five years. However, we usually continue to provide compression services at a specific locationbeyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. We primarily enterinto fixed-fee contracts whereby our customers are required to pay our monthly fee even during periods of limited ordisrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the servicemonth, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30days after receipt of our invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which timethey are recognized as revenue. The amount of consideration we receive and revenue we recognize is based upon the fixedfee rate stated in each service contract. Retail parts and services revenue Retail parts and services revenue is earned primarily on freight and crane charges that are directly reimbursable by ourcustomers and maintenance work on units at our customers’ locations that are outside the scope of our core maintenanceactivities. Revenue from retail parts and services is recognized at the point in time the part is transferred or service isprovided and control is transferred to the customer. At such time, the customer has the ability to direct the use of the benefitsof such part or service after we have performed our services. We bill upon completion of the service or transfer of the parts,and payment is generally due 30 days after receipt of our invoice. The amount of consideration we receive and revenue werecognize is based upon the invoice amount. Business Combinations and Goodwill Goodwill acquired in connection with business combinations represents the excess of consideration over the fair valueof net assets acquired. Certain assumptions and estimates are employed in determining the fair value of assets acquired andliabilities assumed. Goodwill is not amortized, but is reviewed for impairment annually based on the carrying values as ofOctober 1, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not berecovered.61 Table of Contents Goodwill—Impairment Assessments We evaluate goodwill for impairment annually on October 1 and whenever events or changes indicate that it is morelikely than not that the fair value of our single business reporting unit could be less than its carrying value (includinggoodwill). The timing of the annual test may result in charges to our statement of operations in our fourth fiscal quarter thatcould not have been reasonably foreseen in prior periods. We estimate the fair value of our reporting unit based on a number of factors, including the potential value we wouldreceive if we sold the reporting unit, enterprise value, discount rates and projected cash flows. Estimating projected cashflows requires us to make certain assumptions as it relates to future operating performance. When considering operatingperformance, various factors are considered such as current and changing economic conditions and the commodity priceenvironment, among others. Due to the imprecise nature of these projections and assumptions, actual results can, and oftendo, differ from our estimates. If the growth assumptions embodied in the current year impairment testing prove inaccurate, wecould incur an impairment charge in the future. As of October 1, 2018, we performed our annual goodwill impairment analysis which included a qualitative assessmentand concluded that it is not more likely than not that the fair value of our single reporting unit was less than its carryingvalue and that our goodwill was not impaired. As a result, we recorded no goodwill impairment charges for the year endedDecember 31, 2018. We had approximately $619.4 million of goodwill recorded on the balance sheet as of December 31,2018. For the year ended December 31, 2017, the USA Compression Predecessor performed a quantitative assessment for itsannual goodwill impairment test and determined its fair value using a weighted combination of the discounted cash flowmethod and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use ofsignificant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins,weighted average costs of capital and future market conditions, among others. The USA Compression Predecessor believedthe estimates and assumptions used in the impairment assessment were reasonable and based on available marketinformation, but variations in any of the assumptions could have resulted in materially different calculations of fair value anddeterminations of whether or not an impairment is indicated. Under the discounted cash flow method, the USA CompressionPredecessor determined fair value based on estimated future cash flows including estimates for capitalexpenditures, discounted to present value using the risk-adjusted industry rate, which reflects the overall level of inherentrisk of the company. Cash flow projections were derived from one year budgeted amounts and five year operating forecastsplus an estimate of later period cash flows, all of which were developed by management. Subsequent period cash flows weredeveloped using growth rates that management believed were reasonably likely to occur. Under the guideline companymethod, the USA Compression Predecessor determined its estimated fair value by applying valuation multiples ofcomparable publicly-traded companies to the projected EBITDA of the company and then averaging that estimate withsimilar historical calculations using a three-year average. In addition, the USA Compression Predecessor estimated areasonable control premium representing the incremental value that accrues to the predecessor’s majority owner from theopportunity to dictate the strategic and operational actions of the business. Additionally, the USA Compression Predecessorconsidered the presence and probability of subsequent events on market transactions in estimating the fair value of thecompany, such as the Transactions discussed in Note 1 to our consolidated financial statements. One key assumption for the measurement of goodwill impairment is management’s estimate of future cash flows andEBITDA. These estimates are based on the annual budget for the upcoming year and forecasted amounts for multiplesubsequent years. The annual budget process is typically completed near the annual goodwill impairment testing date, andmanagement uses the most recent information for the annual impairment tests. The forecast is also subjected to acomprehensive update annually in conjunction with the annual budget process and is revised periodically to reflect newinformation and/or revised expectations. Based on the completion of the annual goodwill impairment testing as described above, the USA CompressionPredecessor recorded a $223.0 million impairment for the year ended December 31, 2017. The USA Compression62 Table of ContentsPredecessor had approximately $253.4 million of goodwill remaining on the balance sheet as of December 31, 2017following this impairment. There was no goodwill impairment for the year ended December 31, 2016. As discussed above, estimates of fair value can be affected by a variety of external and internal factors. Volatility incrude oil prices can cause disruptions in global energy industries and markets. Potential events or circumstances that couldreasonably be expected to negatively affect the key assumptions we used in estimating the fair value of our reporting unitinclude the consolidation or failure of crude oil and natural gas producers, which may result in a smaller market for servicesand may cause us to lose key customers, and cost-cutting efforts by crude oil and natural gas producers, which may cause usto lose current or potential customers or achieve less revenue per customer. We continue to monitor the $619.4 millionbalance of goodwill and if the estimated fair value of our reporting unit declines due to any of these or other factors, we maybe required to record future goodwill impairment charges. Long-Lived Assets Long-lived assets, which include property and equipment, and intangible assets, comprise a significant amount of ourtotal assets. Long-lived assets to be held and used by us are reviewed to determine whether any events or changes incircumstances indicate the carrying amount of the asset may not be recoverable. For long-lived assets to be held and used, webase our evaluation on impairment indicators such as the nature of the assets, the future economic benefit of the assets, theconsistency of performance characteristics of compression units in our idle fleet with the performance characteristics of ourrevenue generating horsepower, any historical or future profitability measurements and other external market conditions orfactors that may be present. If such impairment indicators are present or other factors exist that indicate the carrying amountof the asset may not be recoverable, we determine whether an impairment has occurred through the use of an undiscountedcash flows analysis. If an impairment has occurred, we recognize a loss for the difference between the carrying amount andthe 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, the expected net sale proceeds compared to othersimilarly configured fleet units we recently sold, a review of other units recently offered for sale by third parties, or theestimated component value of similar equipment we plan to continue to use. Potential events or circumstances that could reasonably be expected to negatively affect the key assumptions we used inestimating whether or not the carrying value of our long-lived assets are recoverable include the consolidation or failure ofcrude oil and natural gas producers, which may result in a smaller market for services and may cause us to lose key customers,and cost-cutting efforts by crude oil and natural gas producers, which may cause us to lose current or potential customers orachieve less revenue per customer. If our projections of cash flows associated with our units decline, we may have to recordan impairment of compression equipment in future periods. Allowances and Reserves We maintain an allowance for doubtful accounts based on specific customer collection issues and historical experience.The determination of the allowance for doubtful accounts requires us to make estimates and judgments regarding ourcustomers’ ability to pay amounts due. On an ongoing basis, we conduct an evaluation of the financial strength of ourcustomers based on payment history, the overall business climate in which our customers operate and specific identificationof customer bad debt and make adjustments to the allowance as necessary. Our evaluation of our customers’ financialstrength is based on the aging of their respective receivables balance, customer correspondence, financial information andthird-party credit ratings. Our evaluation of the business climate in which our customers operate is based on a review ofvarious publicly-available materials regarding our customers’ industries, including the solvency of various companies in theindustry. Recent Accounting Pronouncements For a discussion on specific recent accounting pronouncements affecting us, please see Note 18 to our consolidatedfinancial statements. 63 Table of Contents 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 naturalgas or crude oil in connection with our services and, accordingly, have no direct revenue exposure to fluctuating commodityprices. However, the demand for our compression services depends upon the continued demand for, and production of,natural gas and crude oil. Natural gas or crude oil prices remaining low over the long-term could result in a decline in theproduction of natural gas or crude oil, which could result in reduced demand for our compression services. We do not intendto hedge our indirect exposure to fluctuating commodity prices. A 1% decrease in average revenue generating horsepower ofour active fleet during the year ended December 31, 2018 would have resulted in a decrease of approximately $5.3 millionand $3.4 million in our revenue and gross operating margin, respectively. Gross operating margin is a non-GAAP financialmeasure. For a reconciliation of gross operating margin to net income (loss), its most directly comparable financial measure,calculated and presented in accordance with GAAP, please read Part II, Item 6 (“—Non-GAAP Financial Measures”). Pleasealso read Part I, Item 1A (“Risk Factors—Risks Related to Our Business—A long-term reduction in the demand for, orproduction of, natural gas or crude oil in the locations where we operate could adversely affect the demand for our services orthe prices we charge for our services, which could result in a decrease in our revenues and cash available for distribution tounitholders”). Interest Rate Risk We are exposed to market risk due to variable interest rates under our financing arrangements. As of December 31, 2018, we had approximately $1.1 billion of variable-rate outstanding indebtedness at a weighted-average interest rate of 4.69%. A 1% increase or decrease in the effective interest rate on our variable-rate outstanding debt asof December 31, 2018 would result in an annual increase or decrease in our interest expense of approximately $10.5 million. For further information regarding our exposure to interest rate fluctuations on our debt obligations, see Note 10 to ourconsolidated financial statements. Although we do not currently hedge our variable rate debt, we may, in the future, hedge allor a portion of such debt. Credit Risk Our credit exposure generally relates to receivables for services provided. If any significant customer of ours should havecredit or financial problems resulting in a delay or failure to repay the amount it owes us, it could have a material adverseeffect on our business, financial condition, results of operations 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. 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 participationof our management, including our principal executive officer and principal financial officer, the effectiveness of the designand operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the ExchangeAct) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to providereasonable assurance that the information required to be disclosed by us in reports64 Table of Contentsthat we file or submit under the Exchange Act is accumulated and communicated to our management, including our principalexecutive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures, andis recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Basedupon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosurecontrols and procedures were effective as of December 31, 2018 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 forus. Our internal control system was designed to provide reasonable assurance regarding the preparation and fair presentationof our published financial statements. There are inherent limitations to the effectiveness of any control system, however well designed, including thepossibility of human error and the possible circumvention or overriding of controls. Further, the design of a control systemmust reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs.Management must make judgments with respect to the relative cost and expected benefits of any specific control measure.The design of a control system also is based in part upon assumptions and judgments made by management about thelikelihood of future events, and there can be no assurance that a control will be effective under all potential futureconditions. As a result, even an effective system of internal control over financial reporting can provide no more thanreasonable assurance with respect to the fair presentation of financial statements and the processes under which they wereprepared. Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2018. Inmaking this assessment, management used the criteria set forth by the 2013 Committee of Sponsoring Organizations of theTreadway Commission in Internal Control — Integrated Framework. Based on this assessment, our management believesthat, as of December 31, 2018, our internal control over financial reporting was effective. Grant Thornton LLP, anindependent registered public accounting firm, has audited the effectiveness of our internal control over financial reportingas of December 31, 2018, as stated in their report, which is included herein. 65 Table of ContentsREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Board of Directors of USA Compression GP, LLC andUnitholders of USA Compression Partners, LP Opinion on internal control over financial reportingWe have audited the internal control over financial reporting of USA Compression Partners, LP (a Delaware limitedpartnership) and subsidiaries (the “Partnership”) as of December 31, 2018, based on criteria established in the 2013 InternalControl—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission(“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reportingas of December 31, 2018, based on criteria established in the 2013 Internal Control—Integrated Framework issued byCOSO.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)(“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2018, andour report dated February 19, 2019 expressed an unqualified opinion on those financial statements.Basis for opinionThe Partnership’s management is responsible for maintaining effective internal control over financial reporting and for itsassessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’sReport on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internalcontrol over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and arerequired to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and theapplicable rules and regulations of the Securities and Exchange Commission and the PCAOB.We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and performthe audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained inall material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing therisk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control basedon the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believethat our audit provides a reasonable basis for our opinion.Definition and limitations of internal control over financial reportingA company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding thereliability of financial reporting and the preparation of financial statements for external purposes in accordance with generallyaccepted accounting principles. A company’s internal control over financial reporting includes those policies and proceduresthat (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions anddispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary topermit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts andexpenditures of the company are being made only in accordance with authorizations of management and directors of thecompany; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, ordisposition of the company’s assets that could have a material effect on the financial statements.Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequatebecause of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate./s/ GRANT THORNTON LLPHouston, TexasFebruary 19, 201966 Table of ContentsChanges 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) and15d-15(f)) during the last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internalcontrol over financial reporting. ITEM 9B.Other Information On February 13, 2019, the Board approved the USA Compression Partners, LP Amended and Restated Annual CashIncentive Plan (the “A&R Bonus Plan”). See “Part III—Item 11. Executive Compensation—Compensation Discussion &Analysis—Annual Cash Incentive Compensation for 2019” for a description of the A&R Bonus Plan; such description doesnot purport to be complete and is qualified by reference to the A&R Bonus Plan, which is filed as Exhibit 10.21 hereto and isincorporated herein by reference.67 Table of Contents PART III ITEM 10.Directors, Executive Officers and Corporate Governance Board of Directors Our general partner, USA Compression GP, LLC (the “General Partner”), manages our operations and activities. As aresult of several transactions (the “Transactions”) that closed on April 2, 2018 (the “Transactions Date”), the General Partneris solely owned by Energy Transfer Operating, L.P. (“ETO”), a wholly owned subsidiary of Energy Transfer LP (“ET” and,collectively with ETO and their affiliates, “Energy Transfer”). The General Partner has a board of directors (the “Board”) thatmanages our business. The Board is not elected by our unitholders and is not subject to re-election on a regular basis in thefuture. As the sole member of the General Partner, ETO is entitled under the limited liability company agreement of theGeneral Partner (the “GP LLC Agreement”) to appoint all directors of the General Partner, subject to rights and restrictionscontained in other agreements. The GP LLC Agreement provides that the Board shall consist of between two and ninepersons, at least two of whom are required to meet the independence standards required of directors who serve on an auditcommittee of a board of directors established by the Securities Exchange Act of 1934, as amended (the “Exchange Act”), andthe rules and regulations of the SEC thereunder, and by the NYSE pertaining to qualification for service on an auditcommittee. Prior to the Transactions Date, the Board was comprised of eight members, and Eric D. Long, our President and ChiefExecutive Officer (“CEO”), is the only director who remained on the Board subsequent to the Transactions Date. Effective asof the Transactions Date, the Board is comprised of nine members, eight of whom were designated by ETO and one of whomwas designated by EIG Management Company, LLC (“EIG Management”) pursuant to that certain Board RepresentationAgreement among us, the General Partner, Energy Transfer Equity, L.P. (whose wholly owned subsidiary, Energy TransferPartners, L.L.C. acquired the General Partner in the Transactions and subsequently contributed it to ETO in connection with amerger among several Energy Transfer entities that closed in October 2018) and EIG Veteran Equity Aggregator, L.P. (alongwith its affiliated funds, “EIG”) on the Transactions Date in connection with our private placement to EIG and FS Energy andPower Fund (“FS Energy”) of Series A Preferred Units in the Partnership (the “Preferred Units”) and warrants to purchasecommon units of the Partnership (the “Warrants”). Under the Board Representation Agreement, EIG Management has theright to designate one member of the Board for so long as EIG and FS Energy own, in the aggregate, more than 5% of thePartnership’s outstanding common units (taking into account the common units issuable upon conversion of the PreferredUnits and exercise of the Warrants). Three members of the Board are independent as defined under the independencestandards established by the NYSE and the SEC. Although the NYSE does not require a publicly traded limited partnershiplike us to have a majority of independent directors on the Board or to establish a compensation committee or a nominatingcommittee, the Board has elected to have a standing compensation committee (the “Compensation Committee”). We do nothave a nominating committee in light of the fact that ETO and EIG currently collectively appoint all of the members of theBoard. Our CEO is currently the only management member of the Board. The non-management members of the Board meet inexecutive session without any members of management present at least twice a year. Mr. William S. Waldheim presides atsuch meetings. Interested parties can communicate directly with non-management members of the Board by mail in care ofthe General Counsel and Secretary at USA Compression Partners, LP, 100 Congress Avenue, Suite 450, Austin, Texas 78701.Such communications should specify the intended recipient or recipients. Commercial solicitations or similarcommunications will not be forwarded to the Board. As a limited partnership, NYSE rules do not require us to seek unitholder approval for the election of any of ourdirectors. We do not have a formal process for identifying director nominees, nor do we have a formal policy regardingconsideration of diversity in identifying director nominees. We believe, however, that the individuals appointed as directorshave experience, skills and qualifications relevant to our business and have a history of service in senior leadership positionswith the qualities and attributes required to provide effective oversight of the Partnership. Independent Directors. The Board has determined that Matthew S. Hartman, Glenn E. Joyce and William S. Waldheimare independent directors under the standards established by the NYSE and the Securities Exchange Act of 1934 (the“Exchange Act”). The Board considered all relevant facts and circumstances and applied the independence68 Table of Contentsguidelines of the NYSE and the Exchange Act in determining that none of these directors has any material relationship withus, our management, the General Partner or its affiliates or our subsidiaries. Mr. Hartman is a Managing Director at EIG, and, since the Transactions Date, EIG owns over 80% of the Preferred Unitsand Warrants in the Partnership. The Board determined that EIG’s ownership of Preferred Units and Warrants did not precludethe independence of Mr. Hartman because (i) the Preferred Units and Warrants do not confer voting rights sufficient toparticipate in the control of the Partnership or influence its management, (ii) the Board Representation Agreement does notgrant to EIG a sufficient number of seats on the Board to significantly influence or control its decision making or materiallyinfluence the management or operation of the Partnership and (iii) the Board has determined that ownership of even asignificant amount of the Partnership’s securities does not, by itself, preclude a finding of independence. In addition, Mr.Hartman serves on the board of directors of one of our customers, Southcross Holdings GP LLC (“Southcross”). During theperiod of Mr. Hartman’s directorship during 2018, Southcross made compression service payments to us of approximately$0.3 million. The Board determined that Mr. Hartman’s relationship with Southcross did not preclude his independence. Prior to the Transactions, the Board included the following directors that it had determined were independent under thestandards established by the NYSE and the Exchange Act: Robert F. End, Jerry L. Peters and Forrest E. Wylie. Mr. Petersserved on the Board from October 2017 until the Transactions Date, and since September 2012, Mr. Peters also served on theboard of directors and the audit committee of one of our customers. During the period of Mr. Peters’ directorship during2018, subsidiaries of this customer made compression service payments to us of approximately $0.3 million. The Boardpreviously determined that Mr. Peters’ relationship with this customer did not preclude his independence. Each of Messrs.End, Peters and Wylie resigned effective the Transactions Date in connection with the Transactions. The Board’s Role in Risk Oversight The Board administers its risk oversight function as a whole and through its committees. It does so in part throughdiscussion and review of our business, financial reporting and corporate governance policies, procedures and practices, withopportunity to make specific inquiries of management. In addition, at each regular meeting of the Board, managementprovides a report of the Partnership’s operational and financial performance, which often prompts questions and feedbackfrom the Board. The audit committee of the Board (the “Audit Committee”) provides additional risk oversight through itsquarterly meetings, where it discusses policies with respect to risk assessment and risk management, reviews contingentliabilities and risks that may be material to the Partnership and assesses major legislative and regulatory developments thatcould materially impact the Partnership’s contingent liabilities and risks. The Audit Committee is also required to discussany material violations of our policies brought to its attention on an ad hoc basis. Additionally, the CompensationCommittee reviews our overall compensation program and its effectiveness at both linking executive pay to performance andaligning the interests of our executives and our unitholders. Committees of the Board of Directors Audit Committee. The Board appoints the Audit Committee, which is comprised solely of directors who meet theindependence and experience standards established by the NYSE and the Exchange Act. The Audit Committee consists ofMessrs. Hartman, Joyce and Waldheim, and Mr. Waldheim serves as chairman of the Audit Committee. The Board determinedthat Mr. Waldheim is an “audit committee financial expert” as defined in Item 407(d)(5)(ii) of SEC Regulation S-K, and thateach of Messrs. Hartman, Joyce and Waldheim is “independent” within the meaning of the applicable NYSE and ExchangeAct rules governing audit committee independence. The Audit Committee assists the Board in its oversight of the integrity ofour financial statements and our compliance with legal and regulatory requirements as well as the effectiveness of ourcorporate policies and internal controls. The Audit Committee has the sole authority to retain and terminate our independentregistered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve anynon-audit services to be rendered by our independent registered public accounting firm. The Audit Committee is alsoresponsible for confirming the independence and objectivity of our independent registered public accounting firm. Ourindependent registered public accounting firm is given unrestricted access to the Audit Committee. 69 Table of ContentsIn April 2018, the Audit Committee recommended that the Board approve an amended and restated Audit Committeecharter (the “A&R Audit Committee Charter”) that is based on Energy Transfer’s audit committee charter, and in May 2018the Board approved the A&R Audit Committee Charter. The A&R Audit Committee Charter is available under the InvestorRelations tab on our website at usacompression.com. We will provide a copy of the A&R Audit Committee Charter to any ofour unitholders without charge upon written request to Investor Relations, 100 Congress Avenue, Suite 450, Austin, TX78701. Compensation Committee. The NYSE does not require a listed limited partnership like us to have a compensationcommittee. However, the Board established the Compensation Committee to, among other things, oversee our compensationprogram described below in Part III, Item 11 “Executive Compensation.” The Compensation Committee consists of Messrs.Joyce and Waldheim and is chaired by Mr. Joyce. The Compensation Committee establishes and reviews general policiesrelated to our compensation and benefits and is responsible for making recommendations to the Board with respect to thecompensation and benefits of the Board. In addition, the Compensation Committee administers the USA CompressionPartners, LP 2013 Long-Term Incentive Plan, as amended and as may be further amended or replaced from time to time (the“LTIP”). In February 2019, the Compensation Committee recommended that the Board approve, and the Board approved, anamended and restated Compensation Committee charter (the “A&R Compensation Committee Charter”) that is based onEnergy Transfer’s compensation committee charter. Under the A&R Compensation Committee Charter, a director serving as amember of the Compensation Committee may not be an officer of or employed by the General Partner, us or our subsidiaries.During 2018, neither Mr. Joyce nor Mr. Waldheim was an officer or employee of Energy Transfer or any of its affiliates, orserved as an officer of any company with respect to which any of our executive officers served on such company’s board ofdirectors. In addition, neither Mr. Joyce nor Mr. Waldheim is a former employee of Energy Transfer or any of its affiliates. The A&R Compensation Committee Charter is available under the Investor Relations tab on our website atusacompression.com. We will provide a copy of the A&R Compensation Committee Charter to any of our unitholderswithout charge upon written request to Investor Relations, 100 Congress Avenue, Suite 450, Austin, TX 78701. Conflicts Committee. As set forth in the GP LLC Agreement, the General Partner may, from time to time, establish aconflicts committee to which the Board will appoint independent directors and which may be asked to review specificmatters that the Board believes may involve conflicts of interest between us, our limited partners and Energy Transfer. Suchconflicts committee will determine the resolution of the conflict of interest in any matter referred to it in good faith. Themembers of the conflicts committee may not be officers or employees of the General Partner or directors, officers oremployees of its affiliates, including Energy Transfer, and must meet the independence and experience standards establishedby the NYSE and the Exchange Act to serve on the Audit Committee, and certain other requirements. Any matters approvedby the conflicts committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of ourpartners and not a breach by the General Partner of any duties it may owe us or our unitholders. Corporate Governance Guidelines and Code of Ethics The Board has adopted Corporate Governance Guidelines (the “Guidelines”) that outline important policies andpractices regarding our governance and provide a framework for the function of the Board and its committees. In February2019, the Board approved certain amendments to the Guidelines to reflect current Board practices since the Transactions.The Board has also adopted a Code of Business Conduct and Ethics (the “Code”) that applies to the General Partner and itssubsidiaries and affiliates, including us, and to all of its and their directors, employees and officers, including its principalexecutive officer, principal financial officer and principal accounting officer. We intend to post any amendments to theCode, or waivers of its provisions applicable to our directors or executive officers, including our principal executive officerand principal financial officer, on our website. The Guidelines and the Code are available under the Investor Relations tab onour website at usacompression.com. We will provide copies of the Guidelines and the Code to any of our unitholders withoutcharge upon written request to Investor Relations, 100 Congress Avenue, Suite 450, Austin, TX 78701. 70 Table of ContentsNote that the preceding internet addresses are for informational purposes only and are not intended to be hyperlinked.Accordingly, no information found on or provided at those internet addresses or on our website in general is intended ordeemed to be incorporated by reference herein. Directors and Executive Officers The following table shows information as of February 14, 2019 regarding the current directors and executive officers ofUSA Compression GP, LLC. Name Age Position with USA Compression GP, LLCEric D. Long 60 President and Chief Executive Officer and DirectorMatthew C. Liuzzi 44 Vice President, Chief Financial Officer and TreasurerWilliam G. Manias 56 Vice President and Chief Operating OfficerDavid A. Smith 56 Vice President and President, Northeast RegionSean T. Kimble 54 Vice President, Human ResourcesChristopher W. Porter 35 Vice President, General Counsel and SecretaryMichael Bradley 64 DirectorChristopher R. Curia 63 DirectorMatthew S. Hartman 38 DirectorGlenn E. Joyce 61 DirectorThomas E. Long 62 DirectorThomas P. Mason 62 DirectorMatthew S. Ramsey 63 DirectorWilliam S. Waldheim 62 Director The directors of the General Partner hold office until the earlier of their death, resignation, removal or disqualification oruntil their successors have been elected and qualified. Officers serve at the discretion of the Board. There are no familyrelationships among any of the directors or executive officers of the General Partner. Eric D. Long has served as our President and CEO since September 2002 and has served as a director of the GeneralPartner since June 2011. Mr. Long co-founded USA Compression in 1998 and has over 35 years of experience in the oil andgas industry. From 1980 to 1987, Mr. Long served in a variety of technical and managerial roles for several major pipelineand oil and natural gas producing companies, including Bass Enterprises Production Co. and Texas Oil & Gas. Mr. Long thenserved in a variety of senior officer level operating positions with affiliates of Hanover Energy, Inc., a company primarilyengaged 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 WiserOil Company, an NYSE listed company from May 2001 until it was sold to Forest Oil Corporation in May 2004. Mr. Longreceived his bachelor’s degree, with honors, in Petroleum Engineering from Texas A&M University. He is a registeredProfessional Engineer in the state of Texas. As a result of his professional background, Mr. Long brings to us executive level strategic, operational and financialskills. These skills, combined with his over 35 years of experience in the oil and natural gas industry, including in particularhis experience in the compression services sector, make Mr. Long a valuable member of the Board. Matthew C. Liuzzi has served as our Vice President, Chief Financial Officer and Treasurer since January 2015. Prior tosuch time, Mr. Liuzzi served as our Senior Vice President – Strategic Development since joining us in April 2013. Mr. Liuzzijoined us after nine years in investment banking, since 2008 at Barclays, where he was most recently a Director in the GlobalNatural Resources Group in Houston. At Barclays, Mr. Liuzzi worked primarily with midstream clients on a variety ofinvestment banking assignments, including initial public offerings, public and private debt and equity offerings, as well asstrategic advisory assignments. He holds a B.A. and an M.B.A., both from the University of Virginia. William G. Manias has served as our Vice President and Chief Operating Officer since July 2013. He served as a directorof the General Partner from February 2013 to July 2013. From October 2009 until January 2013, Mr. Manias71 Table of Contentsserved as Senior Vice President and Chief Financial Officer of Crestwood Midstream Partners LP and its affiliates, where hisgeneral responsibilities included managing the partnership’s financial and treasury activities. Before joining Crestwood inJanuary 2009, Mr. Manias was the Chief Financial Officer of TEPPCO Partners, L.P. starting in January 2006. FromSeptember 2004 until January 2006, he served as Vice President of Business Development and Strategic Planning atEnterprise Products Partners L.P. He previously served as Vice President and Chief Financial Officer of GulfTerra EnergyPartners, L.P. from February 2004 to September 2004 at which time GulfTerra Energy Partners, L.P. was merged withEnterprise Products 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 SecuritiesInc. and its predecessor companies from May 1992 to August 2001. Mr. Manias earned a B.S.E. in civil engineering fromPrinceton University in 1984, a M.S. in petroleum engineering from Louisiana State University in 1986 and an M.B.A. fromRice University in 1992. David A. Smith has served as our President, Northeast Region since joining us in November 1998 and was appointed as aVice President of the General Partner in June 2011. Mr. Smith has approximately 20 years of experience in the natural gascompression industry, primarily in operations and sales. From 1985 to 1989, Mr. Smith was a sales manager for McKenzieCorporation, a compression fabrication company. From 1989 to 1996, Mr. Smith held positions of General Manager andRegional Manager of Northeast Division with Compressor Systems Inc., a fabricator and supplier of compression services.Mr. Smith was the Regional Manager in the northeast for Global Compression Services, Inc., a compression servicescompany, and served in that capacity from 1996 to 1998. Mr. Smith received an associate’s degree in Automotive and DieselTechnology from Rosedale Technical Institute. Sean T. Kimble has served as our Vice President, Human Resources since June 2014. Mr. Kimble brings to us overtwenty-five years of human resources leadership experience. Prior to joining us, he was most recently the Senior VicePresident of Human Resources at Millard Refrigerated Services from January 2011 to May 2014 where he led all aspects ofhuman resources. Before joining Millard, he was the Chief Administrative Officer and Executive Vice President of HumanResources at MV Transportation from March 2005 to February 2009 where he led human resources, safety, labor relationsand various other operating support functions. Mr. Kimble holds a B.S. in marketing from Sacramento State University andan M.B.A. from Saint Mary’s College of California. Mr. Kimble also completed the University of Michigan’s Strategic HRand Strategic Collective Bargaining Programs. Christopher W. Porter has served as our Vice President, General Counsel and Secretary since January 2017, and, prior tothat, had served as our Associate General Counsel and Assistant Secretary since October 2015. From January 2010 throughOctober 2015, Mr. Porter practiced corporate and securities law at Hunton Andrews Kurth LLP, representing public andprivate companies, including master limited partnerships, in capital markets offerings and mergers and acquisitions. Mr.Porter holds a B.B.A. degree in accounting from Texas A&M University, a M.S. degree in finance from Texas A&MUniversity, and a J.D. degree from The George Washington University. Michael Bradley has served on the Board since April 2018. Mr. Bradley currently serves as the Executive Vice President—LNG & International Business Development at ETO. He served on the board of directors of Regency GP, LLC, the generalpartner of Regency Energy Partners LP (“Regency”) and as the President and Chief Executive Officer of Regency until itsmerger with ETP in May 2015. Prior to joining Regency, he served as President, Chief Executive Officer and a director ofMatrix Service Company. Prior to joining Matrix Service Company, Mr. Bradley served as President and Chief ExecutiveOfficer of DCP Midstream Partners, LP (“DCP Midstream”) and as a member of the board of its general partner. Mr. Bradleyalso previously served as Group Vice President of Gathering and Processing for Duke Energy Field Services (“DEFS”) andExecutive Vice President of DEFS and Senior Vice President of DEFS. Mr. Bradley holds a bachelor’s degree in civilengineering from the University of Kansas and completed the Duke University Executive Management Program. Mr. Bradleyis a member of the American Society of Civil Engineers and serves on the advisory board for the University of Kansas Schoolof Engineering. Mr. Bradley was selected to serve on the Board due to his many years of experience in the natural gas industry andmidstream energy sector and proven record of effective executive level leadership. Christopher R. Curia has served on the Board since April 2018. Mr. Curia has also served as a director on the board ofdirectors of the general partner of Sunoco LP (NYSE: SUN) since August 2014 and as its Executive Vice President-72 Table of ContentsHuman Resources since April 2015. Mr. Curia also serves as the Executive Vice President and Chief Human ResourcesOfficer of LE GP, LLC (“LE GP”), the general partner of Energy Transfer LP (“ET LP”) and has served in that capacity sinceJanuary 2015. Mr. Curia joined ETO in July 2008 and was appointed the Executive Vice President and Chief HumanResources Officer of ET LP in January 2015. Prior to joining Energy Transfer, Mr. Curia held HR leadership positions at bothValero Energy Corporation and Pennzoil and has more than three decades of Human Resources experience in the oil and gasfield. Mr. Curia holds a master’s degree in Industrial Relations from the University of West Virginia. Mr. Curia was selected to serve on the Board due to the valuable perspective he brings from his extensive experienceworking as a human resources professional in the energy industry, and the insights he brings to the Board on matters such assuccession planning, compensation, employee management and acquisition evaluation and integration. Matthew S. Hartman has served on the Board since April 2018. Mr. Hartman is a Managing Director at EIG GlobalEnergy Partners and is the co-head of EIG’s midstream investment team. In this capacity, he invests in and monitors energymidstream investments. Mr. Hartman also serves on the board of directors of Southcross Holdings GP LLC. Prior to joiningEIG in 2014, Mr. Hartman served in various roles within the Citigroup and UBS investment banking divisions, where headvised on mergers as well as equity and debt financings for midstream energy companies. Mr. Hartman also previouslyworked in Ernst & Young’s tax practice. Mr. Hartman received a B.B.A. and B.P.A. from Oklahoma Baptist University and anM.B.A. from the University of Texas. Mr. Hartman was selected to serve on the Board because of his financial and investment acumen and experience with themidstream energy sector. Glenn E. Joyce has served on the Board since April 2018. Mr. Joyce has served as Chief Administrative Officer of ApexInternational Energy (“Apex”) since January 2017. He previously served as Director – HR and Administration since he joinedApex in April 2016. Prior to joining Apex, he spent over 17 years with Apache Corporation where his last position wasDirector of Global Human Resources in which he managed the HR functions of the international regions of Apache(Australia, Argentina, UK, Egypt). Previously, he worked for Amoco and was involved in international operationsin many different countries. Mr. Joyce received his bachelor’s degree in accounting from Texas A&M University. Mr. Joyce was selected to serve on the Board due to his extensive experience in senior human resources leadershippositions in the energy industry. Thomas E. Long has served on the Board since April 2018. He has also served on the board of directors of the generalpartner of Sunoco LP since May 2016. Mr. Long was appointed the Chief Financial Officer of the general partner of ET LPfollowing the merger of ETE and ETP in October 2018 and prior to the merger he was the Group Chief Financial Officer sinceFebruary 2016. Mr. Long previously served as Chief Financial Officer of ETO’s general partner and as Executive VicePresident and Chief Financial Officer of Regency Energy Partners LP’s general partner from November 2010 to April 2015.From May 2008 to November 2010, Mr. Long served as Vice President and Chief Financial Officer of Matrix ServiceCompany. Prior to joining Matrix, he served as Vice President and Chief Financial Officer of DCP Midstream, a publiclytraded natural gas and natural gas liquids midstream business company located in Denver, Colorado. In that position, he wasresponsible for all financial aspects of the company since its formation in December 2005. From 1998 to 2005, Mr. Longserved in several executive positions with subsidiaries of Duke Energy Corp., one of the nation’s largest electric powercompanies. Mr. Long has a Bachelor of Arts in Accounting and is a Certified Public Accountant. Mr. Long was selected to serve on the Board because of his understanding of energy-related corporate finance gainedthrough his extensive experience in the energy industry. Thomas P. Mason has served on the Board since April 2018. Mr. Mason was appointed Executive Vice President,General Counsel & President – LNG of LE GP after the merger of ETE and ETP in October 2018. Prior to the merger he wasExecutive Vice President and General Counsel of the general partner of ETE. Mr. Mason previously served as Senior VicePresident, General Counsel and Secretary of ETO’s general partner from April 2012 to December 2015, as73 Table of ContentsVice President, General Counsel and Secretary from June 2008 and as General Counsel and Secretary from February 2007.Prior to joining Energy Transfer, he was a partner in the Houston office of Vinson & Elkins L.L.P. Mr. Mason has specializedin securities offerings and mergers and acquisitions for more than 25 years. Mr. Mason also previously served on the Board ofDirectors of the general partner of Sunoco Logistics Partners L.P. Mr. Mason was selected to serve on the Board because of his decades of legal experience in securities, mergers andacquisitions and corporate governance in the energy sector. Matthew S. Ramsey has served on the Board since April 2018. Mr. Ramsey has also served on the board of directors ofthe general partner of SUN since August 2014, and as the chairman of the board of directors of the general partner of SUNsince April 2015. Mr. Ramsey is the Chief Operating Officer and director of ET LP’s general partner and has served in thatcapacity since the completion of the merger of ETE and ETP in October 2018. Mr. Ramsey served as President and ChiefOperating Officer of ETO’s general partner from November 2015 until the merger between ETE and ETP in October 2018. Mr. Ramsey has served on the board of directors of the general partner of ETO since July 2012. Mr. Ramsey served asPresident and Chief Operating Officer and Chairman of the board of directors of PennTex Midstream Partners, LP’s generalpartner from November 2016 until ETP completed its acquisition of PennTex in June 2017. Prior to joining Energy Transferin November 2015, Mr. Ramsey served as president of Houston-based RPM Exploration Ltd., a private oil and gasexploration partnership generating and drilling 3-D seismic prospects on the Gulf Coast of Texas. Mr. Ramsey is currently adirector of RSP Permian, Inc. (NYSE: RSPP), where he serves as chairman of the compensation committee and as a member ofthe audit committee. Mr. Ramsey formerly served as President of DDD Energy, Inc. until its sale in 2002. From 1996 to 2000,Mr. Ramsey served as President and Chief Executive Officer of OEC Compression Corporation, Inc., a publicly traded oilfield service company, providing gas compression services to a variety of energy clients. Mr. Ramsey holds a B.B.A. inMarketing from the University of Texas at Austin and a J.D. from South Texas College of Law. Mr. Ramsey is a graduate ofthe Harvard Business School Advanced Management Program. Mr. Ramsey is licensed to practice law in the State of Texas.He is qualified to practice in the Western District of Texas and the United States Court of Appeals for the Fifth Circuit. Mr.Ramsey formerly served as a director of Southern Union Company. Mr. Ramsey was selected to serve on the Board in recognition of his vast knowledge of the energy space and valuableindustry, operational and management experience. William S. Waldheim has served on the Board since April 2018. Mr. Waldheim served as a director and a member of theAudit, Finance & Risk Committee of Enbridge Energy Company, Inc. and Enbridge Energy Management, L.L.C. fromFebruary 2016 through December 2018. He previously served as President of DCP Midstream where he had overallresponsibility for DCP Midstream’s affairs including commercial, trading and business development until his retirement in2015. Prior to this, Mr. Waldheim was President of Midstream Marketing and Logistics for DCP Midstream and managednatural gas, crude oil and natural gas liquids marketing and logistics. From 2005 to 2008, he was Group Vice President ofCommercial for DCP Midstream, managing its upstream and downstream commercial business. Mr. Waldheim started hisprofessional career in 1978 with Champlin Petroleum as an auditor and financial analyst and served in roles involving NGLand crude oil distribution and marketing. He served as Vice President of NGL and Crude Oil Marketing for Union PacificFuels from 1987 until 1998 at which time it was acquired by DCP Midstream. Mr. Waldheim was selected to serve on the Board because of his broad and extensive experience in senior leadershiproles in the energy industry and his financial and accounting expertise. Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Exchange Act requires that the members of the Board, our executive officers and persons who ownmore than 10 percent of a registered class of our equity securities file initial reports of ownership and reports of changes inownership of our common units and other equity securities with the SEC and any exchange or other system on which suchsecurities are traded or quoted. SEC regulations also require that the members of the Board, our executive officers andpersons who own greater than 10 percent of a registered class of our equity securities furnish to us and any exchange or othersystem on which such securities are traded or quoted copies of all Section 16(a) forms they have filed with the SEC. To ourknowledge and based solely on a review of the copies of such reports furnished to us, we believe74 Table of Contentsthat all reporting obligations of the members of the Board, our executive officers and greater than 10 percent unitholdersunder Section 16(a) were satisfied during the year ended December 31, 2018. Common Unit Ownership by Directors and Executive Officers We encourage our directors and executive officers to invest in and retain ownership of our common units, but we do notrequire such individuals to establish and maintain a particular level of ownership. Reimbursement of Expenses of the General Partner The General Partner does not receive any management fee or other compensation for its management of us, but wereimburse the General Partner and its affiliates for all expenses incurred on our behalf, including the compensation ofemployees of the General Partner or its affiliates that perform services on our behalf. These expenses include all expendituresnecessary or appropriate to the conduct of our business and that are allocable to us. The Second Amended and RestatedAgreement of Limited Partnership of USA Compression Partners, LP (the “Partnership Agreement”) provides that the GeneralPartner will determine in good faith the expenses that are allocable to us. There is no cap on the amount that may be paid orreimbursed to the General Partner or its affiliates for compensation or expenses incurred on our behalf. ITEM 11.Executive Compensation As is commonly the case with publicly traded limited partnerships, we have no officers, directors or employees. Underthe terms of the Partnership Agreement, we are ultimately managed by the General Partner, which is controlled by EnergyTransfer. All of our employees, including our executive officers, are employees of USA Compression Management Services,LLC (“USAC Management”), a wholly owned subsidiary of the General Partner. References to “our officers” and “ourdirectors” refer to the officers and directors of the General Partner. Compensation Discussion & Analysis Named Executive Officers The following disclosure describes the executive compensation program for the named executive officers identifiedbelow (the “NEOs”). For the year ended December 31, 2018, the NEOs were: ·Eric D. Long, President and CEO;·Matthew C. Liuzzi, Vice President, Chief Financial Officer and Treasurer;·William G. Manias, Vice President and Chief Operating Officer;·David A. Smith, Vice President and President, Northeast Region; and·Sean T. Kimble, Vice President, Human Resources. Compensation Philosophy and Objectives Since our initial public offering in 2013, we have consistently based our compensation philosophy and objectives onthe premise that a significant portion of each NEO’s total compensation should be incentive-based or “at-risk” compensation.We share Energy Transfer’s philosophy that the NEOs’ total compensation levels should be competitive in the marketplacefor executive talent and abilities. The Compensation Committee generally targets at or near the 50th percentile of the marketfor the three main components of our compensation program: base salary, annual discretionary cash bonus and long-termequity incentive awards. The Compensation Committee believes the incentive-based balance is achieved by (i) the paymentof annual discretionary cash bonuses that consider (a) the achievement of the financial performance objectives for a fiscalyear set at the beginning of such fiscal year and (b) the individual contributions of each of the NEOs to our level of success inachieving the annual financial performance objectives, and (ii) the annual grant of time-based restricted phantom unit awardsunder the LTIP, which awards are intended to incentivize and retain our key employees for the long-term and motivate themto focus their efforts on increasing the market price of our common units and the level of cash distributions we pay to ourcommon unitholders.75 Table of Contents The following charts illustrate the level of at-risk incentive compensation we awarded in 2018 to our CEO and, on anaveraged basis, the other NEOs. “Variable/at-risk” compensation is comprised of long-term equity incentive awards andannual discretionary cash bonuses, and “fixed” compensation is comprised of base salary. Our compensation program is structured to achieve the following: ·compensate executives with an industry-competitive total compensation package of competitive base salaries andsignificant incentive opportunities yielding a total compensation package at or near the 50th percentile of themarket;·attract, retain and reward talented executive officers and key members of management by providing a totalcompensation package competitive with those of their counterparts at similarly situated companies;·motivate executive officers and key employees to achieve strong financial and operational performance;·emphasize performance-based or “at risk” compensation; and·reward individual performance. Methodology to Setting Compensation Packages Our executive compensation program is administered by the Compensation Committee. The Compensation Committeeconsiders market trends in compensation, including the practices of identified competitors, and the alignment of thecompensation program with the Partnership’s strategy. Specifically, for the NEOs, the Compensation Committee: ·establishes and approves target compensation levels for each NEO;·approves Partnership performance measures and goals;·determines the mix between cash and equity compensation, short-term and long-term incentives and benefits;·verifies the achievement of previously established performance goals; and·approves the resulting cash or equity awards to the NEOs. The Compensation Committee also considers other factors such as the role, contribution and performance of anindividual relative to his or her peers at the Partnership. The Compensation Committee does not assign specific weight tothese factors, but rather makes a subjective judgment taking all of these factors into account. The Compensation Committee reviews and approves all compensation for the NEOs. In determining the compensationfor the NEOs, the Compensation Committee takes into account input from the CEO for the compensation of the other NEOs. The CEO considers comparative compensation data and evaluates the individual performance of each NEO and theirrespective contributions to the Partnership. The recommendations are then reviewed by the Compensation Committee, whichmay accept the recommendations or make adjustments to the recommended compensation based on76 Table of Contentsthe Compensation Committee’s assessment of the individual’s performance and contributions to the Partnership. The CEO’scompensation is reviewed and approved by the Compensation Committee based on comparative compensation data and theCompensation Committee’s independent evaluation of the CEO’s contributions to the Partnership’s performance. Periodically, we engage a third-party consultant to provide the Compensation Committee with market information aboutcompensation levels at peer companies to assist in setting compensation levels for our executives, including the NEOs. In2016, the Compensation Committee engaged Longnecker & Associates (“Longnecker”) to assist the CompensationCommittee in determining appropriate compensation levels for senior management, including the NEOs, by: (i) providingmarket information for compensation levels at peer companies; (ii) evaluating the market competitiveness of our totalcompensation levels; and (iii) confirming that our compensation program is yielding compensation packages consistent withour overall compensation philosophy. The compensation analysis provided by Longnecker in 2016 (the “2016 LongneckerReport”) covered all major components of total compensation, including annual base salary, annual short-term cash bonusand long-term equity incentive awards for the NEOs as compared to executives at similarly situated companies in terms ofindustry, annual revenue and market capitalization. The Compensation Committee also benchmarked results for the annual base salary, annual short-term cash bonus andlong-term equity incentive awards of the NEOs against data for compensation levels for specific executive positions reportedin published executive compensation surveys within each of the (i) energy industry and (ii) overall market. TheCompensation Committee also reviewed publicly filed peer group executive compensation disclosures pertaining to certainexecutive roles, but because of limited sample size due to the relatively small number of publicly traded natural gascompression companies, the Compensation Committee used this data as a reference point rather than a primary data source. On November 2, 2017, the Compensation Committee determined that the 2016 Longnecker Report was completedrecently enough to be utilized in setting 2018 compensation levels for the NEOs, and consulted the 2016 LongneckerReport, adjusted to account for general inflation and other relevant information obtained from other sources, such as 2018third party survey results, in its determination of compensation levels for 2018 for our executives, including the NEOs. In light of the Transactions and resulting increased size of the Partnership and greater level of responsibility for each ofthe NEOs, in May 2018 the Compensation Committee again engaged Longnecker, who is also the independentcompensation advisor to Energy Transfer, to provide an updated targeted market review and benchmarking for certainmembers of our senior leadership team (the “2018 Longnecker Report”). The Compensation Committee relied on the resultsof the 2018 Longnecker Report for determinations of base salary and bonus and long-term equity incentive targets for 2019for the NEOs. In connection with its engagement of Longnecker, based on the information presented to it, the CompensationCommittee assessed the independence of Longnecker under applicable SEC and NYSE rules and concluded thatLongnecker’s work for the Compensation Committee did not raise any conflict of interest for 2018. 77 Table of ContentsOur 2018 peer group selected by the Compensation Committee in consultation with Longnecker included the followingcompanies: CompanyTicker1. American Midstream Partners, LPAMID2. Archrock, Inc.AROC3. Buckeye Partners, L.P.BPL4. Crestwood Equity Partners LPCEQP5. Enlink Midstream, LLCENLC6. EQT Midstream Partners, LPEQM7. Exterran CorporationEXTN8. Genesis Energy, L.P.GEL9. Martin Midstream Partners L.P.MMLP10. SemGroup CorporationSEMG11. Summit Midstream Partners, LPSMLP12. MPLX LPMPLX13. Tallgrass Energy Partners, LPTEP14. TETRA Technologies, Inc.TTI Elements of the Compensation Program Compensation for the NEOs consists primarily of the following elements and corresponding objectives: Compensation Element Primary Objective Base salary To recognize performance of job responsibilities and toattract and retain individuals with superior talent. Annual incentive compensation To promote near-term performance objectives and rewardindividual contributions to the achievement of thoseobjectives. Long-term equity incentive awards To emphasize long-term performance objectives, encouragethe maximization of unitholder value and retain keyexecutives by providing an opportunity to participate in theownership of the Partnership. Retirement savings (401(k)) plan To provide an opportunity for tax-efficient savings. Other elements of compensation and perquisites To attract and retain talented executives in a cost-efficientmanner by providing benefits comparable to those offeredby similarly situated companies. Base Salary for 2018 and 2019 Base salaries for the NEOs have generally been set at a level deemed necessary to attract and retain individuals withsuperior talent. Base salary increases are determined based upon the job responsibilities, demonstrated proficiency andperformance of the NEO and market conditions. In connection with determining base salaries for each of the NEOs for 2018,the Compensation Committee and CEO utilized the 2016 Longnecker Report to determine comparable salaries for suchexecutive roles within our peer group. 78 Table of ContentsFollowing the Transactions, the Compensation Committee in consultation with Longnecker, and in consideration of theavailable compensation data, determined that three of the NEOs’ 2018 salaries were at appropriate levels for 2019, andadjusted two of the NEOs’ base salaries for 2019. The 2018 and current 2019 base salaries for the NEOs, including our CEO, are set forth in the following table: 2018 Base Salary Current 2019Base SalaryName and Principal Position ($) ($)Eric D. Long, President and Chief Executive Officer 644,709 644,709Matthew C. Liuzzi, Vice President, Chief Financial Officer and Treasurer 387,239 400,000William G. Manias, Vice President and Chief Operating Officer 437,092 437,092David A. Smith, Vice President and President, Northeast Region 502,357 517,428Sean T. Kimble, Vice President, Human Resources 307,670 307,670 Annual Cash Incentive Compensation for 2018 The Board previously approved the USA Compression Partners, LP Annual Cash Incentive Program (the “Bonus Plan”).Each of the NEOs is entitled to participate in the Bonus Plan and their potential bonus is governed by the Bonus Plan and,for Messrs. Smith and Kimble, also governed by their respective employment agreements. The Compensation Committee actsas the administrator of the Bonus Plan under the supervision of the full Board, and has the discretion to amend, modify orterminate the Bonus Plan at any time. Although for 2018 the Bonus Plan utilized both Partnership and individualperformance goals to assist in determining bonus amounts, the Bonus Plan is ultimately a discretionary annual bonus planand awards are therefore reported in the “Bonus” column within the Summary Compensation Table below. For the year ended December 31, 2018, the Compensation Committee set a target bonus amount (the “Target Bonus”) foreach NEO prior to the first quarter of the year, which was set as a percentage of the NEO’s base salary. For the bonusapplicable to the year ended December 31, 2018, the Target Bonus, as a percentage of base salary and as a dollar amount, isreflected in the table below. Percentage of AmountName Base Salary ($)Eric D. Long 100% 644,709Matthew C. Liuzzi 75% 290,429William G. Manias 80% 349,674David A. Smith 60% 301,346Sean T. Kimble 70% 215,369 The Target Bonus for 2018 was generally subject to the satisfaction of both a Partnership performance goal (accountingfor 75% of the Target Bonus) and an individual performance goal (accounting for 25% of the Target Bonus). Prior to 2018,seventy-five percent (75%) of the Target Bonus was subject to the Partnership’s achievement of its budgeted distributablecash flow (“DCF”) target for the year. For the year ended December 31, 2018, because the Partnership’s predecessor forfinancial reporting purposes, the USA Compression Predecessor, did not historically calculate DCF on a basis directlycomparable to the Partnership’s calculation of DCF, the Compensation Committee determined that seventy-five percent(75%) of the Target Bonus would be instead subject to the Partnership’s achievement of its budgeted Adjusted EBITDAtarget, as determined by the Compensation Committee. Additionally, because the Transactions closed on April 2, 2018, andprior to that Partnership management had no oversight of or involvement with the USA Compression Predecessor, theCompensation Committee determined that only the second, third and fourth quarters of 2018 (together, the “2018 BonusPeriod”) would be considered when determining whether the Adjusted EBITDA target had been met. For the bonusapplicable to 2018, the Compensation Committee determined that, as with the previous DCF target, payouts with respect tothe portion of the bonus determined by Adjusted EBITDA (the “Adjusted EBITDA Bonus”) would not occur unless wesatisfied the Adjusted EBITDA threshold, which was set at 80% of the Partnership’s budgeted Adjusted EBITDA target. Forthe 2018 Bonus Period, the Compensation Committee set the budget for Adjusted EBITDA at $278.8 million. The threshold,target and maximum requirements for the Adjusted EBITDA target for the 2018 Bonus Period, as well as the portion of theAdjusted EBITDA Bonus that could79 Table of Contentsbecome payable if Adjusted EBITDA performance was satisfied for the 2018 Bonus Period at such levels, are set forth below. AdjustedEBITDA as a Percentage of Percentage of AdjustedEBITDA Levels of Budgeted Adjusted Bonus that would Adjusted EBITDA Bonus EBITDA for 2018Bonus Period be Paid Threshold 80% 50% Target 100% 100% Maximum 110% 200% For 2018, if Adjusted EBITDA performance for the 2018 Bonus Period fell in between threshold and target, or betweentarget and maximum levels, the amounts payable would be adjusted ratably using straight line interpolation. If AdjustedEBITDA was achieved above maximum levels, the potential payment of the Adjusted EBITDA Bonus was capped at themaximum level of 200%. For the year ended December 31, 2018, the remaining twenty-five percent (25%) of the Target Bonus was determined bythe satisfaction of individual objectives specific to each NEO’s role (the “Individual Bonus”). The individual objectives wereagreed upon in advance between the NEO and the CEO (or, with respect to the CEO, between the Compensation Committeeand the CEO) and such objectives addressed the key priorities for that NEO’s position. For the year ended December 31,2018, the Individual Bonus objectives included key operating goals as well as personal development criteria. For the yearended December 31, 2018, the Individual Bonus was subject to a maximum payout of 100% of the targeted Individual Bonusamount, although the Compensation Committee retained sole discretion to determine to pay out smaller amounts rangingfrom 0% to 100% after analyzing the NEO’s personal performance for the year. In connection with the Individual Bonus forthe year ended December 31, 2018, each of the NEOs met with the CEO (or, in the case of the CEO, the CompensationCommittee) to set individual objectives that reflected the responsibilities and priorities of their respective positions. For the year ended December 31, 2018, in the aggregate, the maximum amount payable with respect to a Target Bonusunder the Bonus Plan was 175%, as the Adjusted EBITDA Bonus was capped at 200% of target and the Individual Bonus wascapped at 100% of target. Target Bonuses, if any, are paid within one week following delivery by our independent auditor ofthe audit of our financial statements for the year to which the Target Bonus relates, but in any case no later than March 15 ofthe year following the year to which the Target Bonus relates. For the 2018 Bonus Period, Adjusted EBITDA exceeded thetarget level by 3.60%, which resulted in the Adjusted EBITDA Bonus (comprising seventy-five percent of the overall TargetBonus) being paid to each NEO at the rate of 136.0%. With respect to the Individual Bonus portion of the overall TargetBonus, the CEO (or in the case of the CEO, the Compensation Committee (based on the recommendation of management))determined that each NEO satisfied his individual objectives and therefore was entitled to receive 100% of the IndividualBonus. The awards made pursuant to the Bonus Plan with respect to the year ended December 31, 2018 were: Name BonusEric D. Long $818,597Matthew C. Liuzzi $368,763William G. Manias $443,986David A. Smith $382,710Sean T. Kimble $273,457 Annual Cash Incentive Compensation for 2019 In February 2019, the Compensation Committee approved the USA Compression Partners, LP Amended and RestatedAnnual Cash Incentive Plan (the “A&R Bonus Plan”), which is effective beginning with respect to fiscal year 2019 andmakes several modifications to the Partnership’s annual cash incentive program. The Compensation Committee will makedeterminations whether to make discretionary annual cash bonus awards to executives attributable to 2019, including theNEOs, under the A&R Bonus Plan following the year ended December 31, 2019. The A&R Bonus Plan contains four payoutfactors and corresponding percentages that comprise the total annual target bonus for all80 Table of Contentseligible employees, including our named executive officers (the “Annual Target Bonus Pool”): (i) the Adjusted EBITDABudget Target Factor (the “Adjusted EBITDA Factor”): 30%; (ii) the Distributable Cash Flow Budget Target Payout Factor(the “DCF Factor”): 30%; (iii) the Leverage Ratio Budget Target Factor (the “Leverage Ratio Factor”): 30% and (iv) theSafety Budget Target Payout Factor (the “Safety Factor”): 10%. Each of the Adjusted EBITDA Factor and DCF Factor assign payout factors from 0% to 120% based on the percentage ofthe Partnership’s budgeted Adjusted EBITDA and DCF, respectively, achieved for the year, as shown in the following chart. Adjusted EBITDA and DCF Factors% of Budget Target Bonus Pool Payout FactorGreater than or equal to 110% 1.20x109.9%-105.0% 1.10x104.9%-95.0% 1.00x94.9%-90.0% 0.90x89.9%-80.0% 0.75xLess than 80.0% 0.00x The Leverage Ratio Factor assigns payout factors based on the Partnership’s achievement of its budgeted Leverage Ratio (asdefined in the Partnership’s Sixth Amended and Restated Credit Agreement, provided that, for the purposes of calculating theLeverage Ratio for the A&R Bonus Plan, EBITDA attributable to the full plan year shall be used in lieu of any other timeperiod) for the year, as shown in the following chart. Leverage Ratio FactorRange within Budget Target Bonus Pool Payout FactorMore than 0.250 below budget target 1.20x0.250-0.125 below 1.10x0.124 below-0.125 above 1.00x0.126-0.375 above 0.70x0.376-0.500 above 0.50xGreater than 0.500 above 0.00x The Safety Factor assigns payout factors based on the Partnership’s Total Recordable Incident Rate, or TRIR (ascalculated by the U.S. Occupational Safety and Health Administration) against the Partnership’s TRIR target, as shown in thefollowing chart. Safety Factor% of Target Bonus Pool Payout FactorLess than 100% 1.00x100%-105% 0.90x105.1%-110% 0.80x110.1%-115% 0.70x115.1%-125% 0.60xGreater than 125% 0.00x The establishment and amount of the Funded Bonus Pool is 100% discretionary and subject to approval and/oradjustment by the Compensation Committee. In determining bonuses for the NEOs, the Compensation Committee takes intoaccount whether the Partnership achieved or exceeded its targeted performance objectives. In the case of the NEOs, theirbonus pool targets range from 60% to 125% of their respective annual base earnings (which amount reflects the actual basesalary earned during the calendar year to reflect periods before and after any base salary adjustment). For 2019, the annualcash bonus pool targets for the NEOs are as follows: for Mr. Long, 125%; for Mr. Liuzzi, 105%; for Mr. Manias, 100%; forMr. Smith, 60%; and for Mr. Kimble, 70%. The annual cash bonus pool targets for 2019 are81 Table of Contentsbased on the determination of the Compensation Committee in consultation with Longnecker, and in consideration of theavailable compensation data and internal compensation levels within Energy Transfer. Long-Term Equity Incentive Awards The Board adopted the LTIP, which is designed to promote our interests, as well as the interests of our unitholders, byrewarding our officers, directors and certain of our employees for delivering desired performance results, as well as bystrengthening our ability to attract, retain and motivate qualified individuals to serve as officers, directors and employees.The LTIP provides for the grant, from time to time at the discretion of the Board, of unit awards, restricted units, phantomunits, unit options, unit appreciation rights, distribution equivalent rights (“DERs”) and other common unit-based awards,although since our initial public offering in 2013 the Board has only granted awards of phantom units with DERs under theLTIP. The outstanding, unvested phantom units granted under the LTIP and held by the NEOs are reflected below in “—Outstanding Equity Awards as of December 31, 2018.” During 2018, the Board granted phantom unit awards to certain key employees, including the NEOs. With respect to theannual awards granted under the LTIP in February of each of 2016, 2017 and 2018, twenty percent (20%) of the phantomunits awarded to each individual were subject to a performance-based vesting formula (the “Performance Units”) and theremaining eighty percent (80%) of the phantom units were subject to time-based vesting restrictions (the “Standard Units”). Performance Units granted prior to the Transactions were scheduled to vest (i) based upon our level of total unitholderreturn (“TUR”) relative to a group of peer companies over a certain period of time or (ii) immediately prior to a “Change inControl.” As the Transactions constituted a “Change in Control,” all outstanding Performance Units vested on theTransactions Date, including those Performance Units granted in February of 2018. Since we have not granted anyPerformance Units subsequent to the awards granted in February 2018, there are currently no Performance Units outstandingunder the LTIP. The Standard Units granted to our CEO were also accelerated in connection with the Transactions pursuantto the terms of his then-current LTIP award agreements, but the other NEOs continue to hold outstanding Standard Unitsgranted prior to the Transactions that have not vested pursuant to time-based vesting in the ordinary course. See “UnitsVested During the Year Ended December 31, 2018” below. Standard Units that were granted prior to July 30, 2018 vest inthree equal annual installments, with the first installment vesting February 15 of the year following the grant. The target level of annual long-term incentive awards for each of the NEOs is expressed as a percentage of the NEO’sbase salary. In 2016, the Compensation Committee, in consultation with Longnecker, set the individual long-term incentivetarget percentages for the NEOs, and the Compensation Committee did not make any changes to those individual long-termincentive target percentages for the NEOs during 2017 or for the grants in 2018 that occurred prior to the Transactions. Thefollowing table shows each NEO’s long-term incentive target for 2018 prior to the Transactions (expressed as a percentage ofbase salary). Pre-Transactions Long-Term Incentive Target Amounts Percentage of AmountName Base Salary ($)Eric D. Long 300% 1,934,127Matthew C. Liuzzi 200% 774,478William G. Manias 225% 983,457David A. Smith 70% 351,650Sean T. Kimble 175% 538,423 On November 1, 2018, the Board adopted a new form of employee phantom unit award agreement under the LTIP (the“New Award Agreement”) to bring our long-term equity incentive compensation program in line with Energy Transfer’spractices. The New Award Agreement (i) alters the vesting schedule of Standard Units from three equal annual installments toincremental vesting over five years (60% on the third December 5 following the grant and 40% on the fifth December 5following the grant) and (ii) provides for vesting of 100% of the outstanding, unvested Standard Units in the event of aChange in Control (as defined under the LTIP and set forth below under “Potential Payments upon Termination or Change inControl”). 82 Table of Contents In determining the level of the December 2018 grants of Standard Units to the NEOs, the Compensation Committee, inconsultation with Longnecker and taking into account internal compensation levels within Energy Transfer, determined tomodify certain of the NEOs’ long-term incentive targets, as shown in the following table: Post-Transactions Long-Term Incentive Target Amounts Percentage of AmountName Base Salary ($)Eric D. Long 400% 2,578,836Matthew C. Liuzzi 250% 1,000,000William G. Manias 225% 983,457David A. Smith 97% 500,000Sean T. Kimble 175% 538,423 Under the LTIP, the Compensation Committee has the discretion to determine whether any portion of phantom unitsshould be settled in cash upon vesting for the purpose of conserving common units approved for issuance under the LTIP.For the awards made in February 2018, the Compensation Committee recommended to the Board, and on February 9, 2018the Board approved, the default settlement method for phantom units of 50% in cash (valued based on the closing price onthe NYSE of the Partnership’s common units on the date of vesting) and 50% in common units. However, the Board alsospecified that if an employee affirmatively requests in writing that the percentage of cash settlement be set at a specificamount that is less than 50% (and such employee agrees to pay out of his or her own funds the amount of any required federalwithholding to the extent that the cash portion is insufficient for the Partnership to withhold and pay such amounts on theemployee’s behalf), the Board approves in advance such lesser cash settlement percentage. Each phantom unit granted to an employee, including the NEOs, is granted in tandem with a corresponding DER, whichentitles the recipient to receive an amount in cash on a quarterly basis equal to the product of (a) the number of phantomunits granted to the grantee that remain outstanding and unvested as of the record date for the distribution on thePartnership’s common units for such quarter and (b) the quarterly distribution with respect to the Partnership’s commonunits. With respect to Performance Units, DERs were granted for the target number of underlying common units and were notadjusted up or down depending on actual performance results. Awards granted pursuant to the LTIP are subject to certain clawback features, and the award may not vest or settle if wedetermine that the recipient committed certain acts of misconduct, as more particularly described in the LTIP. Benefit Plans and Perquisites We provide the NEOs with certain personal benefits and perquisites, which we do not consider to be a significantcomponent of our overall executive compensation program but which we recognize are an important factor in attracting andretaining talented executives. The NEOs are eligible under the same plans as all other employees with respect to our medical,dental, vision, disability and life insurance benefits and a defined contribution plan that is tax-qualified under Section401(k) of the Internal Revenue Code (the “401(k) Plan”). In addition, we currently provide one or more NEOs with (i) anannual automobile allowance; (ii) additional life insurance coverage; (iii) club memberships; and (iv) personaladministrative support. The Compensation Committee has determined it is appropriate to offer these perquisites in order toprovide compensation opportunities competitive with those offered by similarly situated public companies. In determiningthe compensation payable to the NEOs, the Compensation Committee considers perquisites in the context of the totalcompensation the NEOs are eligible to receive. However, given the fact that perquisites represent a relatively small portion ofthe NEOs’ total compensation, the availability of these perquisites does not materially influence the CompensationCommittee’s decision making with respect to other elements of the total compensation to which the NEOs are entitled orwhich they are awarded. The value of personal benefits and perquisites we provided to each of the NEOs in 2018 is set forthbelow in “—Summary Compensation Table.” 83 Table of ContentsRetention Phantom Unit Agreements On November 1, 2018, the Compensation Committee approved the form of, and the Partnership entered into, a RetentionPhantom Unit Agreement (collectively, the “Retention Agreements”) under the LTIP with each of Messrs. Long, Liuzzi andManias, which provide for a grant of Standard Units (the “Retention Units”) in the following amounts: (i) 90,000 RetentionUnits to Mr. Long; (ii) 35,000 Retention Units to Mr. Liuzzi; and (iii) 45,000 Retention Units to Mr. Manias. The RetentionUnits will vest incrementally, with 60% of the Retention Units vesting on December 5, 2021 and 40% of the Retention Unitsvesting on December 5, 2023, subject in each case to the NEO’s continued employment with the Partnership. Each RetentionUnit was granted with a corresponding DER. The Compensation Committee approved the Retention Agreements in recognition of the importance of Messrs. Long,Liuzzi and Manias to the Partnership’s long-term success and to encourage their retention by providing additional time-based compensation. For additional information regarding the Retention Agreements, please see “—Potential Payments uponTermination or Change in Control—Retention Phantom Unit Agreements” below. Employment Agreements Each of Messrs. Smith and Kimble is party to an employment agreement with us (together, the “EmploymentAgreements”), each of which have been extended on a year-to-year basis and will be automatically extended for successivetwelve month periods unless either party delivers written notice to the other at least 90 days prior to the end of the currentemployment term. The employment agreements with Messrs. Long, Liuzzi and Manias were terminated on November 1,2018. Please see the description of the Employment Agreements under “Potential Payments upon Termination or Change inControl” for further details on the terms of the Employment Agreements. Risk Assessment Related to Our Compensation Structure We believe our compensation program for all of our employees, including the NEOs, is appropriately structured and notreasonably likely to result in material risk to us because it is structured in a manner that does not promote excessive risk-taking that could damage our reputation, negatively impact our financial results or reward poor judgment. We have alsoallocated our compensation among base salary and short and long-term compensation in such a way as to not encourageexcessive risk-taking. Furthermore, all business groups and employees receive the same core compensation components ofbase pay and short-term incentives. We typically offer long-term equity incentives to employees at the director level orabove, and we use phantom units rather than unit options for these equity awards because phantom units retain value even ina depressed market, so employees are less likely to take unreasonable risks to get or keep options “in-the-money.” Finally,the time-based vesting over three to five years for our long-term incentive awards ensures that our employees’ interests alignwith those of our unitholders with respect to our long-term performance. Accounting and Tax Considerations We account for the equity compensation expense for equity awards granted under our LTIP in accordance with U.S.generally accepted accounting principles, which requires us to estimate and record an expense for each equity award over thevesting period of the award. Standard Units are accounted for as a liability and are re-measured at fair value at the end of eachreporting period using the market price of the Partnership’s common units. Fair value for Performance Units was determinedusing a Monte Carlo simulation model, which incorporated a number of factors in its valuation, including the vesting period,the expected price volatility of the Partnership’s common units, expected distributions and the risk free interest rate. Phantomunits granted to independent directors do not have a cash settlement option; therefore we account for these awards as equity.During the requisite service period, compensation cost is recognized using the proportionate amount of the award’s fair valuethat has been earned through service to date. Because we are a partnership and the General Partner is a limited liability company, Section 162(m) of the InternalRevenue Code (the “Code”) does not apply to the compensation paid to the NEOs and, accordingly, the CompensationCommittee did not consider its impact in making the compensation recommendations discussed above. 84 Table of ContentsCompensation Committee Interlocks and Insider Participation We do not have any Compensation Committee interlocks. Messrs. Joyce and Waldheim are the only members of theCompensation Committee, and during 2018 neither Mr. Joyce nor Mr. Waldheim was an officer or employee of EnergyTransfer or any of its affiliates, or served as an officer of any company with respect to which any of our executive officersserved on such company’s board of directors. In addition, neither Mr. Joyce nor Mr. Waldheim is a former employee ofEnergy Transfer or any of its affiliates. Compensation Committee Report The Compensation Committee has reviewed and discussed the section of this report entitled “Compensation Discussionand Analysis” with management of the Partnership and approved its inclusion in this Annual Report on Form 10-K.Compensation CommitteeGlenn E. Joyce (Chairman)William S. Waldheim The foregoing report shall not be deemed to be incorporated by reference by any general statement or reference to thisAnnual Report on Form 10-K into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act, asamended, except to the extent that we specifically incorporate this information by reference, and shall not otherwise bedeemed filed under those Acts. Summary Compensation Table Since our initial public offering (“IPO”) in 2013, we have been considered an “emerging growth company” (“EGC”)under the Jumpstart Our Business Startups Act. As an EGC we were only required to disclose compensation information forour three most highly compensated individuals, compared to five individuals as is required of companies that do not qualifyfor reduced disclosure requirements. We ceased to be an EGC on December 31, 2018. Since 2018 is the first fiscal year forwhich we are required to disclose compensation information for five NEOs, the following table provides a summary of thecompensation paid to (i) three NEOs for the years ended December 31, 2018, 2017 and 2016 and (ii) five NEOs for the yearended December 31, 2018.85 Table of ContentsSummary Compensation Table All Other Unit Awards Compensation Name and Principal Position Year Salary ($) Bonus ($) (1) ($) (2) ($) Total ($)Eric D. Long 2018 644,709 818,597 5,942,922 322,176(3) 7,728,404President and Chief Executive Officer 2017 625,233 721,436 1,953,127 755,233 4,055,029 2016 607,109 773,419 1,892,893 742,412 4,015,833 Matthew C. Liuzzi 2018 387,239 368,763 2,331,734 261,277(4) 3,349,013Vice President, Chief Financial Officer andTreasurer 2017 375,538 329,496 782,050 313,209 1,800,293 2016 362,885 381,399 852,693 306,589 1,903,566 William G. Manias 2018 437,092 443,986 2,682,754 323,631(5) 3,887,463Vice President and Chief Operating Officer 2017 423,886 396,711 993,108 389,700 2,203,405 2016 411,538 416,353 1,069,430 380,616 2,277,937 David A. Smith 2018 502,357 382,710 879,243 136,049(6) 1,900,359Vice President and President, NortheastRegion Sean T. Kimble 2018 307,670 273,457 1,105,336 176,784(7) 1,863,247Vice President, Human Resources (1)Represents the awards earned under the Bonus Plan for the years ended December 31, 2018, 2017 and 2016 for Messrs. Long, Liuzziand Manias, and for the year ended December 31, 2018 for Messrs. Smith and Kimble. For a discussion of the determination of the 2018bonus amounts, see “—Annual Cash Incentive Compensation for 2018” above. (2)On February 12, 2018, February 13, 2017 and February 11, 2016, each of the NEOs received an award of phantom units comprised ofStandard Units and Performance Units under the LTIP. Each phantom unit is the economic equivalent of one common unit, although thePerformance Units were eligible to vest at up to 200% of target levels three years after grant, depending on the level of achievement ofcertain performance goals over the performance period. The phantom unit values reflect the grant date fair value of the awards calculatedin accordance with the Financial Accounting Standards Board’s (“FASB”) Accounting Standard Codification (“ASC”) Topic 718,disregarding the estimated likelihood of forfeitures. For a discussion of the assumptions utilized in determining the fair value of theseawards, please see Note 15 to our consolidated financial statements. Fair value for the Performance Units was determined using a MonteCarlo simulation model, which incorporated a number of factors in its valuation including the vesting periods of our awards, the expectedvolatility of our units, expected dividends and the risk free interest rate. In connection with the closing of the Transactions, on theTransactions Date all outstanding, unvested Performance Units vested at 100% of the target level pursuant to the terms of the applicableLTIP award agreements because the Transactions constituted a Change in Control under the LTIP. The value of the Performance Units atvesting was over 25% less than the grant date fair value of the Performance Units reported in this table, as anticipated accelerated vestingin connection with a change in control was not factored into the valuation of the Performance Units under FASB ASC Topic 718. Pleasesee the “Units Vested during the Year Ended December 31, 2018” table below for the actual value realized upon vesting of thePerformance Units. In addition, all of Mr. Long’s outstanding, unvested Standard Units vested on the Transactions Date pursuant to theterms of Mr. Long’s LTIP award agreements in effect at the time. (3)Includes: (i) $267,728 of DERs; (ii) $18,000 of automobile allowance; (iii) $13,750 of employer contributions under the 401(k) Plan; (iv)$3,897 of parking; (v) $9,623 of club membership dues; and (vi) $9,178 of personal administrative assistant support. Please see adescription of the DERs under “—Long-Term Equity Incentive Awards” above. (4)Includes: (i) $247,828 of DERs; and (ii) $13,449 of employer contributions under the 401(k) Plan. (5)Includes: (i) $313,391 in DERs; and (ii) $10,240 of employer contributions under the 401(k) Plan. 86 Table of Contents(6)Includes: (i) $101,654 of DERs; (ii) $9,960 of automobile allowance; (iii) $13,750 of employer contributions under the 401(k) Plan; (iv)$6,000 of club membership dues; and (v) $4,685 of life insurance premiums. (7)Includes: (i) $160,015 of DERs; (ii) $13,716 of employer contributions under the 401(k) Plan; and (iii) $3,053 for parking. Grants of Plan-Based Awards during the Year Ended December 31, 2018 The below reflects awards granted to our NEOs under the LTIP during 2018. Grant All Other Date Approval Estimated Future Payouts Under Unit Fair Date of Equity Awards: Value of Equity- Incentive Plan Awards (1) Number of Unit Based Threshold Target Maximum Units AwardsName Grant Date Awards (#) (#) (#) (#) (2) ($) (3)Eric D. Long 2/12/2018 11/3/2017 10,787 21,574 43,148 86,296 2,036,586 11/1/2018 11/1/2018 — — — 90,000 1,327,500 12/5/2018 11/1/2018 — — — 176,874 2,578,836Matthew C. Liuzzi 2/12/2018 11/3/2017 4,319 8,639 17,278 34,554 815,484 11/1/2018 11/1/2018 — — — 35,000 516,250 12/5/2018 11/1/2018 — — — 68,587 1,000,000William G. Manias 2/12/2018 11/3/2017 5,485 10,970 21,940 43,879 1,035,549 11/1/2018 11/1/2018 — — — 45,000 663,750 12/5/2018 11/1/2018 — — — 67,452 983,455David A. Smith 2/12/2018 11/3/2017 2,008 4,017 8,034 16,070 379,243 12/5/2018 11/1/2018 — — — 34,293 500,000Sean T. Kimble 2/12/2018 11/3/2017 3,003 6,006 12,012 24,022 566,929 12/5/2018 11/1/2018 — — — 36,927 538,407(1)The amounts in these columns show the range of potential payouts for the Performance Units at the time of grant by the CompensationCommittee on February 12, 2018 pursuant to the LTIP. Fair value for the Performance Units was determined using a Monte Carlosimulation model, which incorporated a number of factors in its valuation including the vesting periods of our awards, the expectedvolatility of our units, expected dividends and the risk free interest rate. The Performance Units were scheduled to vest (i) on the thirdanniversary of the date of grant at between 0% and 200% of the granted number of Performance Units based upon our level of TURrelative to a group of peer companies; or (ii) immediately prior to a “Change in Control.” Pursuant to the terms of the applicable LTIPaward agreements, the Performance Units granted on February 12, 2018 received accelerated vesting at target levels on the TransactionsDate in connection with the Transactions, which constituted a Change in Control under the LTIP. The value of the Performance Units atvesting was over 25% less than the value of the Performance Units reported in this table, as anticipated accelerated vesting in connectionwith a change in control was not factored into the valuation of the Performance Units under FASB ASC Topic 718. Please see the “UnitsVested during the Year Ended December 31, 2018” table below for the actual value realized upon vesting of the Performance Units. (2)The Standard Units granted on February 12, 2018 will vest in three equal tranches beginning on February 15, 2019, except for theStandard Units granted to Mr. Long, which vested in full on the Transactions Date in connection with the Transactions pursuant to theterms of his LTIP award agreements in effect at the time. The Retention Units granted on November 1, 2018 to Messrs. Long, Liuzzi andManias and the Standard Units granted on December 5, 2018 to all of the NEOs will vest incrementally, with 60% of the Retention Unitsand Standard Units vesting on December 5, 2021 and the remaining 40% of the Retention Units and Standard Units vesting on December5, 2023. The Retention Units and the Standard Units granted on December 5, 2018 will also vest in full upon a Change in Control (asdefined in the LTIP) or the death or Disability (as defined in the LTIP) of the NEO. If Mr. Long retires after attaining the age of 65, 60%of his then-unvested Retention Units will be forfeited, and the remainder will vest, at the time of retirement. With respect to the StandardUnits granted December 5, 2018 to all of the NEOs, if the NEO retires after attaining the age of 65, 60% of his then-unvested StandardUnits will be forfeited, and the remainder will vest, at the time of retirement. If the NEO is over age 68 at the time of retirement, 50% ofhis then-unvested Standard Units granted December 5, 2018 will be forfeited, and the remainder will vest, at the time of retirement. 87 Table of Contents(3)The reported grant date fair value of unit awards was determined in compliance with FASB ASC Topic 718 as more fully described inNote 15 in “Item 8. Financial Statements and Supplementary Data.” Outstanding Equity Awards as of December 31, 2018 The following table provides information regarding phantom units granted to the NEOs pursuant to the LTIP in each ofthe years ended December 31, 2016, 2017 and 2018 that were outstanding as of December 31, 2018. None of the NEOs heldany outstanding option awards as of December 31, 2016, 2017 or 2018. Also reflected in the table are the outstanding ClassB Units in USA Compression Holdings, LLC held by the NEOs as of December 31, 2018. Equity Incentive Plan Awards Number of Market ValueOf Number of Vested and Number of Market Unearned Unearned Outstanding Class B Outstanding Value of Performance Performance Units in USA Standard Outstanding Units ThatHave Units That Compression Holdings, LLC Units Standard Units Not Vested Have NotVestedName (#) (6) (#) ($) (7) (#) ($)Eric D. Long 481,250 2018 Grants 266,874(1)3,464,025 — N/AMatthew C. Liuzzi 62,500 2016 Grant 30,290(2)393,164 — N/A2017 Grant 21,782(3)282,730 — N/A2018 Grants 138,141(4) (5)1,793,070 — N/AWilliam G. Manias 125,000 2016 Grant 37,989(2)493,097 — N/A2017 Grant 27,660(3)359,027 — N/A2018 Grants 156,331(4) (5)2,029,176 — N/ADavid A. Smith 125,000 2016 Grant 12,522(2)162,536 — N/A2017 Grant 10,130(3)131,487 — N/A2018 Grants 50,363(4) (5)653,712 — N/ASean T. Kimble — 2016 Grant 21,392(2)277,668 — N/A2017 Grant 15,142(3)196,543 — N/A2018 Grants 60,949(4) (5)791,118 — N/A(1)On November 1, 2018, Mr. Long received a grant of 90,000 Retention Units pursuant to the LTIP and a Retention Agreement enteredinto by Mr. Long and the General Partner. The Retention Units will vest incrementally, with 60% of the Retention Units vesting onDecember 5, 2021 and 40% of the Retention Units vesting on December 5, 2023. In the event of cessation of Mr. Long’s employmentwithout Cause or for Good Reason (each as defined in his Retention Agreement), all Retention Units that have not vested prior to or inconnection with such cessation of service shall automatically vest in full. The Retention Units will also vest in full upon (i) the death orDisability (as defined in the LTIP) of Mr. Long or (ii) a Change in Control (as defined in the LTIP). On December 5, 2018, Mr. Longreceived a grant of 176,874 Standard Units pursuant to the LTIP with the same vesting schedule as the Retention Units. All of theStandard Units granted on December 5, 2018 will vest in full upon (i) the death or Disability (as defined in the LTIP) of Mr. Long or (ii)a Change in Control (as defined in the LTIP). In the event of the cessation of Mr. Long’s employment for any reason (other than death orDisability), all Standard Units that have not vested prior to or in connection with such cessation of service shall automatically be forfeited.Notwithstanding the foregoing, if Mr. Long retires after attaining the age of 65, 60% of his then-unvested Standard Units and RetentionUnits will be forfeited, and the remainder will vest, at the time of retirement. If Mr. Long is over age 68 at the time of retirement, 50% ofhis then-unvested Standard Units will be forfeited, and the remainder will vest, at the time of retirement. (2)Represents the number of Standard Units granted on February 11, 2016 pursuant to the LTIP that had not vested as of December 31,2018. Each Standard Unit is the economic equivalent of one common unit. The Standard Units vest in three equal annual installments oneach subsequent February 15th, beginning with the first installment that vested on February 15, 2017. In the event of cessation of theNEO’s service for any reason, all Standard Units that have not vested prior to or in connection with such cessation of service shallautomatically be forfeited. In the event of a Change in Control (as defined in the LTIP) followed by a88 Table of Contentstermination of the NEO’s employment without Cause or for Good Reason (each as defined in the applicable LTIP award agreement), allof the NEO’s unvested Standard Units will vest in connection with the NEO’s cessation of service. (3)Represents the number of Standard Units granted on February 13, 2017 pursuant to the LTIP that had not vested as of December 31,2018. Each Standard Unit is the economic equivalent of one common unit. The Standard Units vest in three equal annual installments oneach subsequent February 15th, beginning with the first installment that vested on February 15, 2018. In the event of cessation of theNEO’s service for any reason, all Standard Units that have not vested prior to or in connection with such cessation of service shallautomatically be forfeited. In the event of a Change in Control (as defined in the LTIP) followed by a termination of the NEO’semployment without Cause or for Good Reason (each as defined in the applicable LTIP award agreement), all of the NEO’s unvestedStandard Units will vest in connection with the NEO’s cessation of service. (4)Includes Standard Units granted pursuant to the LTIP on February 12, 2018 (34,554 for Mr. Liuzzi; 43,879 for Mr. Manias; 16,070 forMr. Smith and 24,022 for Mr. Kimble) that had not vested as of December 31, 2018. Each Standard Unit is the economic equivalent ofone common unit. The Standard Units granted on February 12, 2018 vest in three equal annual installments on each subsequent February15th, with the first installment vesting on February 15, 2019. In the event of cessation of the NEO’s service for any reason, all StandardUnits that have not vested prior to or in connection with such cessation of service shall automatically be forfeited. In the event of aChange in Control (as defined in the LTIP) followed by a termination of the NEO’s employment without Cause or for Good Reason(each as defined in the applicable LTIP award agreement), all of the NEO’s unvested Standard Units will vest in connection with theNEO’s cessation of service. Amounts shown also include the following number of Standard Units granted on December 5, 2018 to eachof the NEOs: 176,874 to Mr. Long; 68,587 to Mr. Liuzzi; 67,452 to Mr. Manias; 34,293 to Mr. Smith and 36,927 to Mr. Kimble. TheStandard Units granted on December 5, 2018 vest incrementally, with 60% of the Standard Units vesting on December 5, 2021 and 40%of the Standard Units vesting on December 5, 2023. All of the Standard Units granted on December 5, 2018 will vest in full upon (i) thedeath or Disability (as defined in the LTIP) of the NEO or (ii) a Change in Control (as defined in the LTIP). In the event of the cessationof the NEO’s service for any reason (other than death or Disability), all Standard Units granted on December 5, 2018 that have not vestedprior to or in connection with such cessation of service shall automatically be forfeited. Notwithstanding the foregoing, with respect to theStandard Units granted on December 5, 2018 if the NEO retires after attaining the age of 65, 60% of his then-unvested Standard Unitswill be forfeited, and the remainder will vest, at the time of retirement. If the NEO is over age 68 at the time of retirement, 50% of histhen-unvested Standard Units will be forfeited, and the remainder will vest, at the time of retirement. (5)Includes Retention Units granted on November 1, 2018 (35,000 for Mr. Liuzzi and 45,000 for Mr. Manias) pursuant to the LTIP and theRetention Agreement entered into by the applicable NEO and the General Partner that had not vested as of December 31, 2018. EachRetention Unit is the economic equivalent of one common unit. The Retention Units vest incrementally, with 60% of the Retention Unitsvesting on December 5, 2021 and the remaining 40% of the Retention Units vesting on December 5, 2023. In the event of cessation of theNEO’s service without Cause or for Good Reason (each as defined in the Retention Agreements), all Retention Units that have not vestedprior to or in connection with such cessation of service shall automatically vest in full. The Retention Units will also vest in full upon (i)the death or Disability (as defined in the LTIP) of the NEO or (ii) a Change in Control (as defined in the LTIP). (6)Represents the number of Class B Units in USA Compression Holdings (“USAC Holdings”) that became vested but had not beensettled as of December 31, 2018. These Class B Units vested 25% on the one-year anniversary of the date of grant and 1/36 monthlythereafter; provided that with respect to Mr. Long 50% of the then-unvested portion of Class B Units vested at the time of our initialpublic offering, which occurred on January 18, 2013. There are no distributions or payouts contemplated with respect to the Class BUnits in USAC Holdings. (7)The market value of Standard Units is calculated by multiplying $12.98, the closing price of the Partnership’s common units onDecember 31, 2018, by the number of Standard Units outstanding. 89 Table of ContentsUnits Vested During the Year Ended December 31, 2018 The following table provides information regarding the vesting of Performance Units and Standard Units held by theNEOs during 2018. There are no options outstanding on the Partnership’s common units. Standard Unit Awards Performance Unit Awards Number of Value Number of Value Phantom Realized on Phantom Realized on Units Vested Vesting Units Vested VestingName (#) ($) (5) (#) (6) ($) (7)Eric D. Long 327,554(1)5,657,930 92,405(8)1,564,417Matthew C. Liuzzi 51,024(2)911,799 39,525(9)669,158William G. Manias 63,988(3)1,143,466 49,835(10)843,707David A. Smith 21,531 384,759 17,207 291,315Sean T. Kimble 34,838(4)622,555 27,729(11)469,452(1)This number includes 119,618 Standard Units that vested on February 15, 2018 and 207,936 Standard Units that vested on theTransactions Date in connection with the Transactions. Mr. Long settled approximately 50% of his newly vested Standard Units in cashin the amount of $2,828,965 (before taxes), which cash settlement was reported as a disposition of those Standard Units. The remaining163,777 Standard Units vested following such cash settlement. (2)Mr. Liuzzi settled approximately 50% of his newly vested Standard Units in cash in the amount of $455,900 (before taxes), which cashsettlement was reported as a disposition of those Standard Units. The remaining 25,512 Standard Units vested following such cashsettlement. (3)Mr. Manias settled approximately 50% of his newly vested Standard Units in cash in the amount of $571,733 (before taxes), which cashsettlement was reported as a disposition of those Standard Units. The remaining 31,994 Standard Units vested following such cashsettlement. (4)Mr. Kimble settled approximately 50% of his newly vested Standard Units in cash in the amount of $311,278 (before taxes), which cashsettlement was reported as a disposition of those Standard Units. The remaining 17,419 Standard Units vested following such cashsettlement. (5)The value realized on vesting of Standard Units was calculated by multiplying $17.87, the closing price of the Partnership’s commonunits on the date of vesting (February 15, 2018) by the number of Standard Units vesting. For Mr. Long, whose outstanding StandardUnits vested on the Transactions Date, the value realized on vesting for those units was calculated by multiplying $16.93, the closingprice of the Partnership’s common units on March 29, 2018 (the last business day before the Transactions Date) by the number ofStandard Units vesting. (6)The Performance Units were scheduled to vest, if at all, (i) on the third anniversary of the date of grant at between 0% and 200% of thegranted number of Performance Units based upon our level of TUR relative to a group of peer companies; or (ii) immediately prior to a“Change in Control”. In accordance with the applicable LTIP award agreements, the Performance Units received accelerated vesting attarget levels in connection with the Transactions on the Transactions Date. (7)The value realized on vesting was calculated by multiplying $16.93, the closing price of the Partnership’s common units on March 29,2018, by the number of Performance Units vesting. (8)Mr. Long settled approximately 50% of his newly vested Performance Units for cash in the amount of $782,209 (before taxes), whichcash settlement was reported as a disposition of those Performance Units. The remaining 46,202 Performance Units vested followingsuch cash settlement. (9)Mr. Liuzzi settled approximately 50% of his newly vested Performance Units for cash in the amount of $334,579 (before taxes), whichcash settlement was reported as a disposition of those Performance Units. The remaining 19,762 Performance Units vested followingsuch cash settlement. (10)Mr. Manias settled approximately 50% of his newly vested Performance Units for cash in the amount of $421,854 (before taxes), whichcash settlement was reported as a disposition of those Performance Units. The remaining 24,917 Performance Units vested followingsuch cash settlement. 90 Table of Contents(11)Mr. Kimble settled approximately 50% of his newly vested Performance Units for cash in the amount of $234,726 (before taxes), whichcash settlement was reported as a disposition of those Performance Units. The remaining 13,864 Performance Units vested followingsuch cash settlement. Potential Payments upon Termination or Change in Control The NEOs are entitled to severance payments and/or other benefits upon certain terminations of employment and, incertain cases, in connection with a Change in Control (as defined below) of the General Partner. All capitalized terms used inthe following description but not defined therein shall have the definitions set forth in the referenced document. Retention Phantom Unit Agreements As previously noted, each of Messrs. Long, Liuzzi and Manias entered into a Termination Agreement and MutualRelease (collectively, the “Termination Agreements”) with USAC Management (and, with respect to Mr. Long, the USACompression Partners, LLC) providing for (i) the termination, effective as of November 1, 2018, of the employmentagreements that each of Messrs. Long, Liuzzi and Manias had been party to and (ii) a mutual release by each party to theother(s) of all obligations, claims and causes of action arising under the applicable employment agreement. On November 1, 2018, each of Messrs. Long, Liuzzi and Manias entered into a Retention Agreement providing for agrant of Retention Units that will vest incrementally, with 60% of the Retention Units vesting on December 5, 2021 and theremaining 40% of the Retention Units vesting on December 5, 2023. The Retention Agreements provide for the vesting of100% of the then-unvested Retention Units upon (i) the NEO’s termination of employment without Cause or for GoodReason (ii) a Change in Control or (iii) the death or Disability (as defined under the LTIP) of the NEO. In the event of theNEO’s termination of employment without Cause or for Good Reason, provided that the NEO executes and does not revoke ageneral release and waiver of claims, the NEO will also be entitled to a severance payment intended to capture the value offuture distributions associated with Retention Units forfeited for tax withholding purposes upon vesting. Upon Mr. Long’stermination of employment due to retirement, provided that Mr. Long is at least 65 years of age at the time of such retirement,40% of his then-outstanding, unvested Retention Units will receive accelerated vesting and 60% of his then-outstanding,unvested Retention Units will automatically be forfeited at the time of his retirement pursuant to the terms of Mr. Long’sRetention Agreement. As used in the Retention Agreements, “Cause” means (1) the commission by the NEO of a criminal or other act thatinvolves dishonesty, misrepresentation or moral turpitude; (2) engagement by the NEO in any willful or deliberatemisconduct which causes or is reasonably likely to cause economic damage to the Company, the Partnership or any of its andtheir subsidiaries or injury to the business reputation of the Company, the Partnership or its or their subsidiaries; (3)engagement in any dishonest or fraudulent conduct by the NEO in the performance of the NEO’s duties on behalf of theCompany, the Partnership or its or their subsidiaries, including, without limitation, the theft or misappropriation of funds orthe disclosure of confidential or proprietary information; (4) a knowing breach by the NEO of any fiduciary duty applicableto the NEO in performance of the NEO’s duties as contained in the organizational documents of the Company, thePartnership or any of its or their subsidiaries; (5) the continuing failure or refusal of the NEO to satisfactorily perform theessential duties of the NEO for the Company; (6) improper conduct materially prejudicial to the business of the Company,the Partnership or any of its or their subsidiaries; (7) the material disregard or violation by the NEO of any policy orprocedure of the Company; or (8) any other conduct materially detrimental (as determined in the sole reasonable judgment ofthe Company) to the Company’s, the Partnership’s or its or their subsidiaries’ business. With respect to a termination forCause pursuant to clauses (5), (6), (7) and (8) above, such termination will not be considered for Cause unless the NEO hasbeen given written notice specifying in detail the conduct that allegedly constitutes grounds to terminate for Cause and anopportunity for thirty (30) days after receipt of such notice to cure such grounds, if curable. Termination for Cause underclauses (1), (2), (3) or (4) above cannot be cured by the individual and no such notice to cure will be delivered. “Good Reason” is defined under the Retention Agreements as the occurrence, during the Restricted Period and withoutthe NEO’s prior written consent, of any one or more of the following: (1) a material reduction in the NEO’s current title; (2) amore than 10% reduction by the Company in the NEO’s rate of annual base salary, annual bonus target or annual long-termincentive target, each determined as of the Grant Date; (3) a material diminution in the NEO’s authority, duties, reportingrelationship or responsibilities that is inconsistent in a material and adverse respect with the91 Table of ContentsNEO’s authority, duties, reporting relationship or responsibilities with the Partnership on the date of the Grant Date, providedthat such material diminution is also accompanied with any associated reduction in the NEO’s annual base salary, annualbonus target or annual long-term incentive target, determined based on the NEO’s highest annual base salary, annual bonustarget or annual long-term incentive target during the most recent 365-day period prior to the date the change described inthis clause (3) occurs; or (4) a change of 50 miles or more in the geographic location of the NEO’s principal place ofemployment as of the Grant Date. For any resignation to be treated as based on “Good Reason” under the RetentionAgreement, the following must occur: (x) the NEO must provide written notice to the Company of the existence of the GoodReason condition within a period not to exceed thirty (30) days of the initial existence of the condition; (y) the Companyshall have not less than thirty (30) days following its receipt of such during which it may remedy the condition; and (z) theNEO’s termination of employment must occur within the ninety (90)-day period after the initial existence of the conditionspecified in such notice. Further, no act or omission shall be “Good Reason” if the NEO has consented in writing to such actor omission. “Disability” as defined under the LTIP means, as determined by the Compensation Committee in its discretion exercisedin good faith, a physical or mental condition of the NEO that would entitle him or her to payment of disability incomepayments under the Company’s or the Partnership’s or one of its subsidiaries’ long-term disability insurance policy or planfor employees as then in effect; or in the event that an NEO is not covered, for whatever reason, under the Company’s or thePartnership’s or one of its subsidiaries’ long-term disability insurance policy or plan for employees or the Company’s or thePartnership’s or one of its subsidiaries’ does not maintain such a long-term disability insurance policy, “Disability” means atotal and permanent disability within the meaning of Section 22(e)(3) of the Code; provided, however, that if a Disabilityconstitutes a payment event with respect to any Award which provides for the deferral of compensation and is subject toSection 409A of the Code, then, to the extent required to comply with Section 409A of the Code, the NEO must also beconsidered “disabled” within the meaning of Section 409A(a)(2)(C) of the Code. A determination of Disability may be madeby a physician selected or approved by the Compensation Committee and, in this respect, NEOs shall submit to anexamination by such physician upon request by the Compensation Committee. Accelerated Vestings in 2018 Pursuant to the terms of Mr. Long’s LTIP grant agreements in effect at the time of the Transactions, 100% of hisoutstanding, unvested Standard Units received accelerated vesting on the Transactions Date because the Transactionsconstituted a Change in Control under the LTIP. All unvested Performance Units for all of the NEOs received acceleratedvesting at target levels on the Transactions Date in connection with the Transactions pursuant to the terms of the applicableLTIP grant agreements because the Transactions constituted a Change in Control under the LTIP. The potential paymentscalculated in the “Potential Payments upon Termination or Change in Control” table below only reflect the value of thepotential acceleration of LTIP awards that were still outstanding as of December 31, 2018. Employment Agreements As previously noted, each of Messrs. Smith and Kimble is party to an Employment Agreement providing for certainpayments and benefits upon certain terminations of employment. For the purposes of the following description, the“Company” means USAC Management with respect to Messrs. Smith and Kimble. All capitalized terms used in the followingdescription but not defined therein shall have the definitions set forth in the referenced document. The Employment Agreements provide for the following in the event of a termination of the NEO without Cause or by theNEO with Good Reason: (i) semi-monthly severance payments for the one year period following the NEO’s Separation fromService in an amount totaling the higher of the NEO’s Base Salary for (a) the current year and (b) the previous year (the“Severance Payment”); (ii) the entire amount of any earned Annual Bonus for the year preceding the year in which the NEOis terminated by the Company for convenience or resigns for Good Reason; (iii) a pro rata portion (based on the number ofdays the NEO was employed during the year) of any earned Annual Bonus for the year in which the NEO is terminatedwithout Cause or resigns for Good Reason; (iv) continued health insurance benefits for the NEO and his eligible dependentsfor a period of 24 months, as follows: (a) for the first 12 months of the Coverage Period, the Company will provide suchhealth insurance coverage at its own expense (other than the NEO’s monthly cost-sharing contribution under the Company’sgroup health plan, as in effect at the time of the NEO’s Separation from Service); (b) for the following six months of theCoverage Period, such health insurance coverage will be at the NEO’s92 Table of Contentssole expense; and (c) for the final six months of the Coverage Period, the Company will be responsible for the proportion ofthe cost of such health insurance coverage that the NEO covered in the first 12 months of the Coverage Period; and the NEOwill be responsible for the proportion that the Company covered during the first 12 months of the Coverage Period; and (v)within 30 days of the NEO’s Separation from Service, all earned but unpaid base salary and paid time off. In the event of the termination of Mr. Smith’s or Mr. Kimble’s employment by the Company without Cause or by theNEO with Good Reason within two years of a “change in control event” within the meaning of Treasury Regulation 1.409A-3(i)(5), the Severance Payment will be paid in a lump sum on the Company’s first regular payroll date that occurs on or before30 days after the date of the NEO’s Separation from Service. In the event of a termination of Mr. Smith’s or Mr. Kimble’s employment due to death or Disability (as defined in theEmployment Agreements), the Company shall pay the following to the NEO or the NEO’s estate: (i) the Severance Paymentand (ii) the entire amount of any earned but unpaid Annual Bonus for the year preceding the year in which the NEO dies orbecomes Disabled; (iii) a pro rata portion (based on the number of days employed during the year) of any earned AnnualBonus for the year in which the NEO dies or becomes Disabled; and (iv) all earned but unpaid base salary and paid time off.In the event of the NEO’s death during the Severance Period, the Severance Payment will be paid in a lump sum within 30days of his death. As used in the Employment Agreements, a termination for “convenience” means an involuntary termination for anyreason, including a failure to renew the employment agreement at the end of an initial term or any renewal term, other than atermination for “Cause.” “Cause” is defined in the Employment Agreements to mean (i) any material breach of theEmployment Agreement, including the material breach of any representation, warranty or covenant made under theEmployment Agreement by the NEO, (ii) the NEO’s breach of any applicable duties of loyalty to the Company or any of itsaffiliates, gross negligence or misconduct, or a significant act or acts of personal dishonesty or deceit, taken by the NEO, inthe performance of the duties and services required of the NEO that is demonstrably and significantly injurious to theCompany or any of its affiliates, (iii) conviction of a felony or crime involving moral turpitude, (iv) the NEO’s willful andcontinued failure or refusal to perform substantially the NEO’s material obligations pursuant to the Employment Agreementor follow any lawful and reasonable directive from the CEO or the Board, other than as a result of the NEO’s incapacity, or(v) a violation of federal, state or local law or regulation applicable to the business of the Company that is demonstrably andsignificantly injurious to the Company. “Good Reason” is defined in Employment Agreements to mean (i) a material breach by the Company of the EmploymentAgreement or any other material agreement with the NEO, (ii) a material reduction in the NEO’s base salary, other than areduction that is generally applicable to all similarly situated employees of the Company, (iii) a material reduction in theNEO’s duties, authority, responsibilities, job title or reporting relationships, (iv) a material reduction by the Company in thefacilities or perquisites available to the NEO, other than a reduction that is generally applicable to all similarly situatedemployees, or (v) the relocation of the geographic location of the NEO’s current principal place of employment by more thanfifty miles from the location of the NEO’s principal place of employment as of the Effective Date of the EmploymentAgreement. On January 1, 2013, we entered into a services agreement with USAC Management (as amended, the “ServicesAgreement”), pursuant to which USAC Management provides to us and the General Partner management, administrative andoperating services and personnel to manage and operate our business. Pursuant to the Services Agreement, we will reimburseUSAC Management for the allocable expenses for the services performed, including the salary, bonus, cash incentivecompensation and other amounts paid to our NEOs. See Part III, Item 13 (“Certain Relationships and Related PartyTransactions, and Director Independence”). Change in Control Benefits—LTIP We have historically included double-trigger change in control provisions for our outstanding LTIP awards, such that inorder for accelerated vesting of phantom units to occur in connection with a change in control, such change in control mustbe followed by a termination of employment by the Company without Cause or by the NEO with Good Reason (each asdefined in the applicable phantom unit award agreement). However, in 2018, 2017 and 2016 we granted93 Table of Contentsawards of Performance Units that received accelerated vesting at target levels upon the Change in Control (as defined underthe LTIP and as set forth below) triggered by the Transactions. The following number of Performance Units vested upon theChange in Control in connection with the Transactions: 92,405 for Mr. Long, 39,525 for Mr. Liuzzi, 49,835 for Mr. Manias,17,207 for Mr. Smith and 27,729 for Mr. Kimble. Mr. Long also received immediate vesting of all of his then-outstandingStandard Units in connection with the Transactions pursuant to the terms of his LTIP award agreements in effect at the time. Under the LTIP award agreements entered into prior to the Transactions, in the event of cessation of the NEO’s servicefor any reason, all Standard Units that have not vested prior to or in connection with such cessation of service shallautomatically be forfeited. With respect to unvested Standard Units held by the NEOs, those Standard Units will receiveaccelerated vesting in the event that that the NEO is terminated by the Company without Cause or by the NEO for GoodReason (as each term is defined in the applicable LTIP award agreement) in connection with a change in control event. If a termination occurred immediately following the Transactions, the following number of incremental Standard Unitswould have vested for each of the NEOs (other than Mr. Long): 86,626 for Mr. Liuzzi; 109,528 for Mr. Manias; 38,722 forMr. Smith; and 60,556 for Mr. Kimble. If a termination were to occur on December 31, 2018 following a Change in Control,the following number of Standard Units would vest: 176,874 for Mr. Long, 155,213 for Mr. Liuzzi, 176,980 for Mr. Manias,73,015 for Mr. Smith and 97,483 for Mr. Kimble. Additionally, the following number of Retention Units would vest in theevent of a termination following a Change in Control on December 31, 2018: 90,000 for Mr. Long, 35,000 for Mr. Liuzzi and45,000 for Mr. Manias. On November 1, 2018, the Board approved and adopted the First Amendment to the LTIP which, among other things, (i)updated the definition of Change in Control to refer to Energy Transfer with respect to awards granted on or after April 3,2018; (ii) increased the number of common units of the Partnership available to be awarded under the LTIP by 8,590,000common units (which brings the total number of common units available to be awarded under the LTIP to 10,000,000common units); and (iii) extended the term of the LTIP until November 1, 2028. A “Change in Control” is defined under the LTIP as follows: (a) with respect to Awards granted before April 3, 2018, the occurrence of any of the following events: (i) any “person”or “group” within the meaning of Sections 13(d) and 14(d)(2) of the Exchange Act, other than the Company, RiverstoneHoldings LLC or an Affiliate of the Company (as determined immediately prior to such event) or Riverstone Holdings LLC,shall become the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% ormore of the combined voting power of the equity interests in the Company or the Partnership; (ii) the limited partners of thePartnership approve, in one or a series of transactions, a plan of complete liquidation of the Partnership; (iii) the sale or otherdisposition by either the Company or the Partnership of all or substantially all of its assets in one or more transactions to anyPerson other than the Company, the Partnership, Riverstone Holdings LLC or an Affiliate of the Company, the Partnership orRiverstone Holdings LLC; or (iv) a transaction resulting in a Person other than the Company, Riverstone Holdings LLC oran Affiliate of the Company (as determined immediately prior to such event) or Riverstone Holdings LLC being the solegeneral partner of the Partnership; and (b) with respect to Awards granted on or after April 3, 2018, means the occurrence of any of the following events: (i)any “person” or “group” within the meaning of Sections 13(d) and 14(d)(2) of the Exchange Act, other than the Company,Energy Transfer LP, a Delaware limited partnership (“ET”), Energy Transfer Operating, L.P., a Delaware limited partnership(“ETO”), an Affiliate of the Company (as determined immediately prior to such event), or an Affiliate of, or successor to, ETor ETO, shall become the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of50% or more of the combined voting power of the equity interests in the Company or the Partnership; (ii) the limited partnersof the Partnership approve, in one or a series of transactions, a plan of complete liquidation of the Partnership; (iii) the sale orother disposition by either the Company or the Partnership of all or substantially all of its assets in one or more transactionsto any Person other than the Company, the Partnership, ET, ETO, an Affiliate of the Company (as determined immediatelyprior to such event), the Partnership, or an Affiliate of, or successor to, ET or ETO; or (iv) a transaction resulting in a Personother than the Company, ET, ETO, an94 Table of ContentsAffiliate of the Company (as determined immediately prior to such event), or an Affiliate of, or successor to, ET or ETO beingthe sole general partner of the Partnership. However, if an LTIP award is subject to section 409A of the Internal Revenue Code, a “Change in Control” will bedefined in accordance with section 409A of the Internal Revenue Code and the regulations promulgated thereunder. Also on November 1, 2018, the Board adopted the New Award Agreement, which (i) provides for incremental vesting ofStandard Units over five years (60% on the third December 5 following the grant and 40% on the fifth December 5 followingthe grant) and (ii) provides for vesting of 100% of the outstanding, unvested Standard Units in the event of (a) a Change inControl (as defined under the LTIP and set forth above) or (b) the death or Disability of the NEO. Also, under the New AwardAgreement, if the NEO is at least 65 at the time of his voluntary retirement, 60% of his then-unvested Standard Units will beforfeited, and the remainder will vest, at the time of retirement. If the NEO is over age 68 at the time of his retirement, 50% ofhis then-unvested Standard units will be forfeited, and the remainder will vest, at the time of retirement. 95 Table of ContentsPotential Payments upon Termination or Change in Control Except as otherwise noted, the values in the table below assume that a Change in Control occurred on December 31,2018 and/or that the NEO’s employment terminated on that date, as applicable. The amounts actually payable to any NEOcan only be calculated with certainty upon actual termination or a Change in Control. The value of the acceleration of theLTIP awards was calculated using the value of $12.98, which was the closing price of the Partnership’s common units onDecember 31, 2018. Change in Control followed by Terminationof termination Employment Termination of Terminationby the Continued without without“Cause” Employment ExecutiveOther Employment “Cause” orfor or for because ofDeath Than for FollowingChangeExecutive Benefits and “GoodReason” “GoodReason” or Disability “GoodReason” of ControlPayments ($) (2) ($) (2) ($) (3) ($) (4) ($) (5)Eric D. Long Salary (1) 17,663 17,663 17,663 17,663 —Bonus (1) — — — — —Accelerated Vesting of Standard Units (7) — — 2,295,825 — 2,295,825Accelerated Vesting of Retention Units (8) 1,168,200 1,168,200 1,168,200 — 1,168,200Severance Payment under Retention Agreements(9) 359,100 359,100 — — —Totals 1,544,963 1,544,963 3,481,688 17,663 3,464,025Matthew C. Liuzzi Salary (1) 10,609 10,609 10,609 10,609 —Bonus (1) — — — — —Accelerated Vesting of Standard Units (7) 2,014,664 1,124,405 890,259 — 890,259Accelerated Vesting of Retention Units (8) 454,300 454,300 454,300 — 454,300Severance Payment under Retention Agreements(9) 139,650 139,650 — — —Totals 2,619,223 1,728,964 1,355,168 10,609 1,344,559William G. Manias Salary (1) 11,975 11,975 11,975 11,975 —Bonus (1) — — — — —Accelerated Vesting of Standard Units (7) 2,297,200 1,421,673 875,527 — 875,527Accelerated Vesting of Retention Units (8) 584,100 584,100 584,100 — 584,100Severance Payment under Retention Agreements(9) 179,550 179,550 — — —Totals 3,072,825 2,197,298 1,471,602 11,975 1,459,627David A. Smith Salary (1) 554,763 554,763 554,763 13,763 —Bonus (1) 382,710 382,710 382,710 — —Accelerated Vesting of Standard Units (7) 947,735 502,612 445,123 — 445,123Health and Welfare Plan Benefits (6) 24,102 24,102 — — —Totals 1,909,310 1,464,187 1,382,596 13,763 445,123Sean T. Kimble Salary (1) 330,950 330,950 330,950 8,429 —Bonus (1) 273,457 273,457 273,457 — —Accelerated Vesting of Standard Units (7) 1,265,329 786,017 479,312 — 479,312Health and Welfare Plan Benefits (6) 24,102 24,102 — — —Totals 1,893,838 1,414,526 1,083,719 8,429 479,31296 Table of Contents(1)The listed salary for each of Messrs. Smith and Kimble represents his annualized rate of pay as of December 31, 2018, plus, with respectto the first three columns of the table, his accrued but unused paid time off as of December 31, 2018. The listed bonus amount for each ofMessrs. Smith and Kimble is his bonus awarded with respect to the year ended December 31, 2018. Because the assumed terminationdate for each NEO is December 31, 2018, no pro rata bonus amounts based on a partial year of continued employment prior totermination are included. The amount shown for each of Messrs. Long, Liuzzi and Manias represents the amount of earned but unpaidbase salary he would be entitled to receive. (2)The Employment Agreements for each of Messrs. Smith and Kimble provide that upon termination by the Company without Cause or bythe NEO for Good Reason, the NEO is entitled to receive one times his base salary, payable in equal semimonthly installments over thecourse of one year (or, if such termination occurs within two years after a “change in control event” within the meaning of TreasuryRegulation 1.409A-3(i)(5), in a lump sum within 30 days of termination of employment). (3)Upon the death or Disability of Mr. Kimble or Mr. Smith during the Severance Period (as defined in the Employment Agreements), hissalary payment will be accelerated and he (or his estate) will be entitled to the same bonus payment as if the death or Disability had notoccurred. (4)In the event of the termination of employment by any of the NEOs without Good Reason, the NEO will be entitled to all earned butunpaid annual base salary. (5)The NEOs are not entitled to a certain level of compensation in the event of continued employment following a Change in Control, but forpurposes of this table it is assumed that the NEO would continue to receive a level of base salary, bonus, benefits and other compensationin the event of continued employment following a Change in Control that is the same as, or similar to, the amounts shown in theSummary Compensation Table. Accordingly, no additional amounts are shown for salary, bonus or health and welfare plan benefitsbecause those amounts would remain as in effect at the time of the Change in Control. (6)In the event of Mr. Smith’s or Mr. Kimble’s termination by the Company without Cause or by the NEO with Good Reason, he and hiseligible dependents will be entitled to continued health insurance benefits for a period of 24 months following his Separation from Service(the “Coverage Period”), as follows: (i) for the first twelve months of the Coverage Period, the Company will provide such healthinsurance coverage at its own expense (other than the NEO’s monthly cost-sharing contribution under the Company’s group health plan,as in effect at the time of the NEO’s Separation from Service) (ii) for the following six months of the Coverage Period, such healthinsurance coverage will be at the NEO’s sole expense; and (iii) for the final six months of the Coverage Period, the Company will beresponsible for the proportion of the cost of such health insurance coverage that the NEO covered in the first 12 months of the CoveragePeriod; and the NEO will be responsible for the proportion that the Company covered during the first 12 months of the Coverage Period.The amount shown represents the Company’s contribution to the NEO’s health insurance benefits during the first half of the CoveragePeriod. Messrs. Long, Liuzzi and Manias are not currently party to any contractual arrangements providing for continued health insurancecoverage by the Company following a termination of employment. (7)In the event of the NEO’s cessation of service for any reason (other than death or Disability), 100% of the NEO’s Standard Units thathave not vested prior to or in connection with such cessation of service shall be automatically forfeited. Notwithstanding the foregoing,with respect to the Standard Units granted on December 5, 2018, if the NEO retires after attaining the age of 65, 60% of his then-unvested Standard Units will be forfeited, and the remainder will vest, at the time of retirement. For the Standard Units granted onDecember 5, 2018, if the NEO is over age 68 at the time of retirement, 50% of his then-unvested Standard Units will be forfeited, and theremainder will vest, at the time of retirement. For the Standard Units granted on December 5, 2018, in the event of the death or Disabilityof the NEO, 100% of the then-unvested Standard Units shall vest in full immediately prior to such cessation of service due to death orDisability. In the event of a Change in Control (as defined under the LTIP), 100% of the NEO’s outstanding, unvested Standard Unitsgranted on December 5, 2018 would vest. (8)The Retention Agreements for Messrs. Long, Liuzzi and Manias provide that 100% of the outstanding, unvested Retention Units held bythe applicable NEO will vest immediately prior to the NEO’s Separation from Service for the following reasons: (i) termination of theNEO by the Company without Cause or by the NEO with Good Reason, (ii) upon a Change in Control, and (iii) upon the death orDisability of the NEO. Also, if Mr. Long terminates his employment due to retirement, if he is at the time of retirement 65 years of age orolder, 40% of his then-unvested Retention Units will vest and the remaining 60% of his then-unvested Retention Units will be forfeited. (9)For Messrs. Long, Liuzzi and Manias, provided that the NEO executes and does not revoke a general release and waiver of claims, theNEO will be entitled to a severance payment intended to capture the value of future distributions associated with Retention Units forfeitedfor tax withholding purposes. 97 Table of ContentsDirector Compensation For the year ended December 31, 2018, our CEO was the only NEO who also served as a director, and he did not receiveadditional compensation for his service on the Board. Mr. Long’s compensation as an NEO is reflected in the SummaryCompensation Table above. Other than Mr. Hartman, all of the independent members of the Board receive cash and equitycompensation for their service as directors. The following table shows the total fees earned and other compensation paid in cash to each independent director during2018. Fees Earned or All Other Paid in Cash Unit Awards Compensation TotalName ($) ($) (1) ($) (2) ($)Robert F. End (3) (4) 55,250 — 10,692 65,942Jerry L. Peters (3) (5) 55,250 — — 55,250Forrest E. Wylie (3) (6) 51,500 — 21,386 72,886Matthew S. Hartman (7) (8) — — — —Glenn E. Joyce (7) 122,500 140,350 9,130 271,980William S. Waldheim (7) 124,375 140,350 9,130 273,855(1)Represents the grant date fair value of our Standard Units, calculated in accordance with ASC 718. For a detailed discussion of theassumptions utilized in coming to these values, please see Note 15 to our consolidated financial statements. As of December 31, 2018, theindependent members of the Board who receive equity awards held the following number of outstanding equity awards under the LTIP:Mr. Joyce: 8,695 Standard Units; and Mr. Waldheim: 8,695 Standard Units. Mr. Joyce’s and Mr. Waldheim’s respective totals includethe following grants made on July 30, 2018: (i) a one-time director onboarding grant of 2,500 Standard Units and (ii) an annual grant ofStandard Units with a value of $100,000, based on the closing price of the Partnership’s common units on the date of grant. The StandardUnits held by Messrs. Joyce and Waldheim vest incrementally, with 60% of the Standard Units vesting on December 5, 2020 and theremaining 40% of the Standard Units vesting on December 5, 2022. In the event of the director’s cessation of service to due death,Disability or a Change in Control, 100% of his outstanding, unvested Standard Units will vest immediately prior to such event. (2)Amounts in this column reflect the value of DERs, received by the directors with respect to their outstanding phantom unit awards. ForMessrs. Joyce and Waldheim, the amount shown includes DERs paid with respect to the Partnership’s quarterly distribution on itscommon units with respect to the second and third quarters of 2018. (3)Effective as of the Transactions Date, Messrs. End, Peters and Wylie resigned from the Board in connection with the Transactions;therefore this table reflects their compensation for the period from January 1, 2018 to the Transactions Date. (4)Consists of (i) $36,500 in cash retainer and meeting attendance fees (a) for the fourth quarter of 2017 (which were paid in the first quarterof 2018) and (b) earned in the first quarter of 2018; (ii) $18,750 in cash in lieu of a grant of the annual grant of phantom units under theLTIP, which payment was approved by the Board on March 29, 2018 and the amount of which represents one quarter of the value of theannual grant of phantom units that the director would have otherwise received; and (iii) $10,692 of DERs. (5)Consists of (i) $36,500 in cash retainer and meeting attendance fees (a) for the fourth quarter of 2017 (which were paid in the first quarterof 2018) and (b) earned in the first quarter of 2018; and (ii) $18,750 in cash in lieu of a grant of the annual grant of phantom units underthe LTIP, which payment was approved by the Board on March 29, 2018 and the amount of which represents one quarter of the value ofthe annual grant of phantom units that the director would have otherwise received. (6)Consists of (i) a $32,750 in cash retainer and meeting attendance fees (a) for the fourth quarter of 2017 (which were paid in the firstquarter of 2018) and (b) earned in the first quarter of 2018; (ii) $18,750 in cash in lieu of a grant of the annual grant of phantom unitsunder the LTIP, which payment was approved by the Board on March 29, 2018 and the amount of which represents one quarter of thevalue of the annual grant of phantom units that the director would have otherwise received; (iii) $21,386 of DERs. 98 Table of Contents(7)Messrs. Hartman, Joyce and Waldheim were appointed to the Board on the Transactions Date in connection with the Transactions;therefore, this table reflects their compensation for the period from the Transactions Date through December 31, 2018. For Mr. Joyce, theamount shown consists of (i) $122,500 in cash retainer for service on the Board, as Chair of the Compensation Committee and as amember of the Audit Committee; (ii) $140,350 in Standard Units awarded; and (iii) $9,130 of DERs. For Mr. Waldheim, the amountshown consists of (i) $124,375 in cash retainer for service on the Board, as Chair of the Audit Committee and as a member of theCompensation Committee; (ii) $140,350 in Standard Units awarded; and (iii) $9,130 of DERs. (8)Mr. Hartman was appointed to the Board pursuant to that certain Board Representation Agreement entered to among us, the GeneralPartner, ETE and EIG on the Transactions Date in connection with our private placement to EIG of Preferred Units and Warrants. Mr.Hartman does not receive compensation for his service on the Board. Officers, employees or paid consultants or advisors of us or the General Partner or its affiliates who also serve as directorsdo not receive additional compensation for their service as directors. Other than Mr. Hartman, our directors who are notofficers, employees or paid consultants or advisors of us or the General Partner or its affiliates receive cash and equity basedcompensation for their services as directors. Our director compensation program is subject to revision by the Board from timeto time. On July 30, 2018 the Board adopted the Amended and Restated Outside Director Compensation Policy (the “NewDirector Compensation Policy”) effective on the Transactions Date. The New Director Compensation Policy differs from theprevious director compensation plan (the “Previous Director Compensation Policy”) in several ways. The New DirectorCompensation Policy makes the following changes to bring our director compensation program more in line with EnergyTransfer’s director compensation program and consistent with the levels of director compensation at similarly situatedcompanies: (i) increases the annual cash retainer for the independent directors from $75,000 to $100,000 and removes theoption for the director to elect to receive such retainer in common units rather than cash; (ii) increases the cash retainer foracting as Chairman of a standing committee; (iii) awards different levels of annual cash retainer for acting as the Chairman ofthe Audit Committee and acting as Chairman of the Compensation Committee; (iv) adds a retainer for membership on astanding committee; (v) discontinues per meeting attendance fees; (vi) increases the value of the annual equity grant from$75,000 to $100,000; (vii) provides for a one-time director onboarding equity of 2,500 Standard Units; (viii) alters thevesting schedule for the Standard Units from vesting in full on the one year anniversary of the grant to incremental vestingover five years; and (ix) provides for vesting in full of all outstanding, unvested Standard Units in the event of the director’sdeath, Disability or upon a Change in Control. 99 Table of ContentsThe following chart summarizes the key differences between the Previous Director Compensation Policy and the NewDirector Compensation Policy. Compensation ElementPrevious Director Compensation Policy New Director Compensation Policy Annual Cash Retainer$75,000 (or in common units at director’selection) $100,000 Committee Chair Cash RetainerAny Standing Committee: $15,000 Audit Committee: $25,000Compensation Committee: $15,000 Committee Membership Retainer (if not Committee Chair) None Audit Committee: $15,000Compensation Committee: $7,500 Initial Phantom Unit AwardNone 2,500 Standard Units Annual Phantom Unit Award$75,000 value $100,000 value DERs on Unvested Phantom UnitsYes (paid on a current or deferred basis asdetermined at the time of grant) Yes (paid on a current basis) Phantom Unit Vesting ScheduleVest in full 1 year from grant date 60% vest on third December 5following grant40% vest on fifth December 5following grant Change-in-ControlUnvested phantom units vest in full, but ifdirector ceases service, all unvested phantomunits forfeited Unvested phantom units vest in full Cessation of Service due to Death orDisabilityAll unvested phantom units forfeited Unvested phantom units vest in full Attendance Fee Per Meeting$2,000 None Reimbursement of Out-of-PocketExpensesYes Yes IndemnificationYes, to fullest extent permitted underDelaware law Yes, to fullest extent permitted underDelaware law ITEM 12.Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters Pursuant to the terms of the Equity Restructuring Agreement the Partnership entered into on January 15, 2018, at anytime after the first anniversary of the Transactions Date, ETO has the right to contribute (or cause any of its subsidiaries tocontribute) to the Partnership all of the outstanding equity interests in any of its subsidiaries that owns the General PartnerInterest (as defined in the Equity Restructuring Agreement) in exchange for $10,000,000 (the “GP Contribution”); providedthat the GP Contribution will occur automatically if at any time following the Transactions Date (i) ETO or one of itsaffiliates (including ET LP) owns, directly or indirectly, the General Partner Interest and (ii) ETO and its affiliates (includingET LP) collectively own less than 12,500,000 of the Partnership’s common units. Security Ownership of Certain Beneficial Owners and Management The following table sets forth the beneficial ownership of the Partnership’s common units and Series A Preferred Units asof February 14, 2019 held by: ·each person who beneficially owns 5% or more of the Partnership’s outstanding common units;100 Table of Contents ·all of the directors of the General Partner; ·each NEO of the General Partner; and ·all directors and NEOs of the General Partner as a group. As of February 14, 2019, there were 90,000,504 common units outstanding. Except as indicated by footnote, the personsnamed in the table below have sole voting and investment power with respect to all common units shown as beneficiallyowned by them and their address is 100 Congress Avenue, Suite 450, Austin, Texas 78701. Common Units Percentage of Name of Beneficial Owner Beneficially Owned Common Units Energy Transfer Operating, L.P. (1) (2) 39,658,263 44.07% Oppenheimer Funds, Inc. (3) 18,084,216 20.10% EIG Veteran Equity Aggregator, L.P. (4) 12,619,921 14.02% Eric D. Long (5) 489,940 * Matthew C. Liuzzi (6) 175,289 * William G. Manias (7) 225,989 * David A. Smith (8) 106,545 * Sean T. Kimble (9) 93,877 * Michael Bradley — * Christopher R. Curia — * Matthew S. Hartman — * Glenn E. Joyce — * Thomas E. Long — * Thomas P. Mason — * Matthew S. Ramsey — * William S. Waldheim — * All directors and officers as a group (14 persons) (10) 1,110,203 1.23% *Less than 1%. (1)Energy Transfer Operating, L.P. has sole voting and dispositive power over 39,658,263 common units based on a Schedule 13D filed onApril 11, 2018 with the SEC. The principal business address of Energy Transfer Operating, L.P. is 8111 Westchester Drive, Suite 600,Dallas, Texas 75225. (2)Includes 8,000,000 common units held by USA Compression GP, LLC. (3)Oppenheimer Funds, Inc. has the shared power to dispose or to direct the disposition of 18,084,216 common units based on AmendmentNo. 10 to Schedule 13G filed on January 14, 2019 with the SEC. Pursuant to the provisions of the Partnership Agreement providing thatthe holder of 20% or more of any class of the Partnership’s securities may not, subject to certain exceptions, vote any of those securities,Oppenheimer Funds, Inc. does not have the shared power to vote or direct the vote with respect to any of the common units it owns. Theprincipal business address of Oppenheimer Funds, Inc. is Two World Financial Center, 225 Liberty Street, New York, New York10281. (4)EIG Veteran Equity Aggregator, L.P. holds Warrants to acquire (i) 4,206,240 common units of the Partnership at an exercise price of$17.03 per common unit and (ii) 8,413,281 common units of the Partnership at an exercise price of $19.59 per common unit. TheWarrants become exercisable on April 2, 2019 and will expire on April 2, 2028. Upon exercise of the Warrants in full and assuming thePartnership does not elect to settle the Warrants in common units on a net basis, EIG would have sole voting and dispositive power over12,619,921 common units of the Partnership based on the Schedule 13D filed on February 4, 2019 with the SEC. The principal businessaddress of EIG Veteran Equity Aggregator, L.P. is 333 Clay Street, Suite 3500, Houston, Texas 77002. (5)Includes 414,926 common units held directly by Mr. Long, 17,592 common units held by Aladdin Partners, L.P., a limited partnershipaffiliated with Mr. Long, 55,248 common units held by certain trusts of which Mr. Long is the trustee and 2,174101 Table of Contentscommon units held by Mr. Long’s spouse. Mr. Long disclaims any beneficial ownership of the units held by Mr. Long’s spouse, exceptto the extent of his pecuniary interest therein. (6)Includes 52,699 common units that Mr. Liuzzi has the right to acquire within 60 days upon the vesting and/or settlement of his StandardUnits and Retention Units, subject to Compensation Committee discretion. (7)Includes 66,446 common units that Mr. Manias has the right to acquire within 60 days upon the vesting and/or settlement of his StandardUnits and Retention Units, subject to Compensation Committee discretion. (8)Includes 22,944 common units that Mr. Smith has the right to acquire within 60 days upon the vesting and/or settlement of his StandardUnits, subject to Compensation Committee discretion. (9)Includes 36,971common units that Mr. Kimble has the right to acquire within 60 days upon the vesting and/or settlement of his StandardUnits, subject to Compensation Committee discretion. (10)Includes 186,509 common units that certain of our directors and executive officers have the right to receive within 60 days upon thevesting and/or settlement of phantom units held by such directors and executive officers. Securities Authorized for Issuance Under Equity Compensation Plans In connection with our IPO on January 18, 2013, the Board adopted the LTIP. On November 1, 2018, the Boardapproved and adopted the First Amendment to the LTIP (the “First Amendment”) with immediate effectiveness. The FirstAmendment (i) increased the number of common units available to be awarded under the LTIP by 8,590,000 common units(which brings the total number of common units available to be awarded under the LTIP to 10,000,000 common units); (ii)provided that common units withheld to satisfy the exercise price or tax withholding obligations with respect to an awardwill not be considered to be common units that have been delivered under the LTIP; (iii) for awards granted on or after April3, 2018, modifies the definition of “Change in Control” under the LTIP to refer to Energy Transfer Operating, L.P., EnergyTransfer LP and their Affiliates (as defined under the LTIP) and successors; (iv) updated the tax withholding provision of theLTIP and (v) extended the term of the LTIP until November 1, 2028. The following table provides certain information with respect to the LTIP as of December 31, 2018: Number of securities remaining available for future issuance under Number of securities to Weighted-average equity compensation be issued upon exercise exercise price of plan (excluding securities of outstanding options, outstanding options, reflected in the first Plan Category warrants and rights warrants and rights column) Equity compensation plans approved by securityholders — N/A — Equity compensation plans not approved by securityholders 1,429,078 N/A 10,000,000(1)(1)As of December 31, 2018, the number of common units that may be delivered pursuant to awards under the LTIP was 10,000,000common units before giving effect to any outstanding awards. Phantom units withheld to satisfy the exercise price or tax withholdings ofan award and phantom units that are forfeited, cancelled, paid or otherwise terminate or expire without the actual delivery of commonunits will be available for delivery pursuant to other awards. Currently, only phantom unit awards are outstanding under theLTIP. Pursuant to the terms of the LTIP, each phantom unit is the economic equivalent of one common unit and, other than directorphantom unit awards, may be settled in cash or common units at the discretion of the Board or a committee thereof. Any phantom unitsettled in cash will not result in the actual delivery of a common unit. For more information about the LTIP, please see Note 15 to our consolidated financial statements. 102 Table of Contents ITEM 13.Certain Relationships and Related Party Transactions, and Director Independence Certain Relationships and Related Party Transactions Services Agreement In connection with our formation and IPO, we and other parties have entered into the agreements described below. Theseagreements were not the result of arm’s length negotiations, and they, or any of the transactions that they provide for, maynot be effected on terms as favorable to the parties to these agreements as could have been obtained from unaffiliated thirdparties. We entered into that certain Services Agreement with USAC Management, a wholly owned subsidiary of the GeneralPartner, effective on January 1, 2013 (the “Services Agreement”), pursuant to which USAC Management provides to us andthe General Partner management, administrative and operating services and personnel to manage and operate our business.We or one of our subsidiaries pays USAC Management for the allocable expenses it incurs in its performance under theServices Agreement. These expenses include, among other things, salary, bonus, cash incentive compensation and otheramounts paid to persons who perform services for us or on our behalf and other expenses allocated by USAC Management tous. USAC Management has substantial discretion to determine in good faith which expenses to incur on our behalf and whatportion to allocate to us. On November 3, 2017, the Services Agreement was amended to extend its term to December 31, 2022. The ServicesAgreement may be terminated at any time by (i) the Board upon 120 days’ written notice for any reason in its sole discretionor (ii) USAC Management upon 120 days’ written notice if: (a) we or the General Partner experience a Change of Control (asdefined in the Services Agreement); (b) we or the General Partner breach the terms of the Services Agreement in any materialrespect following 30 days’ written notice detailing the breach (which breach remains uncured after such period); (c) a receiveris appointed for all or substantially all of our or the General Partner’s property or an order is made to wind up our or theGeneral Partner’s business; (d) a final judgment, order or decree that materially and adversely affects the ability of us or theGeneral Partner to perform under the Services Agreement is obtained or entered against us or the General Partner, and suchjudgment, order or decree is not vacated, discharged or stayed; or (e) certain events of bankruptcy, insolvency orreorganization of us or the General Partner occur. USAC Management will not be liable to us for their performance of, orfailure to perform, services under the Services Agreement unless its acts or omissions constitute gross negligence or willfulmisconduct. Transactions with Energy Transfer We provide compression services to entities affiliated with Energy Transfer, which became a related party of ours on theTransactions Date as a result of the Transactions and its resultant ownership and control of the General Partner and ownershipof approximately 44% of our limited partner interests as of December 31, 2018 (including the 8,000,000 common unitsowned by the General Partner and before giving effect to the conversion of the 6,397,965 Class B Units to common units thatwill occur in 2019). We recognized $17.1 million in revenue from compression services from entities affiliated with EnergyTransfer for the year ended December 31, 2018. We may provide compression services to entities affiliated with EnergyTransfer in the future, and any significant transactions will be disclosed. 103 Table of ContentsThe following table summarizes payments and accounts receivable and payable between us and Energy Transfer during2018. TransactionExplanationAmount/Value2018 quarterly distributions on limitedpartner interests (three quarters)Represents the aggregate amount of distributions made to EnergyTransfer in respect of the Partnership’s common units during2018.$62.5 millionRevenue for compression servicesRepresents the aggregate amount of revenue recognized forproviding compression services to entities affiliated with EnergyTransfer for the full year 2018.$17.1 millionSales Tax ContingencyReceivable from ETP as of December 31, 2018 related toindemnification for sales tax contingencies incurred by the USACompression Predecessor.$44.9 millionAccounts receivableReceivables for compression services provided to entitiesaffiliated with Energy Transfer as of December 31, 2018.$2.7 millionAccounts payablePayables to entities affiliated with Energy Transfer as ofDecember 31, 2018.$0.4 million Other Related Party Transactions We provide compression services to entities affiliated with Riverstone/Carlyle Global Energy and Power Fund IV, L.P.(“Riverstone”), which owned a majority of the membership interests in USA Compression Holdings, LLC, (“USACHoldings”), which owned and controlled the General Partner and owned approximately 40% of our limited partner interestsbefore the Transactions. We recognized $0.3 million and $0.7 million in revenue from compression services from suchaffiliated entities for the years ended December 31, 2018 and 2017. On the Transactions Date and in connection with the Transactions, three NEOs who held Class A Units in USACHoldings received cash distributions from USAC Holdings in the following amounts pursuant to the terms of the Amendedand Restated Limited Liability Company Agreement of USA Compression Holdings, LLC (the “Holdings LLC Agreement”):Eric D. Long, approximately $1.1 million; William G. Manias, approximately $374,000; and David A. Smith, approximately$374,000. On June 15, 2018, USAC Holdings sold 5,000,000 common units of the Partnership in a secondary offering (the“Secondary Offering”). In connection with the Secondary Offering, in June 2018 two NEOs who held Class A Units in USACHoldings received cash distributions from USAC Holdings in the following amounts pursuant to the terms of the HoldingsLLC Agreement: Eric D. Long, approximately $420,000; and David A. Smith, approximately $140,000. As of August 30, 2018, Riverstone was no longer a related party due to its sale of the General Partner to Energy Transferin connection with the Transactions and its divestiture of all of its remaining common units in a privately negotiated blocktrade (the “August Trade”), as reported on Amendment No. 15 to Schedule 13D Riverstone filed with the SEC on August 30,2018. In connection with the August Trade, in September 2018 two NEOs who held Class A Units in USAC Holdingsreceived cash distributions from USAC Holdings in the following amounts pursuant to the terms of the Holdings LLCAgreement: Eric D. Long, approximately $537,000; and David A. Smith, approximately $179,000. Conflicts of Interest Conflicts of interest exist and may arise in the future as a result of the relationships between the General Partner and itsaffiliates, including Energy Transfer, on the one hand, and the Partnership and its limited partners, on the other hand. Thedirectors and officers of the General Partner have fiduciary duties to manage the General Partner in a manner beneficial to itsowners. At the same time, the General Partner has a fiduciary duty to manage the Partnership in a manner beneficial to us andour unitholders. Whenever a conflict arises between the General Partner or its affiliates, on the one hand, and the Partnership and itslimited partners, on the other hand, the General Partner will resolve that conflict. The Partnership Agreement containsprovisions that modify and limit the General Partner’s fiduciary duties to the Partnership’s unitholders. The Partnership104 Table of ContentsAgreement also restricts the remedies available to the Partnership’s unitholders for actions taken by the General Partner that,without those limitations, might constitute breaches of its fiduciary duty. The Partnership Agreement provides that the General Partner will not be in breach of its obligations under thePartnership Agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of aconflict of interest is (a) approved by the conflicts committee of the Board, although the General Partner is not obligated toseek such approval; (b) approved by the vote of a majority of our outstanding common units, excluding any common unitsowned by the General Partner and its affiliates; (c) on terms no less favorable to us than those generally being provided to oravailable from unrelated third parties; or (d) fair and reasonable to us, taking into account the totality of the relationshipsamong the parties involved, including other transactions that may be particularly favorable or advantageous to us. The General Partner may, but is not required to, seek the approval of such resolution from the conflicts committee of theBoard. In connection with a situation involving a conflict of interest, any determination by the General Partner must be madein good faith, provided that, if the General Partner does not seek approval from the conflicts committee and the Boarddetermines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standardsset forth in subclauses (c) or (d) above, then it will conclusively be deemed that, in making its decision, the Board acted ingood faith. Unless the resolution of a conflict is specifically provided for in the Partnership Agreement, the General Partner orthe conflicts committee may consider any factors that it determines in good faith to be appropriate when resolving a conflict.When the Partnership Agreement provides that someone act in good faith, it requires that person to reasonably believe he isacting in the best interests of the Partnership. Please read Part I, Item 1A (“Risk Factors—Risks Inherent in an Investment inUs”). Procedures for Review, Approval and Ratification of Related Person Transactions If a conflict or potential conflict of interest arises between the General Partner and its affiliates, including EnergyTransfer, on the one hand and the Partnership and its limited partners, on the other hand, the resolution of any such conflictor potential conflict is addressed as described under “−Conflicts of Interest.” Pursuant to the Partnership’s Code of Business Conduct and Ethics and Corporate Governance Guidelines, directors,officers and employees are required to disclose any situations that reasonably would be expected to give rise to a conflict ofinterest and report it to their supervisor, the Partnership’s general counsel or the Board, as appropriate. Director Independence Please see Part III, Item 10 (“Directors, Executive Officers and Corporate Governance—Board of Directors”) for adiscussion of director independence matters. ITEM 14.Principal Accountant Fees and Services The following table sets forth fees paid for professional services rendered by KPMG LLP, our independent registeredpublic accounting firm until April 5, 2018, during the year ended December 31, 2017: Year EndedDecember31, 2017 (in millions)Audit Fees (1) $0.6Audit-Related Fees —Tax Fees —All Other Fees —Total $0.6(1)Expenditures classified as “Audit Fees” above were billed to the Partnership and include the audits of our annual financial statements,work related to the registration statements, reviews of our quarterly financial statements, and fees associated with comfort letters andconsents related to securities offerings and registration statements.105 Table of Contents The following table sets forth fees paid for professional services rendered by Grant Thornton LLP (“Grant Thornton”),our independent registered public accounting firm since April 5, 2018, during the year ended December 31, 2018: Year EndedDecember31, 2018 (1) (in millions)Audit Fees (2) $1.5Audit-Related Fees —Tax Fees —All Other Fees —Total $1.5(1)In connection with the Transactions, we appointed Grant Thornton as our independent registered public accounting firm on April 5, 2018. (2)Expenditures classified as “Audit Fees” above were billed to the Partnership and include the audits of our annual financial statements andinternal control over financial reporting, reviews of our quarterly financial statements, and fees associated with comfort letters andconsents related to securities offerings and registration statements. The Audit Committee has adopted the Audit Committee Charter, which is available on our website and which requiresthe Audit Committee to pre-approve all audit and non-audit services to be provided by our independent registered publicaccounting firm. The Audit Committee does not delegate its pre-approval responsibilities to management or to an individualmember of the Audit Committee. The Audit Committee approved 100% of the services described above. 106 Table of Contents 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: 107 Table of ContentsExhibitNumber Description2.1 Contribution Agreement dated as of January 15, 2018, by and among USA Compression Partners, LP,Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., ETC Compression, LLC and, solely forcertain purposes therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 to thePartnership’s Current Report on Form 8-K (File No. 001-35779) filed on January 16, 2018) 2.2 Equity Restructuring Agreement, dated as of January 15, 2018, by and among Energy Transfer Equity,L.P., USA Compression Partners, LP and USA Compression GP, LLC (incorporated by reference toExhibit 2.2 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on January 16,2018) 3.1 Certificate of Limited Partnership of USA Compression Partners, LP (incorporated by reference to Exhibit3.1 to Amendment No. 3 of the Partnership’s registration statement on Form S-1 (Registration No. 333-174803) filed on December 21, 2011) 3.2 Second Amended and Restated Agreement of Limited Partnership of USA Compression Partners, LP(incorporated by reference to Exhibit 3.1 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on April 6, 2018) 4.1 Indenture, dated as of March 23, 2018 by and among USA Compression Partners, LP, USA CompressionFinance Corp., the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, astrustee (incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K (FileNo. 001-35779) filed on March 26, 2018) 4.2 First Supplemental Indenture, dated as of April 2, 2018, among USA Compression Partners, LP, USACompression Finance Corp., the guarantors named on the signature pages thereto and Wells Fargo Bank,National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Partnership’s CurrentReport on Form 8-K (File No. 001-35779) filed on April 6, 2018) 4.3 Form of 6.875% Senior Note due 2026 (incorporated by reference to Exhibit 4.2 to the Partnership’sCurrent Report on Form 8-K (File No. 001-35779) filed on March 26, 2018) 4.4 Registration Rights Agreement, dated as of March 23, 2018, by and among USA Compression Partners,LP, USA Compression Finance Corp., the subsidiary guarantors named therein and J.P. Morgan SecuritiesLLC and Barclays Capital Inc., as representatives of the initial purchasers named therein (incorporated byreference to Exhibit 4.3 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed onMarch 26, 2016). 4.5 Registration Rights Agreement, dated as of April 2, 2018, by and among USA Compression Partners, LP,ETE, ETP and USA Compression Holdings, LLC (incorporated by reference to Exhibit 4.1 to thePartnership’s Current Report on Form 8-K (File No. 001-35779) filed on April 6, 2018) 4.6 Registration Rights Agreement, dated as of April 2, 2018, by and between USA Compression Partners, LPand the Purchasers party thereto (incorporated by reference to Exhibit 4.2 to the Partnership’s CurrentReport on Form 8-K (File No. 001-35779) filed on April 6, 2018) 4.7 Board Representation Agreement, dated as of April 2, 2018, by and among USA Compression Partners,LP, USA Compression GP, LLC, Energy Transfer Equity, L.P. and the Purchasers party thereto(incorporated by reference to Exhibit 4.3 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on April 6, 2018) 10.1 Fifth Amended and Restated Credit Agreement dated as of December 13, 2013, by and among USACompression Partners, LP, USAC OpCo 2, LLC and USAC Leasing 2, LLC, as guarantors, USACompression Partners, LLC and USAC Leasing, LLC, as borrowers, the lenders party thereto from time totime, JPMorgan Chase Bank, N.A., as agent and LC issuer, J.P. Morgan Securities LLC, as lead arrangerand sole book runner, Wells Fargo Bank, N.A., as documentation agent, and Regions Bank, assyndication agent (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form8-K (File No. 001-35779) filed on December 17, 2013) 108 Table of Contents10.2 Letter Agreement by and among USA Compression Partners, LLC, USAC Leasing, LLC, USACompression Partners, LP, USAC Leasing 2, LLC, USAC OpCo 2, LLC, the Lenders party thereto andJPMorgan Chase Bank, N.A., in its capacity as administrative agent for the Lenders, dated as of June 30,2014 (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (FileNo. 001-35779) filed on July 3, 2014) 10.3 Second Amendment to the Fifth Amended and Restated Credit Agreement, dated as of January 6, 2015,by and among USA Compression Partners, LP, as guarantor, USA Compression Partners, LLC, USACLeasing, LLC, USAC OpCo 2, LLC and USAC Leasing 2, LLC, as borrowers, the lenders party theretoand JPMorgan Chase Bank, N.A., as agent and LC issuer (incorporated by reference to Exhibit 10.1 to thePartnership’s Current Report on Form 8-K (File No. 001-35779) filed on January 9, 2015) 10.4 Third Amendment to the Fifth Amended and Restated Credit Agreement, dated as of March 18, 2016, byand among USA Compression Partners, LP, as guarantor, USA Compression Partners, LLC, USACLeasing, LLC, USAC OpCo2, LLC and USAC Leasing 2, LLC, as borrowers, the lenders party thereto andJP Morgan Chase Bank, N.A., as agent and LC issuer (incorporated by reference to Exhibit 10.1 to thePartnership’s Current Report on Form 8-K (File No. 001-35779) filed on March 21, 2016) 10.5 Fourth Amendment to the Fifth Amended and Restated Credit Agreement, dated as of January 29, 2018,by and among USA Compression Partners, LP, as guarantor, USA Compression Partners, LLC, USACLeasing, LLC, USAC OpCo2, LLC and USAC Leasing 2, LLC, as borrowers, the lenders party thereto andJP Morgan Chase Bank, N.A., as agent and LC issuer and Swingline Lender (incorporated by reference toExhibit 10.1 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on February 2,2018) 10.6 Sixth Amended and Restated Credit Agreement, dated as of April 2, 2018, by and among the Partnership,as borrower, USAC OpCo 2, LLC, USAC Leasing 2, LLC, USA Compression Partners, LLC, USACLeasing, LLC, CDM Resource Management LLC and CDM Environmental & Technical Services LLCand USA Compression Finance Corp., the lenders party thereto from time to time, JPMorgan Chase Bank,N.A., as agent and an LC issuer, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Regions CapitalMarkets, a division of Regions Bank, RBC Capital Markets and Wells Fargo Bank, N.A., as joint leadarrangers and joint book runners, Barclays Bank PLC, Regions Bank, RBC Capital Markets and WellsFargo Bank, N.A., as syndication agents, and MUFG Union Bank, N.A., SunTrust Bank and The Bank ofNova Scotia, as senior managing agents (incorporated by reference to Exhibit 10.1 to the Partnership’sCurrent Report on Form 8-K (File No. 001-35779) filed on April 6, 2018) 10.7† Long-Term Incentive Plan of USA Compression Partners, LP (incorporated by reference to Exhibit 10.1 tothe Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on January 18, 2013) 10.8† First Amendment to the USA Compression Partners, LP 2013 Long-Term Incentive Plan (incorporated byreference to Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q (File No. 001-35779) filedon November 6, 2018) 10.9† Employment Agreement, dated December 23, 2010, between USA Compression Partners, LLC and Eric D.Long (incorporated by reference to Exhibit 10.5 to Amendment No. 4 of the Partnership’s registrationstatement on Form S-1 (Registration No. 333-174803) filed on February 13, 2012) 10.10† Employment Agreement, dated April 17, 2013, between USA Compression Management Services, LLCand Matthew C. Liuzzi (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report onForm 8-K (File No. 001-35779) filed on January 15, 2015) 10.11† Employment Agreement, dated July 15, 2013, between USA Compression Management Services,LLC and William G. Manias (incorporated by reference to Exhibit 10.7 to the Partnership’s AnnualReport on Form 10-K for the year ended December 31, 2015 (File No. 001-35779) filed on February 11,2016) 10.12† Employment Agreement, dated December 23, 2010, between USA Compression Partners, LLC and DavidA. Smith (incorporated by reference to Exhibit 10.8 to Amendment No. 4 of the Partnership’s registrationstatement on Form S-1 (Registration No. 333-174803) filed on February 13, 2012) 109 Table of Contents 10.13†* Employment Agreement, dated July 1, 2016, between USA Compression Management Services, LLC andSean T. Kimble 10.14 Services Agreement, dated effective January 1, 2013, by and among USA Compression Partners, LP, USACompression GP, LLC and USA Compression Management Services, LLC (incorporated by reference toExhibit 10.11 to Amendment No. 10 of the Partnership’s registration statement on Form S-1 (RegistrationNo. 333-174803) filed on January 7, 2013) 10.15 Amendment No. 1 to Services Agreement, dated effective November 3, 2017, by and among USACompression Partners, LP, USA Compression GP, LLC and USA Compression Management Services,LLC (incorporated by reference to Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q (FileNo. 001-35779) filed on November 7, 2017) 10.16† USA Compression Partners, LP 2013 Long-Term Incentive Plan—Form of Director Phantom UnitAgreement (incorporated by reference to Exhibit 10.8 to the Partnership’s Annual Report on Form 10-Kfor the year ended December 31, 2012 (File No. 001-35779) filed on March 28, 2013) 10.17† USA Compression Partners, LP 2013 Long-Term Incentive Plan—Form of Employee Phantom UnitAgreement (incorporated by reference to Exhibit 10.10 to the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013 (File No. 001-35779) filed on February 20, 2014) 10.18† USA Compression Partners, LP 2013 Long-Term Incentive Plan—Form of Director Phantom UnitAgreement (in lieu of Annual Cash Retainer) (incorporated by reference to Exhibit 10.10 to thePartnership’s Annual Report on Form 10-K for the year ended December 31, 2012 (File No. 001-35779)filed on March 28, 2013) 10.19† USA Compression Partners, LP 2013 Long-Term Incentive Plan—Form of Director Phantom UnitAgreement (incorporated by reference to Exhibit 10.5 to the Partnership’s Quarterly Report on form 10-Q(File No. 001-35779) filed on November 6, 2018) 10.20† USA Compression Partners, LP Annual Cash Incentive Program (incorporated by reference to Exhibit10.12 to the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013 (File No.001-35779) filed on February 20, 2014) 10.21†* USA Compression Partners, LP Amended and Restated Annual Cash Incentive Plan 10.22† USA Compression Partners, LP 2013 Long-Term Incentive Plan—Form of Employee Phantom UnitAgreement (with updated performance metrics) (incorporated by reference to Exhibit 10.13 to thePartnership’s Annual Report on Form 10-K for the year ended December 31, 2015 (File No. 001-35779)filed on February 11, 2016) 10.23† USA Compression Partners, LP 2013 Long-Term Incentive Plan – Form of Employee Phantom UnitAgreement (incorporated by reference to Exhibit 10.6 to the Partnership’s Quarterly Report on Form 10-Q(File No. 001-35779) filed on November 6, 2018) 10.24† USA Compression Partners, LP 2018 Long-Term Incentive Plan – Form of Retention Phantom UnitAgreement (incorporated by reference to Exhibit 10.2 to the Partnership’s Quarterly Report on Form 10-Q(File No. 001-35779) filed on November 6, 2018) 10.25 Form of Termination Agreement and Mutual Release (incorporated by reference to Exhibit 10.3 to thePartnership’s Quarterly Report on Form 10-Q (File No. 001-35779) filed on November 6, 2018) 10.26† USA Compression GP, LLC Amended and Restated Outside Director Compensation Policy (incorporatedby reference to Exhibit 10.4 to the Partnership’s Quarterly Report on Form 10-Q (File No. 001-35779)filed on November 6, 2018) 10.27 Series A Preferred Unit and Warrant Purchase Agreement, dated January 15, 2018, among USACompression Partners, LP and the purchasers party thereto (incorporated by reference to Exhibit 10.1 tothe Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on January 16, 2018) 110 Table of Contents16.1 Letter of KPMG LLP, dated April 9, 2018, regarding change in independent registered accounting firm(incorporated by reference to Exhibit 16.1 to the Partnership’s Current Report on Form 8-K/A (File No.001-35779) filed on April 9, 2018) 21.1* List of subsidiaries of USA Compression Partners, LP 23.1* Consent of Grant Thornton LLP 31.1* Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of1934 31.2* Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of1934 32.1# Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant toSection 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 toSection 906 of the Sarbanes-Oxley Act of 2002 99.1* Unaudited pro forma condensed consolidated statement of operations of USA Compression Partners, LPand the CDM Compression Business for the year ended December 31, 2018 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 orotherwise subject to the liabilities of that section.†Management contract or compensatory plan or arrangement.111 Table of Contents SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has dulycaused this report to be signed on its behalf by the undersigned, thereunto duly authorized. USA COMPRESSION PARTNERS, LP By:USA Compression GP, LLC, its General Partner By:/s/ Eric D. Long Eric D. Long President and Chief Executive Officer (Principal Executive Officer) Date:February 19, 2019 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the followingpersons on behalf of the registrant and in the capacities indicated on February 19, 2019. Name Title /s/ Eric D. Long President and Chief Executive Officer and DirectorEric D. Long (Principal Executive Officer) /s/ Matthew C. Liuzzi Vice President, Chief Financial Officer and TreasurerMatthew C. Liuzzi (Principal Financial Officer) /s/ G. Tracy Owens Vice President, Finance and Chief Accounting OfficerG. Tracy Owens (Principal Accounting Officer) /s/ Michael Bradley Michael Bradley Director /s/ Christopher R. Curia Christopher R. Curia Director /s/ Matthew S. Hartman Matthew S. Hartman Director /s/ Glenn E. Joyce Glenn E. Joyce Director /s/ Thomas E. Long Thomas E. Long Director /s/ Thomas P. Mason Thomas P. Mason Director /s/ Matthew S. Ramsey Matthew S. Ramsey Director /s/ William S. Waldheim William S. Waldheim Director 112 Table of ContentsINDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report of Independent Registered Public Accounting Firm F-2Consolidated Balance Sheets as of December 31, 2018 and 2017 F-3Consolidated Statements of Operations for the years ended December 31, 2018, 2017 and 2016 F-4Consolidated Statements of Changes in Partners’ Capital and Predecessor Parent Company Net Investment for theyears ended December 31, 2018, 2017 and 2016 F-5Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016 F-6Notes to Consolidated Financial Statements F-7Supplemental Selected Quarterly Financial Data S-1 F-1 Table of ContentsREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Board of Directors of USA Compression GP, LLC andUnitholders of USA Compression Partners, LP Opinion on the financial statementsWe have audited the accompanying consolidated balance sheets of USA Compression Partners, LP (a Delaware limitedpartnership) and subsidiaries (the “Partnership”) as of December 31, 2018 and 2017, the related consolidated statements ofoperations, changes in partners’ capital and predecessor parent company net investment, and cash flows for each of thethree years in the period ended December 31, 2018, and the related notes (collectively referred to as the “financialstatements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of thePartnership as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three yearsin the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States ofAmerica.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)(“PCAOB”), the Partnership’s internal control over financial reporting as of December 31, 2018, based on criteria establishedin the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the TreadwayCommission (“COSO”), and our report dated February 19, 2019 expressed an unqualified opinion thereon.Basis for opinionThese financial statements are the responsibility of the Partnership’s management. Our responsibility is to express anopinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with thePCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securitieslaws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and performthe audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whetherdue to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financialstatements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures includedexamining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits alsoincluded evaluating the accounting principles used and significant estimates made by management, as well as evaluatingthe overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. /s/ GRANT THORNTON LLPWe have served as the Partnership’s auditor since 2017. Houston, TexasFebruary 19, 2019 F-2 Table of ContentsUSA COMPRESSION PARTNERS, LPConsolidated Balance Sheets(in thousands) December 31, 2018 2017 Assets Current assets: Cash and cash equivalents $99 $4,013 Accounts receivable, net: Trade, net 75,572 32,696 Other 3,809 — Related party receivables 47,661 45 Inventory, net 89,007 33,221 Prepaid expenses and other assets 1,592 4,209 Total current assets 217,740 74,184 Installment receivable 6,924 — Property and equipment, net 2,521,488 1,192,921 Identifiable intangible assets, net 392,550 198,215 Goodwill 619,411 253,428 Other assets 16,536 205 Total assets $3,774,649 $1,718,953 Liabilities, Partners’ Capital and Predecessor Parent Company Net Investment Current liabilities: Accounts payable $23,804 $1,383 Related party payables 395 1,977 Accrued liabilities 94,028 41,513 Deferred revenue 31,372 2,220 Total current liabilities 149,599 47,093 Long-term debt, net 1,759,058 — Other liabilities 9,827 6,990 Total liabilities 1,918,484 54,083 Preferred Units 477,309 — Commitments and contingencies Partners’ capital: Limited partner interest: Common units, 89,984 units issued and outstanding as of December 31, 2018 1,289,731 — Class B Units, 6,398 units issued and outstanding as of December 31, 2018 75,146 — Warrants 13,979 — Predecessor parent company net investment — 1,664,870 Total partners’ capital and predecessor parent company net investment 1,378,856 1,664,870 Total liabilities, partners’ capital and predecessor parent company net investment $3,774,649 $1,718,953 See accompanying notes to consolidated financial statements. F-3 Table of ContentsUSA COMPRESSION PARTNERS, LPConsolidated Statements of Operations(in thousands, except per unit amounts) Year Ended December 31, 2018 2017 2016 Revenues: Contract operations $546,896 $249,346 $239,143 Parts and service 20,402 10,085 7,921 Related party 17,054 17,240 16,873 Total revenues 584,352 276,671 263,937 Costs and expenses: Cost of operations, exclusive of depreciation and amortization 214,724 125,204 112,898 Selling, general and administrative 68,995 24,944 22,739 Depreciation and amortization 213,692 166,558 155,134 Loss (gain) on disposition of assets 12,964 (367) 120 Impairment of compression equipment 8,666 — — Impairment of goodwill — 223,000 — Total costs and expenses 519,041 539,339 290,891 Operating income (loss) 65,311 (262,668) (26,954) Other income (expense): Interest expense, net (78,377) — — Other 41 (223) (153) Total other expense (78,336) (223) (153) Net loss before income tax expense (benefit) (13,025) (262,891) (27,107) Income tax expense (benefit) (2,474) 1,843 (163) Net loss (10,551) (264,734) (26,944) Less: distributions on Preferred Units (36,430) — — Net loss attributable to common and Class B unitholders' interests $(46,981) $(264,734) $(26,944) Net loss attributable to: Common units $(32,053) Class B units $(14,928) Weighted average common units outstanding - basic and diluted 74,481 Weighted average Class B Units outstanding - basic and diluted 6,398 Basic and diluted net loss per common unit $(0.43) Basic and diluted net loss per Class B Unit $(2.33) Distributions declared per common unit $1.575 See accompanying notes to consolidated financial statements. F-4 Table of ContentsUSA COMPRESSION PARTNERS, LPConsolidated Statements of Changes in Partners’ Capital And Predecessor Parent Company Net Investment(in thousands) PredecessorParent Company Net Common Units Class B Units Warrants Investment TotalEnding balance, December 31, 2015 $ — $ — $ — $2,042,996 $2,042,996Predecessor net loss — — — (26,944) (26,944)Predecessor parent company net distributions — — — (86,829) (86,829)Ending balance, December 31, 2016 — — — 1,929,223 1,929,223Predecessor net loss — — — (264,734) (264,734)Predecessor parent company net contributions — — — 381 381Ending balance, December 31, 2017 — — — 1,664,870 1,664,870Predecessor net loss for the period January 1, 2018 toApril 1, 2018 — — — (23,370) (23,370)Predecessor parent company net contribution for theperiod January 1, 2018 to April 1, 2018 — — — 26,730 26,730Allocation of Predecessor parent company net investment 1,668,230 — — (1,668,230) —Deemed distribution for additional interest in USACompression Predecessor (36,111) — — — (36,111)Purchase Price Adjustment for USA Compression Partners,LP (654,340) — — — (654,340)Issuance of common units for the Equity Restructuring 135,440 — — — 135,440Issuance of common units for the CDM Acquisition 324,910 — — — 324,910Issuance of Class B Units for the CDM Acquisition — 86,125 — — 86,125Issuance of Warrants — — 13,979 — 13,979Vesting of phantom units 5,283 — — — 5,283Distributions and distribution equivalent rights (141,694) — — — (141,694)Issuance of common units under the DRIP 645 — — — 645Net loss for the period April 2, 2018 to December 31, 2018 (12,632) (10,979) — — (23,611)Partners' capital ending balance, December 31, 2018 $1,289,731 $75,146 $13,979 $ — $1,378,856 See accompanying notes to consolidated financial statements. F-5 Table of ContentsUSA COMPRESSION PARTNERS, LPConsolidated Statements of Cash Flows(in thousands) Year Ended December 31, 2018 2017 2016 Cash flows from operating activities: Net loss $(10,551) $(264,734) $(26,944)Adjustments to reconcile net loss to net cash provided by operating activities: Depreciation and amortization 213,692 166,558 155,134Bad debt expense (recovery) 633 (1,777) (593)Amortization of debt issue costs 5,080 — —Unit-based compensation expense 11,740 4,048 3,539Deferred income tax expense (benefit) (2,663) 1,801 (155)Loss (gain) on disposition of assets 12,964 (367) 120Impairment of compression equipment 8,666 — —Impairment of goodwill — 223,000 —Changes in assets and liabilities, net of effects of business combination: Accounts receivable, net (50,029) 9,331 25,578Inventory, net (6,736) (698) (515)Prepaid expenses and other current assets 9,298 (3,569) (167)Other noncurrent assets (59) 8 (34)Accounts payable and related party payables (5,140) 2,531 (2,291)Other current liabilities (4,879) 228 (1,769)Accrued liabilities and deferred revenue 44,324 (404) (21,840)Net cash provided by operating activities 226,340 135,956 130,063Cash flows from investing activities: Capital expenditures, net (266,566) (157,292) (61,575)Proceeds from disposition of property and equipment 7,466 14,834 24,808Proceeds from insurance recovery 409 — —Acquisition of USA Compression Predecessor (1,231,478) — —Assumed cash acquired in business combination of USA Compression Partners, LP 710,506 — —Net cash used in investing activities (779,663) (142,458) (36,767)Cash flows from financing activities: Proceeds from revolving credit facility 697,684 — —Payments on revolving credit facility (467,199) — —Proceeds from issuance of Preferred Units and Warrants, net 479,100 — —Cash paid related to net settlement of unit-based awards (4,447) — —Cash distributions on common units (142,324) — —Cash distributions on Preferred Units (24,242) — —Financing costs (17,683) — —Contributions from (distributions to) Parent, net 28,520 (3,666) (90,367)Net cash provided by (used in) financing activities 549,409 (3,666) (90,367)Increase (decrease) in cash and cash equivalents (3,914) (10,168) 2,929Cash and cash equivalents, beginning of year 4,013 14,181 11,252Cash and cash equivalents, end of year $99 $4,013 $14,181Supplemental cash flow information: Cash paid for interest, net of capitalized amounts $61,021 $ — $ —Cash paid for income taxes $183 $ — $ —Supplemental non-cash transactions: Non-cash distributions to certain common unitholders (DRIP) $645 $ — $ —Predecessor's Non-cash contribution (to) from Predecessor's Parent $(1,790) $4,047 $3,538Transfers to inventory from property and equipment $(10,602) $ — $ —Transfer from long-term installment receivable to short-term $(2,809) $ — $ —Transfer from long-term liabilities to short-term $914 $ — $ —Change in capital expenditures included in accounts payable and accrued liabilities $(32,168) $17,300 $(3,678)Deemed distribution for additional interest in USA Compression Predecessor $(36,111) $ — $ —Issuance of common units for the CDM Acquisition $324,910 $ — $ — Issuance of Class B Units for the CDM Acquisition $86,125 $ — $ — Issuance of common units for the Equity Restructuring $135,440 $ — $ — See accompanying notes to consolidated financial statements. F-6 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statements(1) Organization and Description of Business Unless the context otherwise requires or where otherwise indicated, the terms “our”, “we”, “us”, “the Partnership” andsimilar language when used in the present or future tense and for periods on or subsequent to April 2, 2018 (the “TransactionsDate”) refer to USA Compression Partners, LP, collectively with its consolidated operating subsidiaries, including the USACompression Predecessor. Unless the context otherwise requires or where otherwise indicated, the term “USA CompressionPredecessor,” as well as the terms “our,” “we,” “us” and “its” when used in an historical context or in reference to periodsprior to the Transactions Date, refers to CDM Resource Management LLC (“CDM Resource”) and CDM Environmental &Technical Services LLC (“CDM E&T”) collectively, which has been deemed to be the predecessor of the Partnership forfinancial reporting purposes. We are a Delaware limited partnership. Through our operating subsidiaries, we provide compression services underfixed-term contracts with customers in the natural gas and crude oil industries, using natural gas compression packages thatwe design, engineer, own, operate and maintain. We primarily provide compression services in a number of shale playsthroughout the United States, including the Utica, Marcellus, Permian Basin, Delaware Basin, Eagle Ford, Mississippi Lime,Granite Wash, Woodford, Barnett, Haynesville, Niobrara and Fayetteville shales. USA Compression GP, LLC, a Delaware limited liability company, serves as our general partner and is referred to hereinas the “General Partner”. The General Partner was wholly owned by Energy Transfer Equity, L.P. (“ETE”), through its whollyowned subsidiary, Energy Transfer Partners, L.L.C. (“ETP LLC”). In October 2018, ETE and Energy Transfer Partners, L.P.(“ETP”) completed the merger of ETP with a wholly owned subsidiary of ETE in a unit-for-unit exchange (the “ETEMerger”). Following the closing of the ETE Merger, ETE changed its name to “Energy Transfer LP” and ETP changed itsname to “Energy Transfer Operating, L.P.” Upon the closing of the ETE Merger, ETE contributed to ETP 100% of the limitedliability company interests in the General Partner. References herein to “ETP” refer to Energy Transfer Partners, L.P. forperiods prior to the ETE Merger and Energy Transfer Operating, L.P. following the ETE Merger, and references to “ETE” referto Energy Transfer Equity, L.P. for periods prior to the ETE Merger and Energy Transfer LP following the ETE Merger. The USA Compression Predecessor owned and operated a fleet of compressors used to provide natural gas compressionservices for customer specific systems. The USA Compression Predecessor also owned and operated a fleet of equipment usedto provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, and dehydration. TheUSA Compression Predecessor had operations located in Texas, Oklahoma, Louisiana, Arkansas, Pennsylvania, New Mexico,Colorado, Ohio, and West Virginia. Certain of our operating subsidiaries are borrowers under a revolving credit facility and the Partnership is a guarantor ofthat revolving credit facility (see Note 10). The accompanying consolidated financial statements include the accounts of thePartnership and its operating subsidiaries, all of which are wholly owned by us. Net loss is allocated to our common units and Class B Units using the two-class income allocation method. Allintercompany balances and transactions have been eliminated in consolidation. Our common units trade on the New YorkStock Exchange under the ticker symbol “USAC”. USA Compression Management Services, LLC (“USAC Management”), a wholly owned subsidiary of the GeneralPartner, performs certain management and other administrative services for us, such as accounting, corporate development,finance and legal. All of our employees, including our executive officers, are employees of USAC Management. As ofDecember 31, 2018, USAC Management had 864 full time employees. None of our employees are subject to collectivebargaining agreements. CDM Acquisition On the Transactions Date, we consummated the transactions contemplated by the Contribution Agreement dated January15, 2018, pursuant to which, among other things, we acquired all of the issued and outstanding membership interests of theUSA Compression Predecessor from ETP (the “CDM Acquisition”) in exchange for aggregate consideration of approximately$1.7 billion, consisting of (i) 19,191,351 common units representing limited partnerF-7 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statementsinterests in us (the “common units”), (ii) 6,397,965 Class B units representing limited partner interests in us (“Class B Units”)and (iii) $1.2 billion in cash (including customary closing adjustments). General Partner Purchase Agreement On the Transactions Date, and in connection with the closing of the CDM Acquisition, we consummated the transactionscontemplated by the Purchase Agreement dated January 15, 2018, by and among ETE, ETP LLC, USA CompressionHoldings, LLC (“USA Compression Holdings”) and, solely for certain purposes therein, R/C IV USACP Holdings, L.P. andETP, pursuant to which, among other things, ETE acquired from USA Compression Holdings (i) all of the outstanding limitedliability company interests in the General Partner and (ii) 12,466,912 common units for cash consideration paid by ETE toUSA Compression Holdings equal to $250.0 million (the “GP Purchase”). Upon the closing of the ETE Merger, ETEcontributed all of the interests in the General Partner and the 12,466,912 common units to ETP. Equity Restructuring Agreement On the Transactions Date, and in connection with the closing of the CDM Acquisition, we consummated the transactionscontemplated by the Equity Restructuring Agreement dated January 15, 2018, pursuant to which, among other things, thePartnership, the General Partner and ETE agreed to cancel the Partnership’s Incentive Distribution Rights (“IDRs”) andconvert the General Partner Interest (as defined in the Equity Restructuring Agreement) into a non-economic general partnerinterest, in exchange for the Partnership’s issuance of 8,000,000 common units to the General Partner (the “EquityRestructuring”). The CDM Acquisition, GP Purchase and Equity Restructuring are collectively referred to as the “Transactions.” (2) Basis of Presentation and Significant Accounting Policies Basis of Presentation The Partnership The consolidated financial statements give effect to the business combination and the Transactions discussed aboveunder the acquisition method of accounting, and the business combination has been accounted for in accordance with theapplicable reverse merger accounting guidance. ETE acquired a controlling financial interest in us through the acquisition ofthe General Partner. As a result, the USA Compression Predecessor is deemed to be the accounting acquirer of the Partnershipbecause its ultimate parent company obtained control of the Partnership through its control of the General Partner.Consequently, the USA Compression Predecessor is deemed to be the predecessor of the Partnership for financial reportingpurposes, and the historical financial statements of the Partnership now reflect the USA Compression Predecessor for allperiods prior to the closing of the Transactions. The closing of the Transactions occurred on the Transactions Date. The USA Compression Predecessor’s assets and liabilities retained their historical carrying values. Additionally, thePartnership’s assets acquired and liabilities assumed by the USA Compression Predecessor in the business combination havebeen recorded at their fair values measured as of the Transactions Date. The excess of the assumed purchase price of thePartnership over the estimated fair values of the Partnership’s net assets acquired has been recorded as goodwill. The assumedpurchase price and fair value of the Partnership has been determined using acceptable fair value methods. Additionally,because the USA Compression Predecessor is reflected at ETE’s historical cost, the difference between the $1.7 billion inconsideration paid by the Partnership and ETE’s historical carrying values (net book value) at the Transactions Date has beenrecorded as a decrease to partners’ capital in the amount of $36.1 million. Our accompanying consolidated financial statements have been prepared in conformity with accounting principlesgenerally accepted in the United States of America (“GAAP”) and pursuant to the rules and regulations of the Securities andExchange Commission (“SEC”). As noted above, the historical consolidated financial statements of the Partnership nowreflect the historical consolidated financial statements of the USA Compression Predecessor in accordance with theF-8 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statementsapplicable accounting and financial reporting guidance. Therefore, the historical consolidated financial statements arecomprised of the balance sheet and statement of operations of the USA Compression Predecessor as of and for periods prior tothe Transactions Date. The historical consolidated financial statements are also comprised of the consolidated balance sheetand statement of operations of the Partnership, which includes the USA Compression Predecessor, as of and for all periodssubsequent to the Transactions Date. The presentation of certain line items in historical periods have been conformed to thePartnership’s current year presentation for comparability. USA Compression Predecessor ETP allocated various corporate overhead expenses to the USA Compression Predecessor based on a percentage of assets,net income (loss), or adjusted earnings before interest, taxes, depreciation and amortization (“EBITDA”). These allocationsare not necessarily indicative of the cost that the USA Compression Predecessor would have incurred had it operated as anindependent standalone entity. The USA Compression Predecessor also historically relied upon ETP for funding operatingand capital expenditures as necessary. As a result, the historical financial statements of the USA Compression Predecessormay not fully reflect or be necessarily indicative of what the USA Compression Predecessor’s balance sheet, results ofoperations and cash flows would have been or will be in the future. Certain expenses incurred by ETP are only indirectly attributable to the USA Compression Predecessor. As a result,certain assumptions and estimates are made in order to allocate a reasonable share of such expenses to the USA CompressionPredecessor, so that the accompanying financial statements reflect substantially all costs of doing business. The allocationsand related estimates and assumptions are described more fully in Note 14. Certain amounts of the USA Compression Predecessor’s revenues are derived from related party transactions, as describedmore fully in Note 14. Significant Accounting Policies Cash and Cash Equivalents Cash and cash equivalents consist of all cash balances. We consider investments in highly liquid financial instrumentspurchased with an original maturity of 90 days or less to be cash equivalents. Trade Accounts Receivable and Allowance for Doubtful Accounts Trade accounts receivable are recorded at the invoiced amount and do not bear interest. Our determination of theallowance for doubtful accounts requires us to make estimates and judgments regarding our customers’ ability to payamounts due. We continuously evaluate the financial strength of our customers based on payment history, the overallbusiness climate in which our customers operate and specific identification of customer bad debt and make adjustments tothe allowance as necessary. Our evaluation of our customers’ financial strength is based on the aging of their respectivereceivables balance, customer correspondence, financial information and third-party credit ratings. Our evaluation of thebusiness climate in which our customers operate is based on a review of various publicly-available materials regarding ourcustomers’ industries, including the solvency of various companies in the industry. The USA Compression Predecessor determined its allowance for doubtful accounts based upon historical write-offexperience and specific identification of unrecoverable amounts. Inventory Inventory consists of serialized and non-serialized parts used primarily in the repair of compression units. All inventoryis stated at the lower of cost or net realizable value. Serialized parts inventory is determined using the specific identificationmethod, while non-serialized parts inventory is determined using the weighted average cost method. Purchases of these assetsare considered operating activities in the Consolidated Statements of Cash Flows. F-9 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial StatementsProperty and Equipment Property and equipment are carried at cost except for (i) certain acquired assets which are recorded at fair value on theirrespective acquisition dates and (ii) impaired assets which are recorded at fair value on the last impairment evaluation datefor which an adjustment was required. Overhauls and major improvements that increase the value or extend the life ofcompression equipment are capitalized and depreciated over 3 to 5 years. Ordinary maintenance and repairs are charged tocost of operations, exclusive of depreciation and amortization. When property and equipment is retired or sold, its carrying value and the related accumulated depreciation are removedfrom our accounts and any associated gains or losses are recorded on our statements of operations in the period of sale ordisposition. Capitalized interest is calculated by multiplying the Partnership’s monthly effective interest rate on outstanding debtby the amount of qualifying costs, which include upfront payments to acquire certain compression units. Capitalized interestwas $0.3 million for the year ended December 31, 2018. The USA Compression Predecessor had no capitalized interest forthe years ended December 31, 2017 or 2016, as it did not hold any debt during either period. Impairments of Long-Lived Assets Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-downto estimated fair value. We test long-lived assets for impairment when events or circumstances indicate that the assets’carrying value may not be recoverable or will no longer be utilized in the operating fleet. The most common circumstancerequiring compression units to be tested for impairment is when idle units do not meet the performance characteristics of ouractive revenue generating horsepower. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expectedto result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cashflows associated with the operating fleet, an impairment loss equal to the amount of the carrying value exceeding the fairvalue of the asset is recognized. The fair value of the asset is measured using quoted market prices or, in the absence ofquoted market prices, based on an estimate of discounted cash flows, the expected net sale proceeds compared to the othersimilarly configured fleet units we recently sold or a review of other units recently offered for sale by third parties, or theestimated component value of the equipment we plan to use. Refer to Note 7 for more detailed information about impairment charges during the year ended December 31, 2018. Identifiable Intangible Assets Identifiable intangible assets are recorded at cost and amortized using the straight-line method over their estimateduseful lives, which is the period over which the assets are expected to contribute directly or indirectly to our future cashflows. The estimated useful lives range from 15 to 25 years. We assess identifiable intangible assets for impairment whenever events or changes in circumstances indicate that thecarrying amount of an asset may not be recoverable. We did not record any impairment of identifiable intangible assets forthe years ended December 31, 2018, 2017 or 2016. Goodwill Goodwill represents consideration paid in excess of the fair value of the identifiable net assets acquired in a businesscombination. Goodwill is not amortized, but is reviewed for impairment annually based on the carrying values as of October1, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered. F-10 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial StatementsThe Partnership did not record any goodwill impairment during the year ended December 31, 2018. The USACompression Predecessor recorded $223 million of goodwill impairment for the year ended December 31, 2017 and nogoodwill impairment for the year ended December 31, 2016. Refer to the Goodwill section in Note 7 for more informationabout the goodwill impairment assessment performed during the years ended December 31, 2018 and 2017. Predecessor Parent Company Net Investment The USA Compression Predecessor participated in a centralized cash management function managed by ETP. Balancespayable to or due from ETP generated under this arrangement are reflected in Predecessor parent company net investment. ETP’s net investment in the operations of the USA Compression Predecessor is presented as Predecessor parent companynet investment within the consolidated balance sheets. Predecessor parent company net investment represents theaccumulated net earnings of the operations of the USA Compression Predecessor and accumulated net contributions fromETP. Net contributions for the period January 1, 2018 to April 1, 2018 were primarily comprised of intercompany operationsand expense, cash clearing and other financing activities, and general and administrative cost allocations to the USACompression Predecessor. Income Taxes These consolidated financial statements do not include a provision for income taxes as the Partnership is treated as apartnership for U.S. federal and state income tax purposes, with each partner being separately taxed on its distributive shareof the Partnership’s items of income, gain, loss, or deduction. While the Partnership is generally not subject to entity-levelincome taxes, Texas imposes an entity-level income tax on partnerships. Refer to Note 9 for more detailed information aboutthe Texas Franchise Tax for the years ended December 31, 2018, 2017 and 2016. Pass Through Taxes Sales taxes incurred on behalf of, and passed through to, customers are accounted for on a net basis. Fair Value Measurements Accounting standards on fair value measurements establish a framework for measuring fair value and stipulatedisclosures about fair value measurements. The standards apply to recurring and non-recurring financial and non-financialassets and liabilities that require or permit fair value measurements. Among the required disclosures is the fair value hierarchyof inputs we use to value an asset or a liability. The three levels of the fair value hierarchy are described as follows: Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the abilityto access at the measurement date. Level 2 inputs are those 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. As of December 31, 2018, our financial instruments consisted primarily of cash and cash equivalents, trade accountsreceivable, trade accounts payable and long-term debt. The book values of cash and cash equivalents, trade accountsreceivable, and trade accounts payable are representative of fair value due to their short-term maturities. The carrying amountof our revolving credit facility approximates fair value due to the floating interest rates associated with the debt. F-11 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial StatementsThe fair value of our 6.875% Senior Notes due 2026 (the “Senior Notes”) was estimated using quoted prices in inactivemarkets and is considered a Level 2 measurement. The following table summarizes the carrying amount and fair value ofthese assets and liabilities (in thousands): December 31,Assets (Liabilities) 2018 2017Carrying amount of Senior Notes (1) $709,511 $ —Fair value of Senior Notes 696,000 —(1)Carrying amount is shown net of unamortized deferred financing costs. As of December 31, 2018, the outstanding aggregate principalamount of our Senior Notes was $725.0 million. See Note 10 for further details. As of December 31, 2017, the USA Compression Predecessor did not have financial instruments with fair valuesdetermined using available market information and valuation methodologies. The carrying amount of cash and cashequivalents, accounts receivable and accounts payable approximates fair value due to their short-term maturities. As part of the impairment analysis of goodwill as of December 31, 2017, the fair value of the USA CompressionPredecessor’s goodwill was re-measured using Level 3 inputs. Refer to the Goodwill section in Note 7 for more informationabout this valuation as of December 31, 2017. Use of Estimates The preparation of our consolidated financial statements in conformity with GAAP requires us to make estimates andassumptions that affect the amounts reported in these consolidated financial statements and the accompanying results.Although these estimates are based on management’s available knowledge of current and expected future events, actualresults could differ from these estimates. Operating Segment We operate in a single business segment, the compression services business. (3) Acquisitions The USA Compression Predecessor is deemed to be the accounting acquirer of the Partnership in the businesscombination because its ultimate parent company obtained control of the Partnership through its control of the GeneralPartner. Consequently, the USA Compression Predecessor’s assets and liabilities retained their historical carryingvalues. The Partnership’s assets acquired and liabilities assumed by the USA Compression Predecessor have been recorded attheir fair values measured as of the Transactions Date. The excess of the assumed purchase price of the Partnership over theestimated fair values of the Partnership’s net assets acquired has been recorded as goodwill. The assumed purchase price andfair value of the Partnership was determined using a combination of an income and cost valuation methodology, the fairvalue of the Partnership’s common units as of the Transactions Date and the consideration paid by ETE for the GeneralPartner and IDRs. The valuation and purchase price allocation is considered final. The property and equipment of the USA Compression Predecessor is reflected at historical carrying value, which is lessthan the consideration paid for the business. The excess of the consideration paid over the historical carrying value was$36.1 million and is reflected as a decrease to partners’ capital. The Partnership incurred $21.7 million in transaction-related expenses prior to the Transactions Date, which wererecognized by the Partnership when incurred in the periods prior to the Transactions Date, and therefore are not includedwithin the results of operations presented within the consolidated financial statements for the year ended December 31, 2018. For the period from April 2, 2018 to December 31, 2018, we recognized $269.2 million in revenues and $23.1 million innet income attributable to the Partnership’s historical assets. F-12 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial StatementsThe following table summarizes the assumed purchase price and fair value and the allocation to the assets acquired andliabilities assumed (in thousands): Assumed purchase price allocation to USA Compression Partners, LP Current assets $786,258Fixed assets 1,331,850Other long-term assets 15,018Customer relationships 221,500Total identifiable assets acquired 2,354,626Current liabilities (110,465)Long-term debt (1,526,865)Other long-term liabilities (1,538)Total liabilities assumed (1,638,868)Net identifiable assets acquired 715,758Goodwill (1) 365,983Net assets acquired $1,081,741 April 2, 2018 Transactions: Cash assumed in the CDM Acquisition (710,506)Issuance of Preferred Units (465,121)Issuance of Class B Units for the CDM Acquisition (86,125)Issuance of Warrants (13,979)Issuance of common units for the Equity Restructuring (135,440)Issuance of common units for the CDM Acquisition (324,910)Purchase Price Adjustment for USA Compression Partners, LP $(654,340)(1)Goodwill recognized from the business combination primarily relates to the value attributed to additional growth opportunities, synergiesand operating leverage within the Partnership’s areas of operation. The valuation of goodwill recognized from the business combinationis final. Transition Services Agreement In connection with the closing of the Transactions, we entered into an agreement with the USA Compression Predecessorand ETP pursuant to which ETP and its affiliates provided certain services to us with respect to the business and operations ofthe USA Compression Predecessor’s existing assets, including information technology, accounting and emissions testingservices, for a period of three months following the closing of the Transactions. Expenses associated with the transitionservices agreement were $0.7 million for the year ended December 31, 2018. Unaudited Pro Forma Financial Information The following unaudited pro forma condensed financial information for the years ended December 31, 2018 and 2017gives effect to the Transactions as if they had occurred on January 1, 2017. The unaudited pro forma condensed financialinformation has been included for comparative purposes only and is not necessarily indicative of the results that might haveoccurred had the Transactions taken place on the dates indicated and is not intended to be a projection of future events. Thepro forma adjustments for the periods presented consist of (i) adjustments to combine the USA Compression Predecessor’sand the Partnership’s historical results of operations for the periods, (ii) adjustments to interest expense to include interestexpense for additional revolving credit facility borrowings and include the interest expense associated with our Senior Notes(see Note 10), (iii) adjustments to depreciation and amortization expense attributable to adjustments recorded as a result ofthe purchase price allocation to the Partnership’s assets and liabilities and (iv) adjustments to net loss attributable to commonunits and Class B Units attributable to distributions on the Partnership’s Series A Preferred Units (the “Preferred Units”). F-13 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial StatementsThe following table presents the unaudited pro forma revenues, net loss and basic and diluted net loss per unitinformation for each period: Year Ended December 31, 2018 2017Total revenues $662,091 $556,893Net loss $(44,894) $(344,995)Net loss attributable to common and Class B unitholders' interests $(93,644) $(393,745)Basic and diluted net loss per common unit and Class B Unit $(0.98) $(4.14) The pro forma net loss for the year ended December 31, 2018 includes expenses that were a direct result of theTransactions, including $1.0 million in employee severance charges attributable to employees not retained by thePartnership subsequent to the Transactions and $21.7 million in transaction expenses, including advisory, audit and legalfees. These expenses were recognized by the Partnership as they were incurred during the period from January 1, 2018 toApril 1, 2018, but because the USA Compression Predecessor’s historical condensed consolidated financial statements arenow reflected for that period, the condensed consolidated financial statements presented in accordance with GAAP for theyear ended December 31, 2018 do not reflect such expenses incurred as a direct result of the Transactions. (4) Trade Accounts Receivable The allowance for doubtful accounts, which was $1.7 million and $0.8 million as of December 31, 2018 and 2017,respectively, is our best estimate of the amount of probable credit losses included in our existing accounts receivable. Duringthe year ended December 31, 2018, we increased our allowance for doubtful accounts by $0.9 million, due primarily toestimated uncollectible amounts from customers of the USA Compression Predecessor. The USA Compression Predecessor reduced its allowance for doubtful accounts by $4.1 million and $1.0 million duringthe years ended December 31, 2017 and 2016, respectively, due to write-offs of receivables and collections on accountspreviously reserved. Due to the decrease in the allowance for doubtful accounts during 2017 and 2016, the USACompression Predecessor recognized a reduction of bad debt expense of $1.8 million and $0.6 million for the years endedDecember 31, 2017 and 2016, respectively. (5)Inventory Components of inventory were as follows (in thousands): December 31, 2018 2017Serialized parts $45,568 $ —Non-serialized parts 43,439 34,335Total Inventory, gross 89,007 34,335Less: obsolete and slow moving reserve — (1,114)Total Inventory, net $89,007 $33,221 (6) Installment Receivable We granted a bargain purchase option to a customer with respect to certain compressor packages leased to the customer.The bargain purchase option provides the customer with an option to acquire the equipment at a value significantly less thanthe fair market value at the end of the lease term, which is July 31, 2021. We accounted for this option as a sales type lease resulting in a current installment receivable included in other accountsreceivable of $3.7 million and a long-term installment receivable of $6.9 million as of December 31, 2018. The USACompression Predecessor had no capital lease installment receivables as of December 31, 2017. F-14 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial StatementsRevenue and interest income related to the capital lease is recognized over the lease term. We recognize maintenancerevenue within Contract operations revenue and interest income within Interest expense, net. Maintenance revenue was $1.0million for the year ended December 31, 2018. Interest income was $0.7 million for the year ended December 31, 2018. TheUSA Compression Predecessor had no capital lease revenue or maintenance revenue related to capital lease for the yearsended December 31, 2017 or 2016. (7) Property and Equipment, Identifiable Intangible Assets and Goodwill Property and Equipment Property and equipment consisted of the following (in thousands): December 31, 2018 2017 Compression and treating equipment $3,239,831 $1,799,151 Furniture and fixtures 1,129 780 Automobiles and vehicles 32,490 41,796 Computer equipment 54,806 25,049 Buildings 9,314 13,891 Land 77 77 Leasehold improvements 5,377 2,051 Total Property and equipment, gross 3,343,024 1,882,795 Less: accumulated depreciation and amortization (821,536) (689,874) Total Property and equipment, net $2,521,488 $1,192,921 Depreciation is calculated using the straight-line method over the estimated useful lives of the assets as follows: Compression equipment, acquired new 25 years Compression equipment, acquired used 5 - 25 years Furniture and fixtures 3 - 10 years Vehicles and computer equipment 1 - 10 years Buildings 5 years Leasehold improvements 5 years Depreciation expense on property and equipment was $186.5 million, $146.0 million and $134.6 million for the yearsended December 31, 2018, 2017 and 2016, respectively. The Partnership implemented a change in the estimated useful lives of the USA Compression Predecessor’s property andequipment to conform to the Partnership’s historical asset lives, which is accounted for as a change in accounting estimatebeginning on the Transactions Date on a prospective basis. This change resulted in a $33.8 million increase to bothoperating income and net income for the year ended December 31, 2018, and a $0.42 increase to both basic and dilutedearnings per common unit and Class B Unit for year ended December 31, 2018. As of December 31, 2018 and 2017, there was $7.9 million and $14.6 million, respectively, of property and equipmentpurchases in accounts payable and accrued liabilities. During the year ended December 31, 2018, there were net losses on the disposition of assets of $13.0 million, primarilyattributable to disposals of various property and equipment by the USA Compression Predecessor. During the years endedDecember 31, 2017 and 2016, the USA Compression Predecessor recognized a $0.4 million net loss and $0.1 million net gainon disposition of assets, respectively. For the year ended December 31, 2018, we evaluated the future deployment of our idle fleet under then-current marketconditions and determined to retire and re-utilize key components of 103 compressor units, or approximately 33,000horsepower, that were previously used to provide services in our business. As a result, we recorded $8.7 millionF-15 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statementsin impairment of compression equipment for the year ended December 31, 2018. The primary causes for this impairmentwere: (i) units were not considered marketable in the foreseeable future, (ii) units were subject to excessive maintenance costsor (iii) units were unlikely to be accepted by customers due to certain performance characteristics of the unit, such as theinability to meet then-current quoting criteria without excessive retrofitting costs. These compression units were writtendown to their respective estimated salvage values, if any. The USA Compression Predecessor did not record any impairment of long-lived assets during the years ended December31, 2017 or 2016. Identifiable Intangible Assets Identifiable intangible assets, net consisted of the following (in thousands): Customer Relationships Trade Names Total Gross Balance at December 31, 2016 $263,662 $65,500 $329,162 Accumulated amortization (106,111) (24,836) (130,947) Net Balance at December 31, 2017 $157,551 $40,664 $198,215 Gross Balance at December 31, 2017 $263,662 $65,500 $329,162 Additions 221,500 — 221,500 Accumulated amortization (130,001) (28,111) (158,112) Net Balance at December 31, 2018 $355,161 $37,389 $392,550 Amortization expense for the year ended December 31, 2018 was $27.2 million and for each of the years endedDecember 31, 2017 and 2016 was $20.5 million. The expected amortization of the intangible assets for each of thefive succeeding years is $29.4 million. Goodwill As of October 1, 2018, we performed a qualitative assessment and concluded that it is not more likely than not that thefair value of our single reporting unit was less than its carrying value and that our goodwill was not impaired. For the year ended December 31, 2017 and in accordance with its early adoption of Accounting Standards Update(“ASU”) 2017-04, the USA Compression Predecessor performed a quantitative assessment for its annual goodwill impairmenttest and determined its fair value using a weighted combination of the discounted cash flow method and the guidelinecompany method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates andassumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs ofcapital and future market conditions, among others. The USA Compression Predecessor believed the estimates andassumptions used in the impairment assessment were reasonable and based on available market information, but variations inany of the assumptions could have result in materially different calculations of fair value and determinations of whether ornot an impairment is indicated. Under the discounted cash flow method, the USA Compression Predecessor determined fairvalue based on estimated future cash flows including estimates for capital expenditures, discounted to present value usingthe risk-adjusted industry rate, which reflects the overall level of inherent risk of the company. Cash flow projections werederived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all ofwhich were developed by management. Subsequent period cash flows were developed using growth rates that managementbelieved were reasonably likely to occur. Under the guideline company method, the USA Compression Predecessordetermined its estimated fair value by applying valuation multiples of comparable publicly-traded companies to theprojected EBITDA of the company and then averaging that estimate with similar historical calculations using a three-yearaverage. In addition, the USA Compression Predecessor estimated a reasonable control premium representing the incrementalvalue that accrues to the predecessor’s majority owner from the opportunity to dictate the strategic and operational actions ofthe business. Additionally, the USA Compression Predecessor considered the presence and probability of subsequent eventson market transactions in estimating the fair value of the company, such as the Transactions discussed in Note 1. F-16 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial StatementsBased on the completion of the annual goodwill impairment testing as described above, the USA CompressionPredecessor recorded a $223.0 million impairment equal to the excess of the carrying value over fair value for the year endedDecember 31, 2017. There was no goodwill impairment for the year ended December 31, 2016. As of December 31, 2018, the Partnership had $619.4 million of goodwill, of which $366.0 million was determined aspart of the purchase price allocation to the Partnership’s assets acquired by the USA Compression Predecessor. (8) Other Current Assets and Other Current Liabilities As of December 31, 2018, accrued liabilities included $44.9 million of accrued sales tax contingency (Note 17), $16.4million of accrued interest expense, $10.7 million of accrued payroll and benefits and $7.9 million of accrued capitalexpenditures. As of December 31, 2017, the USA Compression Predecessor recognized $27.8 million of accrued equipment and otherasset purchases, $8.3 million of accrued payroll and benefits and $0.7 million of accrued property taxes within accruedliabilities and $3.8 million of miscellaneous prepaid expenses within prepaid expenses and other current assets. (9) Income Tax Expense We, including the USA Compression Predecessor, are subject to the Texas Franchise Tax, which applies a tax to our grossmargin. We do not conduct business in any other state where a similar tax is applied. The Texas Franchise Tax requirescertain forms of legal entities, including limited partnerships, to pay a tax of 0.75% on its “margin,” as defined in the law,based on annual results. The tax base to which the tax is applied is the least of (1) 70% of total revenues for federal incometax purposes, (2) total revenue less cost of goods sold or (3) total revenue less compensation for federal income tax purposes. Components of our income tax expense (benefit) are as follows (in thousands): Year Ended December 31, 2018 2017 2016Current tax expense (benefit) $189 $42 $(8)Deferred tax expense (benefit) (2,663) 1,801 (155)Total income tax expense (benefit) $(2,474) $1,843 $(163) Deferred income tax balances are the direct effect of temporary differences between the financial statement carryingamounts and the tax basis of assets and liabilities at the enacted tax rates expected to be in effect when the taxes are actuallypaid or recovered. The tax effects of temporary differences related to property and equipment that give rise to deferred taxliabilities, included in other liabilities, are as follows (in thousands): December 31, 2018 2017Deferred tax liability - Property and equipment $2,540 $3,791 The Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification (“ASC”) Topic 740 IncomeTaxes (“ASC Topic 740”) provides guidance on measurement and recognition in accounting for income tax uncertainties andprovides related guidance on derecognition, classification, disclosure, interest, and penalties. As of December 31, 2018, wehad no material unrecognized tax benefits (as defined in ASC Topic 740). We do not expect to incur interest charges orpenalties related to our tax positions, but if such charges or penalties are incurred, our policy is to account for interest chargesas Interest expense, net and penalties as Income tax expense in the Consolidated Statements of Operations. The Bipartisan Budget Act of 2015 provides that any tax adjustments (including any applicable penalties and interest)resulting from partnership audits will generally be determined at the partnership level for tax years beginning after December31, 2017. To the extent possible under the new rules, our general partner may elect to either pay the taxesF-17 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statements(including any applicable penalties and interest) directly to the Internal Revenue Service or, if we are eligible, issue a revisedinformation statement to each unitholder and former unitholder with respect to an audited and adjusted return. TheBipartisan Budget Act of 2015 allows a partnership to elect to apply these provisions to any return of the partnership filed forpartnership taxable years beginning after the date of the enactment, November 2, 2015. We do not intend to elect to applythese provisions for any tax return filed for partnership taxable years beginning before January 1, 2018. (10) Long-Term Debt Our long-term debt, of which there is no current portion, consisted of the following (in thousands): December 31, 2018 2017Revolving Credit Facility $1,049,547 $ —Senior Notes, aggregate principal 725,000 —Less: deferred financing costs, net of amortization (15,489) —Senior Notes, net 709,511 —Total long-term debt, net $1,759,058 $ — Revolving Credit Facility On the Transactions Date, we entered into the Sixth Amended and Restated Credit Agreement (the “Credit Agreement”)by and among the Partnership, as borrower, USAC OpCo 2, LLC, USAC Leasing 2, LLC, USA Compression Partners, LLC,USAC Leasing, LLC, CDM Resource, CDM E&T and USA Compression Finance Corp. (“Finance Corp”), the lenders partythereto from time to time, JPMorgan Chase Bank, N.A., as agent and a Letter of Credit (“LC”) issuer, JPMorgan Chase Bank,N.A., Barclays Bank PLC, Regions Capital Markets, a division of Regions Bank, RBC Capital Markets and Wells FargoBank, N.A., as joint lead arrangers and joint book runners, Barclays Bank PLC, Regions Bank, RBC Capital Markets andWells Fargo Bank, N.A., as syndication agents, and MUFG Union Bank, N.A., SunTrust Bank and The Bank of Nova Scotia,as senior managing agents. The Credit Agreement has an aggregate commitment of $1.6 billion (subject to availability under our borrowing base),with a further potential increase of $400 million, and has a maturity date of April 2, 2023. The Credit Agreement permits us to make distributions of available cash to unitholders so long as (a) no default underthe facility has occurred, is continuing or would result from the distribution, (b) immediately prior to and after giving effectto such distribution, we are in compliance with the facility’s financial covenants and (c) immediately after giving effect tosuch distribution, we have availability under the revolving credit facility of at least $100 million. In addition, the CreditAgreement contains various covenants that may limit, among other things, our 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 our assets; or ·make certain acquisitions. F-18 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial StatementsThe revolving credit facility also contains various financial covenants, including covenants requiring us to maintain: ·a minimum EBITDA to interest coverage ratio of 2.5 to 1.0, determined as of the last day of each fiscal quarter; and ·a maximum funded debt to EBITDA ratio, determined as of the last day of each fiscal quarter, for the annualizedtrailing three months of (a) 5.75 to 1.0 through the end of the fiscal quarter ending March 31, 2019, (b) 5.5 to 1.0through the end of the fiscal quarter ending December 31, 2019 and (c) 5.00 to 1.0 thereafter, in each case subject toa provision for increases to such thresholds by 0.5 in connection with certain future acquisitions for the sixconsecutive month period following the period in which any such acquisition occurs. If a default exists under the Credit Agreement, the lenders will be able to accelerate the maturity on the amount thenoutstanding and exercise other rights and remedies. In connection with entering into the amended Credit Agreement, we paid certain upfront fees and arrangement fees to thearrangers, syndication agents and senior managing agents of the Credit Agreement in the amount of $14.3 million during theyear ended December 31, 2018. These fees were capitalized to loan costs and will be amortized through April 2023. Amounts borrowed and repaid under the Credit Agreement may be re-borrowed. As of December 31, 2018, we were in compliance with all of our covenants under the Credit Agreement. As of December 31, 2018, we had outstanding borrowings under the Credit Agreement of $1.1 billion, $550.5 million ofborrowing base availability and, subject to compliance with the applicable financial covenants, available borrowingcapacity of $550.5 million. The borrowing base consists of eligible accounts receivable, inventory and compression units.The largest component, representing 95% of the borrowing base as of December 31, 2018, was eligible compression units.Eligible compression units consist of compressor packages that are leased, rented or under service contracts to customers andcarried in the financial statements as fixed assets. Our interest rate in effect for all borrowings under the Credit Agreement asof December 31, 2018 was 4.97%, with a weighted-average interest rate of 4.69% for the period from the Transactions Date toDecember 31, 2018. There were no LCs issued as of December 31, 2018. The Credit Agreement matures in April 2023 and we expect to maintain it for the term. The Credit Agreement is a“revolving credit facility” that includes a lock box arrangement, whereby remittances from customers are forwarded to a bankaccount controlled by the administrative agent and are applied to reduce borrowings under the facility. Senior Notes On March 23, 2018, the Partnership and its wholly owned finance subsidiary, Finance Corp, co-issued $725.0million aggregate principal amount of the Senior Notes that mature on April 1, 2026. The Senior Notes accrue interest fromMarch 23, 2018 at the rate of 6.875% per year. Interest on the Senior Notes is payable semi-annually in arrears on April 1 andOctober 1, with the first such payment having occurred on October 1, 2018. At any time prior to April 1, 2021, we may redeem up to 35% of the aggregate principal amount of the Senior Notes at aredemption price equal to 106.875% of the principal amount, plus accrued and unpaid interest, if any, to the redemptiondate, in an amount not greater than the net proceeds from one or more equity offerings, provided that at least 65% of theaggregate principal amount of the Senior Notes remains outstanding immediately after the occurrence of such redemption(excluding Senior Notes held by us and our subsidiaries) and redemption occurs within 180 days of the date of the closing ofsuch equity offering. Prior to April 1, 2021, we may redeem all or a part of the Senior Notes at a redemption price equal to the sum of (i) theprincipal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, tothe redemption date. F-19 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial StatementsOn or after April 1, 2021, we may redeem all or a part of the Senior Notes at redemption prices (expressed as percentagesof the principal amount) set forth below, plus accrued and unpaid interest, if any, to the applicable redemption date. If weexperience a change of control followed by a ratings decline, unless we have previously exercised or concurrently exercisethe right to redeem the Senior Notes (as described above), we may be required to offer to repurchase the Senior Notes at apurchase price equal to 101% of the principal amount repurchased, plus accrued and unpaid interest, if any, to the repurchasedate. Year Percentages 2021 105.156%2022 103.438%2023 101.719%2024 and thereafter 100.000% The Indenture governing the Senior Notes (the “Indenture”) contains a Fixed Charge Coverage Ratio (as defined in theIndenture) that we must comply with in order to make certain Restricted Payments (as defined in the Indenture). In connection with issuing the Senior Notes, we incurred certain issuance costs in the amount of $17.3 million which isamortized over the term of the Senior Notes using the effective interest method. The Senior Notes are fully and unconditionally guaranteed (the “Guarantees”), jointly and severally, on a seniorunsecured basis by all of our existing subsidiaries (other than Finance Corp), and will be fully and unconditionallyguaranteed, jointly and severally, by each of our future restricted subsidiaries that either borrows under, or guarantees, ourrevolving credit facility or guarantees certain of our other indebtedness (collectively, the “Guarantors”). The Senior Notesand the Guarantees are general unsecured obligations and rank equally in right of payment with all of the Guarantors’ andour existing and future senior indebtedness and senior to the Guarantors’ and our future subordinated indebtedness, if any.The Senior Notes and the Guarantees are effectively subordinated in right of payment to all of the Guarantors and ourexisting and future secured debt, including debt under our revolving credit facility and guarantees thereof, to the extent ofthe value of the assets securing such debt, and are structurally subordinated to all indebtedness of any of our subsidiaries thatdo not guarantee the Senior Notes. We have no assets or operations independent of our subsidiaries, and there are no significant restrictions upon our abilityto obtain funds from our subsidiaries by dividend or loan. Each of the Guarantors is 100% owned by us. None of the assets ofour subsidiaries represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act of 1933,as amended (“Securities Act”). On January 14, 2019, the Partnership closed an exchange offer whereby holders of the Senior Notes exchanged all of theSenior Notes for an equivalent amount of senior notes (“Exchange Notes”) registered under the Securities Act. The ExchangeNotes are substantially identical to the Senior Notes, except that the Exchange Notes have been registered and do not containtransfer restrictions, restrictive legends, registration rights or additional interest provisions of the Senior Notes. Subsidiary Guarantors On April 20, 2017, the Partnership filed a Registration Statement on Form S-3 (the “Registration Statement”) with the SECto register the issuance and sale of, among other securities, debt securities, which may be co-issued by Finance Corp (togetherwith the Partnership, the “Issuers”) and fully and unconditionally guaranteed on a joint and several basis by the Partnership’soperating subsidiaries for the benefit of each Holder and the Trustee. Such guarantees will be subject to release, subject tocertain limitations, as follows (i) upon the sale, exchange or transfer, by way of a merger or otherwise, to any Person that isnot our Affiliate, of all of our direct or indirect limited partnership or other equity interest in such Subsidiary Guarantor; or(ii) upon delivery by an Issuer of a written notice to the Trustee of the release or discharge of all guarantees by suchSubsidiary Guarantor of any Debt of the Issuers other than obligations arising under the indenture governing such debt andany debt securities issued under such indenture, except a discharge or release by or as a result of payment under suchguarantees. Capitalized terms used but not defined in this paragraph are defined in the Form of Indenture filed as Exhibit 4.1to the Registration Statement. F-20 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial StatementsMaturities of long-term debt for each of the five succeeding years are as follows (in thousands): Year Ending December 31, 2019 $ — 2020 — 2021 — 2022 — 2023 1,049,547 Total Debt $1,049,547 The USA Compression Predecessor did not hold any debt as of December 31, 2017. (11) Preferred Units and Warrants Series A Preferred Unit and Warrant Private Placement On the Transactions Date, we completed a private placement of $500 million in the aggregate of (i) newly authorized andestablished Preferred Units and (ii) warrants to purchase common units (the “Warrants”) pursuant to a Series A Preferred Unitand Warrant Purchase Agreement dated January 15, 2018, with certain investment funds managed or advised by EIG GlobalEnergy Partners (collectively, the “Preferred Unitholders”). We issued 500,000 Preferred Units with a face value of $1,000per Preferred Unit and issued two tranches of Warrants to the Preferred Unitholders, which included Warrants to purchase5,000,000 common units with a strike price of $17.03 per unit and 10,000,000 common units with a strike price of $19.59 perunit. The Warrants may be exercised by the holders thereof at any time beginning April 2, 2019 and before April 2, 2028. On November 13, 2018, the Partnership filed a Registration Statement on Form S-3 to register 41,202,553 common unitsthat are potentially issuable upon conversion of the Preferred Units and exercise of the Warrants. The Preferred Units rank senior to the common units with respect to distributions and rights upon liquidation. ThePreferred Unitholders are entitled to receive cumulative quarterly distributions equal to $24.375 per Preferred Unit and whichmay be paid in cash or, subject to certain limits, a combination of cash and additional Preferred Units as determined by theGeneral Partner with respect to any quarter ending on or prior to June 30, 2019. For the three months ended June 30, 2018,the distribution was pro-rated for the period the Preferred Units were outstanding, which resulted in an initial distribution of$24.107 per Preferred Unit which was paid on August 10, 2018. For the three months ended September 30, 2018, thequarterly distribution was equal to $24.375 per Preferred Unit and was paid on November 9, 2018. The distributionattributable to the quarter ended December 31, 2018 was paid on February 8, 2019 to Preferred Unitholders of record as of theclose of business on January 28, 2019. The Preferred Units are convertible, at the option of the Preferred Unitholders, into common units as follows: one thirdon or after April 2, 2021, two thirds on or after April 2, 2022, and the remainder on or after April 2, 2023. The conversion ratefor the Preferred Units shall be the quotient of (a) the sum of (i) $1,000, plus (ii) any unpaid cash distributions on theapplicable Preferred Unit, divided by (b) $20.0115 for each Preferred Unit. The Preferred Unitholders are entitled to vote onan as-converted basis with the common unitholders and (as proportionately adjusted for unit splits, unit distributions andsimilar transactions) will have certain other class voting rights with respect to any amendment to the Partnership Agreementthat would adversely affect any rights, preferences or privileges of the Preferred Units. In addition, upon certain eventsinvolving a change of control the Preferred Unitholders may elect, among other potential elections, to convert their PreferredUnits to common units at the then change of control conversion rate. On or after April 2, 2023, we have the option to redeem all or any portion of the Preferred Units then outstanding. On orafter April 2, 2028, the Preferred Unitholders have the right to require us to redeem all or a portion of the Preferred Units thenoutstanding, the purchase price for which we may elect to pay up to 50% in common units, subject to certain additionallimits. The Preferred Units are presented as temporary equity in the mezzanine section of the Consolidated Balance Sheetsbecause the redemption provisions on or after April 2, 2028 are outside the Partnership’s control. TheF-21 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial StatementsPreferred Units have been recorded at their issuance date fair value, net of issuance cost. Net income allocations increase thecarrying value and declared distributions decrease the carrying value of the Preferred Units. As the Preferred Units are notcurrently redeemable and it is not probable that they will become redeemable, adjustment to the initial carrying amount isnot necessary and would only be required if it becomes probable that the Preferred Units would become redeemable. Changes in the Preferred Units balance from December 31, 2017 through December 31, 2018 are summarized below (inthousands): Preferred UnitsBalance at December 31, 2017 $ —Issuance of Preferred Units on April 2, 2018, net 465,121Net income allocated for April 2, 2018 through December 31, 2018 36,430Cash distributions on Preferred Units (24,242)Balance at December 31, 2018 $477,309 The Warrants are presented within the equity section of the Consolidated Balance Sheets in accordance with GAAP asthey are indexed to the Partnership’s own stock and require physical settlement or net share settlement. The Warrants werevalued using the Black-Scholes-Merton model. Refer to Note 14 for information about the rights EIG Veteran Equity Aggregator, L.P. (along with its affiliated funds,“EIG”) has to designate one of the members of the Board. (12) Partners’ Capital Common Units As of December 31, 2018, we had 89,983,790 common units outstanding. As of December 31, 2018, ETP held39,658,263 common units, including 8,000,000 common units held by the General Partner and controlled by ETP. USA Compression Holdings, which controlled the General Partner and its IDRs until the Transactions Date, sold all of itsremaining common units during the year ended December 31, 2018. The limited partners holding our common units have the following rights, among others: ·Right to receive distributions of our available cash (as defined in our Second Amended and Restated Agreement ofLimited Partnership of the Partnership (the “Partnership Agreement”)) within 45 days after the end of each quarter, solong as we have paid the required distributions on the Preferred Units for such quarter; ·Right to transfer limited partner unit ownership to substitute limited partners; ·Right to approve certain amendments of the Partnership Agreement; ·Right to electronic access of an annual report, containing audited financial statements and a report on thosefinancial statements by our independent public accountants within 90 days after the close of the fiscal year end; and ·Right to receive information reasonably required for tax reporting purposes within 90 days after the close of thecalendar year. Class B Units As of December 31, 2018, we had 6,397,965 Class B Units outstanding which represent limited partner interests in thePartnership, all of which are held by ETP. Each Class B Unit will automatically be converted into one common unitF-22 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statementsfollowing the record date attributable to the quarter ending June 30, 2019. Each Class B Unit has all of the rights andobligations of a common unit, except the right to participate in distributions made prior to conversion of the Class B Unitsinto common units. Cash Distributions As the USA Compression Predecessor is deemed to be the predecessor of the Partnership for financial reporting purposes,cash distributions made by the Partnership in periods prior to the Transactions Date are not included within the results ofoperations presented within the consolidated financial statements for the year ended December 31, 2018. We have declared quarterly distributions per unit to our limited partner unitholders of record, including holders of ourcommon and phantom units, as follows (dollars in millions, except distribution per unit): Distribution per Amount Paid to Amount Paid to Limited Partner Common Phantom Total Payment Date Unit Unitholders Unitholders Distribution May 11, 2018 $0.525 $47.2 $0.4 $47.6 August 10, 2018 0.525 47.2 0.4 47.6 November 9, 2018 0.525 47.2 0.5 47.7 2018 Total Distributions $1.575 $141.6 $1.3 $142.9 Announced Quarterly Distribution On January 17, 2019, we announced a cash distribution of $0.525 per unit on our common units. The distributionwas paid on February 8, 2019 to unitholders of record as of the close of business on January 28, 2019. Distribution Reinvestment Plan During the year ended December 31, 2018, distributions of $0.6 million were reinvested under the DistributionReinvestment Plan (the “DRIP”) resulting in the issuance of 39,280 common units. Earnings Per Common Unit The computations of earnings per unit are based on the weighted average number of participating securities outstandingduring the period. Basic earnings per unit is determined by dividing net loss allocated to participating securities afterdeducting the amount distributed on Preferred Units, by the weighted average number of participating securities outstandingduring the period. Net loss is allocated to participating securities based on their respective shares of the distributed andundistributed earnings for the period. To the extent cash distributions exceed net income (loss) for the period, the excessdistributions are allocated to all participating securities outstanding based on their respective ownership percentages.Diluted earnings per unit are computed using the treasury stock method, which considers the potential issuance of limitedpartner units associated with our long-term incentive plan and warrants. The classes of participating securities includecommon units, Class B Units, and certain equity-based compensation awards. Unvested phantom units and unexercisedwarrants are not included in basic earnings per unit, as they are not considered to be participating securities, but are includedin the calculation of diluted earnings per unit to the extent that they are dilutive, and in the case of warrants to the extentthey are considered “in the money”. For the year ended December 31, 2018, approximately 208,000 incremental unvestedphantom units were excluded from the calculation of diluted earnings per unit because the impact was anti-dilutive. Ouroutstanding warrants are not applicable to the computation as of December 31, 2018 as they are not considered “in themoney” for the period. Earnings per unit is not applicable to the USA Compression Predecessor as the USA CompressionPredecessor had no outstanding common units prior to the Transactions. F-23 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statements(13) Revenue Recognition Revenue is recognized when obligations under the terms of a contract with our customer are satisfied; generally thisoccurs with the transfer of our services or goods. Revenue is measured at the amount of consideration we expect to receive inexchange for providing services or transferring goods. Sales taxes incurred on behalf of, and passed through to, customers areexcluded from revenue. Incidental items, if any, that are immaterial in the context of the contract are recognized as expense. Adoption of ASC Topic 606, “Revenue from Contracts with Customers” On January 1, 2018, we adopted ASC Topic 606 Revenue from Contracts with Customers (“ASC Topic 606”) using themodified retrospective method applied to those contracts which were not completed as of January 1, 2018. Results forreporting periods beginning after January 1, 2018 are presented under ASC Topic 606, while prior period amounts are notadjusted and continue to be reported in accordance with our historic accounting under ASC Topic 605. We identified no material impact on our historical revenues upon initial application of ASC Topic 606, and as such havenot recognized any cumulative catch-up effect to the opening balance of our partners’ capital as of January 1, 2018.Additionally, the application of ASC Topic 606 has no material impact on any current financial statement line items. The following table disaggregates our revenue by type of service (in thousands): Year Ended December 31, 2018 2017 (1) 2016 (1)Contract operations revenue $563,416 $266,130 $255,560Retail parts and services revenue 20,936 10,541 8,377Total revenues $584,352 $276,671 $263,937(1)As noted above, prior period amounts have not been adjusted under the modified retrospective method of ASC Topic 606. The following table disaggregates our revenue by timing of provision of services or transfer of goods (in thousands): Year Ended December 31, 2018 2017 (1) 2016 (1)Services provided or goods transferred at a point in time $20,936 $10,541 $8,377Services provided over time: Primary term 288,299 128,864 158,313Month-to-month 275,117 137,266 97,247Total revenues $584,352 $276,671 $263,937(1)As noted above, prior period amounts have not been adjusted under the modified retrospective method of ASC Topic 606. F-24 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial StatementsContract operations revenue Revenue from contracted compression, station, gas treating and maintenance services is recognized ratably under ourfixed-fee contracts over the term of the contract as services are provided to our customers. Initial contract terms typicallyrange from six months to five years, however we usually continue to provide compression services at a specific locationbeyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. We primarily enterinto fixed-fee contracts whereby our customers are required to pay our monthly fee even during periods of limited ordisrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the servicemonth, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30days after receipt of our invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which timethey are recognized as revenue. The amount of consideration we receive and revenue we recognize is based upon the fixedfee rate stated in each service contract. Variable consideration exists in select contracts when billing rates vary based on actual equipment availability or volumeof total installed horsepower. Our contracts with customers may include multiple performance obligations. For such arrangements, we allocate revenuesto each performance obligation based on its relative standalone service fee. We generally determine standalone service feesbased on the service fees charged to customers or use expected cost plus margin. The majority of our service performance obligations are satisfied over time as services are rendered at selected customerlocations on a monthly basis and based upon specific performance criteria identified in the applicable contract. The monthlyservice for each location is substantially the same service month to month and is promised consecutively over the servicecontract term. We measure progress and performance of the service consistently using a straight-line, time-based method aseach month passes, because our performance obligations are satisfied evenly over the contract term as the customersimultaneously receives and consumes the benefits provided by our service. If variable consideration exists, it is allocated tothe distinct monthly service within the series to which such variable consideration relates. We have elected to apply theinvoicing practical expedient to recognize revenue for such variable consideration, as the invoice corresponds directly to thevalue transferred to the customer based on our performance completed to date. There are typically no material obligations for returns or refunds. Our standard contracts do not usually include materialnon-cash consideration. Retail parts and services revenue Retail parts and services revenue is earned primarily on freight and crane charges that are directly reimbursable by ourcustomers and maintenance work on units at our customers’ locations that are outside the scope of our core maintenanceactivities. Revenue from retail parts and services is recognized at the point in time the part is transferred or service isprovided and control is transferred to the customer. At such time, the customer has the ability to direct the use of the benefitsof such part or service after we have performed our services. We bill upon completion of the service or transfer of the parts,and payment is generally due 30 days after receipt of our invoice. The amount of consideration we receive and revenue werecognize is based upon the invoice amount. There are typically no material obligations for returns, refunds, or warranties.Our standard contracts do not usually include material variable or non-cash consideration. Contract assets and trade accounts receivable We record contract assets when we have completed performance under a contract but our right to consideration is not yetunconditional. We had no contract assets as of December 31, 2018 and the USA Compression Predecessor had no contractassets as of December 31, 2017. Trade accounts receivable are recorded when our right to consideration becomesunconditional and increased by $36.2 million during the year ended December 31, 2018 as a result of the USA CompressionPredecessor’s acquisition of the Partnership for financial reporting purposes. There were no significant changes to our tradeaccounts receivable balances due to contract modifications or adjustments, or changes in time frame for a right toconsideration to become unconditional during the period. F-25 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial StatementsDeferred revenue We record deferred revenue when cash payments are received or due in advance of our performance. The increase in thedeferred revenue balance for the year ended December 31, 2018 is primarily driven by cash payments received or due inadvance of satisfying our performance obligations under a contract and the addition of $31.0 million of deferred revenuefrom the USA Compression Predecessor’s acquisition of the Partnership, offset by $1.0 million of revenues recognized thatwere included in the deferred revenue balance of the USA Compression Predecessor as of December 31, 2017. There was nosignificant change to our deferred revenue balance as a result of changes in time frame for a performance obligation to besatisfied during the period. Practical expedients and exemptions We have elected to apply the practical expedient in ASC 606-10-50-14 and as such do not disclose the value ofunsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii) contracts forwhich we recognize revenue at the amount to which we have the right to invoice for services performed. Costs to fulfill a contract We sometimes incur non-reimbursable costs for loading, transporting and unloading equipment to and from our storagelocations and customer locations. We defer and amortize these costs using the straight-line method over the life of thecontract. We had no costs to fulfill a contract as of December 31, 2018 and $0.1 million in amortization expense of costs tofulfill a contract for the year ended December 31, 2018. The USA Compression Predecessor had no costs to fulfill a contractas of December 31, 2017 and amortization expense was zero for the year ended December 31, 2017. (14) Transactions with Related Parties We provide compression services to entities affiliated with ETP, which as of December 31, 2018, owned approximately48% of our limited partner interests, including all of the Class B Units, and 100% of the General Partner. During the yearended December 31, 2018, we recognized $17.1 million in revenue from such affiliated entities. As of December 31, 2018, wehad $2.7 million in related party receivables from such affiliated entities and $0.4 million in related party payables to suchaffiliated entities. Additionally, the Partnership had a $44.9 million related party receivable from ETP as of December 31,2018 related to indemnification for sales tax contingencies incurred by the USA Compression Predecessor. See Note 17 formore information related to such sales tax contingencies. The USA Compression Predecessor also provided compression services to entities affiliated with ETP. During the yearsended December 31, 2017 and 2016, the USA Compression Predecessor recognized $17.2 million and $16.9 million,respectively, in revenue from such affiliated entities. As of December 31, 2017, the USA Compression Predecessorrecognized $45,000 in related party receivables from such affiliated entities and $2.0 million in related party payables tosuch affiliated entities. Accounts receivable and payable that related to revenues and expenses between the USA Compression Predecessor andETP were reclassified to Predecessor parent company net investment as there was no expectation that those amounts wouldbe settled in cash. ETP provided certain benefits to the USA Compression Predecessor employees which did not continue following theTransactions Date. ETP provided medical, dental and other healthcare benefits to the USA Compression Predecessoremployees. The total amount incurred by ETP for the benefit of the USA Compression Predecessor employees for the yearsended December 31, 2018, 2017 and 2016 was $1.9 million, $7.4 million and $5.8 million, respectively, which was allocatedto the USA Compression Predecessor and recorded in operation and maintenance and general and administrative expenses, asappropriate. ETP also provided a matching contribution to the USA Compression Predecessor employees’ 401(k) accounts.The total amount of matching contributions incurred for the benefit of the USA Compression Predecessor employees for theyears ended December 31, 2018, 2017 and 2016 was $0.9 million, $3.0 million and $2.7 million, respectively, which wasallocated to the USA Compression Predecessor and recorded in operation and maintenance and general and administrativeexpenses, as appropriate. ETP also provided a 3% profitF-26 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statementssharing contribution to the 401(k) accounts for all USA Compression Predecessor employees with base compensation belowa specified threshold. The contribution was in addition to the 401(k) matching contribution and employees became vested inthe profit sharing contribution based on years of service. ETP allocated certain overhead costs associated with general and administrative services, including salaries and benefits,facilities, insurance, information services, human resources and other support departments to the USA CompressionPredecessor which did not continue following the Transactions Date. Where costs incurred on the USA CompressionPredecessor’s behalf could not be determined by specific identification, the costs were primarily allocated to the USACompression Predecessor based on an average percentage of fixed assets, net income (loss) and adjusted EBITDA. The USACompression Predecessor believes these allocations were a reasonable reflection of the utilization of services provided.However, the allocations may not fully reflect the expenses that would have been incurred had the USA CompressionPredecessor been a standalone company during the periods presented. During the years ended December 31, 2018, 2017 and2016 ETP allocated general and administrative expenses of $1.8 million, $3.6 million and $4.7 million, respectively, to theUSA Compression Predecessor. An independent director of the General Partner serves as a director of one of our customers. During the period of suchdirector’s appointment as a director of the General Partner during the year ended December 31, 2018, we recognized $0.3million in revenue on compression services and $0 in accounts receivable from this customer on the Consolidated BalanceSheets as of December 31, 2018. Pursuant to that certain Board Representation Agreement entered into by us, the General Partner, ETE and EIG inconnection with our private placement of Preferred Units and Warrants to EIG, EIG Management Company, LLC has the rightto designate one of the members of the Board for so long as the holders of the Preferred Units hold more than 5% of thePartnership’s outstanding common units in the aggregate (taking into account the common units that would be issuable uponconversion of the Preferred Units and exercise of the Warrants). (15) Unit-Based Compensation Long-Term Incentive Plan In connection with the Partnership’s initial public offering in January 2013, the board of directors of the General Partner(the “Board”) adopted the USA Compression Partners, LP 2013 Long-Term Incentive Plan (“LTIP”) for certain employees,consultants and directors of the General Partner and any of its affiliates who perform services for us. The LTIP provides forawards of unit options, unit appreciation rights, restricted units, phantom units, distribution equivalent rights (“DERs”), unitawards, profits interest units and other unit-based awards. On November 1, 2018 and effective the same day, the Boardapproved and adopted The First Amendment to the LTIP which, among other things, increased the number of common unitsof the Partnership available to be awarded under the LTIP by 8,590,000 common units (which brings the total number ofcommon units available to be awarded under the LTIP to 10,000,000 common units) and extends the term of the LTIP untilNovember 1, 2028. Awards that are forfeited, cancelled, paid or otherwise terminate or expire without the actual delivery ofcommon units will be available for delivery pursuant to other awards. The LTIP is administered by the Board or a committeethereof. The General Partner’s executive officers, certain of its employees and certain of its independent directors were grantedthese awards to incentivize them to help drive our future success and to share in the economic benefits of that success. Allemployees with phantom units have a portion of their award settled in cash and a portion settled in common units uponvesting, unless otherwise approved by the Board. The amount that can be settled in cash is in excess of the employee’sminimum statutory tax-withholding rate. ASC Topic 718 Compensation-Stock Compensation, requires the entire amount ofan award with such features to be accounted for as a liability. Under the liability method of accounting for unit-basedcompensation, we re-measure the fair value of the award at each financial statement date until the award vests or is cancelled.The fair value is measured using the market price of the Partnership’s common units. During the requisite service period (thevesting period of the awards), compensation cost is recognized using the proportionate amount of the award’s fair value thathas been earned through service to date. Phantom units granted to independent directors do not have a cash settlementoption and as such we account for these awards as equity. Each phantom unit is granted in tandem with a correspondingDER, which entitles the recipient to receive an amount in cash on a quarterly basis equal to the product of (a) the number ofthe recipient’s outstanding, unvested phantom units on the record date forF-27 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statementssuch quarter and (b) the quarterly distribution declared by the Board for such quarter with respect to the Partnership’scommon units. During the period from the Transactions Date to December 31, 2018, an aggregate of 1,136,447 phantom units(including the corresponding DERs) were granted under the LTIP to the General Partner’s executive officers and certain of itsemployees and independent directors. The phantom units (including the corresponding DERs) awarded are subject torestrictions on transferability, customary forfeiture provisions and time vesting provisions. Phantom unit awards granted afterJuly 30, 2018 vest incrementally, with 60% of the phantom units vesting at the end of the third year following the grant andthe remaining 40% vesting at the end of the fifth year following the grant. Phantom unit awards that were granted toemployees of USAC Management prior to July 30, 2018 vest evenly over a three-year service period. Phantom units granted prior to July 30, 2018 vest in full in the event of a change in control followed by a termination ofemployment, and phantom units granted on or after July 30, 2018 vest in full upon a change in control. Award recipients donot have all the rights of a unitholder in the Partnership with respect to the phantom units until the units have vested. On the Transactions Date and in connection with the closing of the CDM Acquisition, and pursuant to the change incontrol provisions of our outstanding phantom unit awards, all of the performance-based phantom units granted during 2018,2017 and 2016 and outstanding as of the Transactions Date, vested immediately upon the change in control event at 100%of the target level. In addition, all outstanding time-based phantom units held by our CEO vested immediately upon thechange in control event. As such, 563,544 outstanding phantom units vested resulting in $6.8 million of compensationexpense recognized during the year ended December 31, 2018. ETP had a long-term incentive plan for the USA Compression Predecessor’s employees, officers and directors. ETP hadgranted restricted unit awards to the USA Compression Predecessor’s employees that vested on a pro-rata basis incrementallyover a five-year vesting period, with vesting based on continued employment as of each applicable vesting date. Uponvesting, ETP common units were issued. These restricted unit awards also entitled the recipients of the unit awards to receive,with respect to each ETP common unit subject to such award that had not vested or been forfeited, a corresponding DERentitling the recipient to a cash payment equal to the cash distribution per ETP common unit paid by ETP to its unitholderspromptly following each such distribution. All unit-based compensation awards were treated as equity within the USACompression Predecessor financial statements. The unit and per-unit amounts disclosed in the remainder of this note for periods prior to the Transactions Date reflectamounts related to ETP. These amounts have been retrospectively adjusted to reflect a 1.5 to one unit-for-unit exchangerelated to the merger of ETP and Sunoco Logistics Partners L.P. in April 2017 and a 0.4124 to one unit-for unit exchangerelated to the merger of ETP and Regency Energy Partners LP in April 2015. The unit and per-unit amounts do not reflect theconversion of ETP units to ETE units as a result of the ETE Merger in October 2018. On the Transactions Date and in connection with the closing of the CDM Acquisition, and pursuant to the change incontrol provisions of the USA Compression Predecessor’s outstanding phantom unit awards, all of the USA CompressionPredecessor’s outstanding phantom unit awards were forfeited. As of December 31, 2018, our total unit-based compensation liability was $3.6 million. During the years endedDecember 31, 2018, 2017 and 2016, we recognized $11.7 million, $4.0 million and $3.5 million of compensation expenseassociated with these awards, respectively, recorded in selling, general and administrative expense. During the years endedDecember 31, 2018, 2017 and 2016, amounts paid related to the cash settlement of vested awards under the LTIP were $4.4million, $0.6 million and $0.9 million, respectively. The total fair value and intrinsic value of the phantom units vested under the LTIP was $9.7 million for the period fromthe Transactions Date to December 31, 2018, and $1.6 million and $1.0 million during the years ended December 31,2017 and 2016, respectively. F-28 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial StatementsThe following table summarizes information regarding phantom unit awards for the periods presented: Weighted-Average Grant Date Fair Number of Units Value per Unit (1) USA Compression Predecessor's phantom units outstanding at December 31, 2015 334,354 $32.98 Granted 147,384 24.22 Vested (42,964) 40.28 Forfeited (9,239) 28.58 USA Compression Predecessor's phantom units outstanding at December 31, 2016 429,535 $29.34 Granted 2,500 18.75 Vested (95,499) 36.94 Forfeited (11,614) 27.41 USA Compression Predecessor's phantom units outstanding at December 31, 2017 324,922 $27.10 Forfeited upon change in control, April 2, 2018 (324,922) 27.10 Assumed upon change in control, April 2, 2018 (2) 1,010,522 14.24 Granted (2) 1,136,447 15.47 Vested (2) (571,892) 14.79 Forfeited (2) (144,013) 17.85 Phantom units outstanding at December 31, 2018 1,431,064 $14.98 (1)Determined by dividing the aggregate grant date fair value of awards by the number of units issued. (2)Following the Transactions Date, the outstanding unvested phantom units granted by the USA Compression Predecessor were forfeitedand the outstanding unvested phantom units granted by the Partnership prior to the Transactions Date were maintained. The number ofunits assumed upon change in control represent the Partnership’s unvested outstanding phantom units as of March 31, 2018. Thesubsequent number of units granted, vested and forfeited reflect activity following the Transactions Date through December 31, 2018. The unrecognized compensation cost associated with phantom unit awards was an aggregate $15.0 million as ofDecember 31, 2018. We expect to recognize the unrecognized compensation cost for these awards on a weighted-averagebasis over a period of 2.2 years. (16) Employee Benefit Plans A 401(k) plan is available to all of our employees. The plan permits employees to contribute up to 20% of their salary,up to the statutory limits, which was $18,500 for 2018. The plan provides for discretionary matching contributions by us onan annual basis. Aggregate matching contributions made to employees’ 401(k) plans were $3.2 million for the year endedDecember 31, 2018, including $0.9 million made by ETP to employees of the USA Compression Predecessor prior to theTransactions Date. Refer to Note 14 for information about the 401(k) plan provided by ETP to employees of the USA CompressionPredecessor. (17) Commitments and Contingencies (a)Leases We maintain both capital leases and operating leases, primarily related to office space, warehouse facilities and certaincorporate equipment. We held $7.6 million and $7.6 million of capital leases, in property and equipment as of December 31,2018 and 2017, respectively, representing the present value of the future minimum lease payments over the term of the leasedetermined at the inception of the lease and $4.9 million and $3.8 million of accumulated amortization on assets recordedunder capital leases, respectively. Amortization expense on assets recorded under capitalF-29 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statementsleases is included within depreciation and amortization expense on the consolidated statements of operations. We recorded$1.1 million and $1.2 million as of December 31, 2018 and 2017, respectively, as the current portion of the lease obligation,which is included in accrued liabilities, and $2.1 million and $3.2 million as of December 31, 2018 and 2017, respectively,as the long-term portion of the lease obligation, included in other non-current liabilities on the consolidated balance sheets. Total rent expense for operating leases, including those leases with terms of less than one year, was $4.4 million, $3.6million and $4.0 million for the years ended December 31, 2018, 2017 and 2016, respectively. Commitments for future minimum lease payments for non-cancelable leases, with lease terms in excess of one year, are asfollows (in thousands): 2019 $3,773 2020 1,563 2021 854 2022 569 2023 509 Thereafter 642 Total minimum lease payments $7,910 Less: Amount representing minimum operating lease payments (3,938) Total minimum capital lease payments 3,972 Less: Amount representing estimated taxes, maintenance and insurance costs included intotal amounts above (652) Net minimum capital lease payments 3,320 Less: Amount representing interest (121) Present value of net minimum lease payments $3,199 Less: Current maturities of capital lease obligations (1,085) Long-term capital lease obligations $2,114 (b)Major Customers Neither we nor the USA Compression Predecessor had revenue from any single customer representing 10% or more oftotal revenue for the years ended December 31, 2018, 2017 or 2016. (c)Litigation From time to time, we and our subsidiaries may be involved in various claims and litigation arising in the ordinarycourse of business. In management’s opinion, the resolution of such matters is not expected to have a material adverse effecton our consolidated financial position, results of operations or cash flows. (d)Equipment Purchase Commitments Our future capital commitments are comprised of binding commitments under purchase orders for new compression unitsordered but not received. The commitments as of December 31, 2018 were $107.5 million, all of which is expected to besettled within the next twelve months. (e)Sales Tax Contingency Our compliance with state and local sales tax regulations is subject to audit by various taxing authorities. The Office ofthe Texas Comptroller of Public Accounts (“Comptroller”) has claimed that specific operational processes, which we andothers in our industry regularly conduct, result in transactions that are subject to state sales taxes. We and other companies inour industry have disputed these claims based on existing tax statutes which provide for manufacturingF-30 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statementsexemptions on the transactions in question. The manufacturing exemptions are based on the fact that our natural gascompression equipment is used in the process of treating natural gas for ultimate use and sale. The USA Compression Predecessor has several open audits with the Comptroller for certain periods prior to theTransactions Date wherein the Comptroller has challenged the applicability of the manufacturing exemption. Any liabilityfor the periods prior to the Transactions Date will be covered by an indemnity between us and ETP. As of December 31,2018, we have recorded a $44.9 million accrued liability and $44.9 million related party receivable from ETP. During the year ended December 31, 2018, we entered into a compromise and settlement agreement with the Comptrollerfor the audit of the Partnership for the period from January 2009 to August 2012 for a $0.2 million refund to the Partnership. (f)Environmental The Partnership’s operations are subject to federal, state and local laws and rules and regulations regarding water quality,hazardous and solid waste management, air quality control and other environmental matters. These laws, rules andregulations require the Partnership to conduct its operations in a specified manner and to obtain and comply with a widevariety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with applicableenvironmental laws, rules and regulations may expose the Partnership to significant fines, penalties and/or interruptions inoperations. The Partnership’s environmental policies and procedures are designed to achieve compliance with suchapplicable laws and regulations. These evolving laws and regulations and claims for damages to property, employees, otherpersons and the environment resulting from current or past operations may result in significant expenditures and liabilities inthe future. (18) Recent Accounting Pronouncements In June 2016, the FASB issued ASU 2016-13, Financial Instruments- Credit Losses (“ASC Topic 326”): Measurement ofCredit Losses on Financial Instruments. The amendment in ASC Topic 326 require immediate recognition of estimated creditlosses expected to occur over the remaining life of many financial assets. The amendments in this update are effective forinterim and annual periods beginning after January 1, 2020, with early adoption permitted by one year. We plan to adopt thisnew standard on January 1, 2020 and expect that our adoption of this standard will not have a material impact on ourconsolidated financial statements. In February 2016, the FASB issued ASC Topic 842 Leases (“ASC Topic 842”). ASC Topic 842 is a new leasing standardthat increases transparency and comparability among organizations by, among other things, requiring lessees to recognizemost lease assets and lease liabilities on the balance sheet and requiring both lessees and lessors to disclose expandedqualitative and quantitative information about leasing arrangements. ASC Topic 842 becomes effective for public businessentities for annual and interim periods in fiscal years beginning after December 15, 2018. Early adoption of this standard ispermitted. In March 2018, the FASB approved amendments to ASC Topic 842 which allow the additional transition methodof using the effective date as the date of initial application, as compared to the beginning of the earliest period presented, andrecognize a cumulative-effect adjustment to the beginning balance of retained earnings as of the effective date. We adoptedthis new standard on January 1, 2019 and plan to use the current period adjustment method. Upon adoption, we willrecognize the cumulative effect of adoption as an adjustment to the opening balance of our partners’ capital. Comparativeinformation will continue to be reported under the accounting standards in effect for those periods. Additionally, in July 2018, the FASB approved amendments to ASC Topic 842 (the “July 2018 amendment”) whichprovided lessors with a practical expedient to not separate non-lease components from the associated lease component and,instead, to account for those components as a single component if the non-lease components otherwise would be accountedfor under ASC Topic 606 and certain conditions are met. The July 2018 amendment also provided clarification on whetherASC Topic 842 or ASC Topic 606 is applicable to the combined component based on determination of the predominantcomponent. An entity that elects the lessor practical expedient also should provide certain disclosures. We have evaluatedthe impact of the July 2018 amendment on our contract operations servicesF-31 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statementsagreements and have concluded that the services non-lease component is predominant, which would result in the ongoingrecognition of revenue following ASC Topic 606 guidance. We have completed the collection of our lease data for the effective date and are using information technology tools toassist in our continuing lease data collection and analysis. We are updating our accounting policies and internal controls thatare impacted by the new guidance. We do not believe the standard will materially affect our consolidated balance sheets,statements of operations or cash flows. Our preliminary estimate of the impact of recording lease assets and leaseliabilities on our consolidated balance sheet upon adoption does not exceed $4.0 million, with no material impact to ourconsolidated statements of operations. In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (“ASC Topic 820”): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement. The amendments to ASC Topic 820 eliminate, addand modify certain disclosure requirements for fair value measurements as part of the FASB’s disclosure framework project.The amendments in this update are effective for interim and annual periods beginning on January 1, 2020, with earlyadoption permitted. We are currently evaluating the impact, if any, of the amendments to ASC Topic 820 on ourconsolidated financial statements. In August 2018, the FASB issued ASU 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (“ASC Subtopic350-40”): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a ServiceContract. The amendments to ASC Subtopic 350-40 align the requirements for capitalizing implementation costs incurred ina hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred todevelop or obtain internal-use software (and hosting arrangements that include an internal-use software license). Theaccounting for the service element of a hosting arrangement that is a service contract is not affected by the amendments toASC Subtopic 350-40. The amendments in this update are effective for interim and annual periods beginning on January 1,2020, with early adoption permitted. The amendments in this update should be applied either retrospectively orprospectively to all implementation costs incurred after the date of adoption. We are currently evaluating the impact, if any,of the amendments to ASC Subtopic 350-40 on our consolidated financial statements. (19) Subsequent Events Phantom Units In January 2019, an aggregate of 15,150 phantom units (including the corresponding DERs) were granted under theLTIP to two of the independent directors of the General Partner. The phantom units (including the corresponding DERs)awarded are subject to restrictions on transferability, customary forfeiture provisions and will vest incrementally, with 60% ofthe phantom units vesting on December 5, 2021 and 40% of the phantom units vesting on December 5, 2023. The phantomunits will vest in full upon a change in control of the Partnership. F-32 Table of ContentsSupplemental Selected Quarterly Financial Data(Unaudited) In the opinion of our management, the summarized quarterly financial data below (in thousands, except per unitamounts) contains all appropriate adjustments, all of which are normally recurring adjustments, considered necessary topresent fairly our financial position and the results of operations for the respective periods. March 31, June 30, September30, December 31, 2018 2018 2018 2018 Revenue $76,530 $166,898 $168,947 $171,977 Gross profit (1) $39,195 $109,365 $104,638 $116,430 Net loss attributable to common and Class B unitholders' interests $(23,370) $(8,857) $(12,751) $(2,003) Net income (loss) per common unit - basic and diluted (2) $(0.06) $(0.10) $0.01 Net loss per Class B Unit - basic and diluted (2) $(0.58) $(0.62) $(0.51) March 31, June 30, September30, December 31, 2017 2017 2017 2017 Revenue $65,271 $67,372 $71,089 $72,939 Gross profit (1) $36,729 $37,025 $39,422 $38,291 Net loss $(10,448) $(9,715) $(12,355) $(232,216) (1)Gross profit is defined as revenue less cost of operations, exclusive of depreciation and amortization expense. (2)Earnings per unit is not applicable to the USA Compression Predecessor for periods prior to the Transactions Date as the USACompression Predecessor had no outstanding common units prior to the Transactions. S-1Exhibit 10.13EMPLOYMENT AGREEMENTThis Employment Agreement (“Agreement”) is made and entered into as of July 1, 2016 (the "EffectiveDate") by and between USA Compression Management Services, LLC, a Delaware limited liability company(hereafter the “Company”), and Sean T. Kimble (“Employee”).WHEREAS, Employee and the Company desire to enter into this Agreement as set forth herein.NOW, THEREFORE, in consideration of the foregoing and the mutual covenants contained herein,Employee and the Company, intending to be legally bound, do hereby agree as follows:1. Employment. During the Employment Period (as defined in Section 4 below), the Company shallemploy Employee, and Employee shall serve, as Vice President — Human Resources of the Company.2. Duties and Responsibilities of Employee.(a) During the Employment Period, Employee shall: (i) devote all of Employee’s business time andattention to the business of the Company and its Affiliates (as defined below) (collectively, the“Company Group”, which term shall include, for the avoidance of doubt, any subsidiaries orother entities that become Affiliates of the Company from and after the date hereof), asapplicable, (ii) will act in the best interests of the Company Group and (iii) will perform withdue care Employee’s duties and responsibilities. Employee’s duties will include those normallyincidental to the position of a Vice President of Human Resources, as well as whateveradditional duties may be assigned to Employee by the Chief Executive Officer or the board ofdirectors of USA Compression GP, LLC (the “Board”), which duties may include, withoutlimitation, providing services to members of the Company Group in addition to the Company.Employee agrees to cooperate fully with the Board and not to engage in any activity thatinterferes with the performance of Employee’s duties hereunder. During the EmploymentPeriod, Employee will not hold any type of outside employment, engage in any type ofconsulting or otherwise render services to or for any other person or business concern withoutthe advance written consent of the Board; provided, that the foregoing shall not precludeEmployee from managing private investments, participating in industry and/or trade groups,engaging in volunteer civic, charitable or religious activities, serving on boards of directors ofcharitable not-for-profit entities or, with the consent of the Board, which consent is not to beunreasonably withheld, serving on the board of directors of other entities, in each case as long assuch activities, individually or in the aggregate, do not materially interfere or conflict withEmployee's responsibilities to the Company.1 (b) Employee represents and covenants that Employee is not the subject of or a party to anyemployment agreement, non-competition covenant, nondisclosure agreement, or any otheragreement, covenant, understanding, or restriction that would prohibit Employee from executingthis Agreement and fully performing Employee's duties and responsibilities hereunder orthereunder, or would in any manner, directly or indirectly, limit or affect the duties andresponsibilities that may now or in the future be assigned to Employee hereunder.(c) Employee acknowledges and agrees that Employee owes the Company Group a duty of loyaltyas a fiduciary of the Company Group, and that the obligations described in this Agreement arein addition to, and not in lieu of, the obligations Employee owes the Company Group under thecommon law.3. Compensation.(a) During the Employment Period, the Company shall pay to Employee an annualized base salaryof $290,000 (the “Base Salary”) in consideration for Employee's services under thisAgreement, payable on a bi-weekly basis, in conformity with the Company's customer payrollpractices for similarly situated employees. The Board will annually review the Base Salary,which may be increased but not decreased during the Employment Period based on Employee’sperformance and market conditions.(b) During the Employment Period, Employee shall be entitled to participate in the bonus programsestablished for employees of the Company, as may be amended from time to time. Theperformance targets that must be achieved in order to be eligible for certain bonus levels shall beestablished by the Board each year within 90 days following the start of the applicable fiscalyear, in its sole discretion, and communicated to Employee. If the Board determines thatEmployee meets the performance targets established for a particular fiscal year, then his bonusfor that year (the “Annual Bonus”) will be in an amount up to $203,000 (the “Target AnnualBonus”), in accordance with the terms of the bonus program in effect for the applicable year. Inaddition, in the event Employee outperforms and exceeds the performance targets establishedfor a particular fiscal year, Employee may receive an additional outperformance bonus for theapplicable year, in an amount determined in the sole discretion of the Board (an“Outperformance Bonus”). The Annual Bonus and any Outperformance Bonus shall be paidno later than March 15 of the year following the year in which the Annual Bonus orOutperformance Bonus is earned, and shall not be payable unless Employee remains employedby the Company on the date that such bonus is paid, except in the case of a termination ofEmployee due to the death or Disability of Employee, by the Company for convenience, or aresignation by Employee for Good Reason, in which case Employee will be entitled to2 (i) the entire amount of any earned Annual Bonus for the year preceding the year in whichEmployee dies, becomes Disabled, is terminated by the Company for convenience or resigns forGood Reason and (ii) a pro rata portion (based on the number of days employed during theyear) of any earned Annual Bonus for the year in which Employee dies, becomes Disabled, isterminated by the Company for convenience or resigns for Good Reason in each case in theyear following the year to which the applicable bonus relates.4. Term of Employment. The initial term of this Agreement shall be for the period beginning on theEffective Date and ending on the second anniversary of the Effective Date (the “Initial Term”). On the secondanniversary of the Effective Date and on each subsequent anniversary thereafter, this Agreement shall automaticallyrenew and extend for a period of 12 months (each such 12-month period being a “Renewal Term”) unless writtennotice of non-renewal is delivered from either party to the other not less than 90 days prior to the expiration of the then-existing Initial Term or Renewal Term. Notwithstanding any other provision of this Agreement, Employee'semployment pursuant to this Agreement may be terminated at any time in accordance with Section 6. The period fromthe Effective Date through the expiration of this Agreement or, if sooner, the termination of Employee's employmentpursuant to this Agreement, regardless of the time or reason for such termination, shall be referred to herein as the“Employment Period.”5. Benefits. Subject to the terms and conditions of this Agreement, Employee shall be entitled to thefollowing benefits during the Employment Period:(a) Reimbursement of Business Expenses. Subject to Section 24 hereof (regarding section 409Acompliance), the Company agrees to reimburse Employee for Employee's reasonable business-related expenses incurred in the performance of Employee's duties under this Agreement;provided, that Employee timely submits all documentation for such reimbursement, as requiredby Company policy in effect from time-to-time. Employee is not permitted to receive a paymentin lieu of reimbursement under this Section 5(a).(b) Benefits. During the Employment Period, Employee and where applicable Employee’s spouseand dependents shall be eligible to participate in the same benefit plans or fringe benefit policies,other than severance programs, such as health, dental, life insurance, vision, and 401(k), as areoffered to members of the Company’s executive management and in each case on no lessfavorable than the terms of benefits generally available to the employees of the Company (basedon seniority and salary level), subject to applicable eligibility requirements and the terms andconditions of all plans and policies.(c) Paid Time Off. During the Employment Period, Employee shall accrue paid time off (“PaidTime Off”) at a rate of 20 days per calendar year during the Employment Period; provided,however, that Employee shall3 cease accruing Paid Time Off once Employee has accrued 20 unused days’ worth of Paid TimeOff, and such accrual will begin again only after Employee has used accrued Paid Time Offsuch that Employee's accrued entitlement to Paid Time Off is once again less than 20 days.Employee shall take Paid Time Off in accordance with all Company policies and with dueregard for the needs of the Company Group.6. Termination of Employment.(a) Company’s Right to Terminate Employee’s Employment for Cause. The Company shall havethe right to terminate Employee’s employment hereunder at any time for “Cause.” For purposesof this Agreement, "Cause" shall mean:(i) any material breach of this Agreement by Employee, including, withoutlimitation, the material breach of any representation, warranty or covenant madeunder this Agreement by Employee;(ii) Employee’s breach of any applicable duties of loyalty to the Company or any ofits Affiliates, gross negligence or material misconduct, or a significant act or actsof personal dishonesty or deceit, taken by Employee, in the performance ofduties and services required of Employee that is demonstrably and significantlyinjurious to the Company or any of its Affiliates;(iii) conviction of Employee of a felony or crime involving moral turpitude;(iv) Employee’s willful and continued failure or refusal to perform substantiallyEmployee's material obligations pursuant to this Agreement or follow any lawfuland reasonable directive from the Chief Executive Officer or the Board, otherthan as a result of Employee's incapacity; or(v) a violation of a federal, state or local law or regulation applicable to the businessof the Company that is demonstrably and significantly injurious to the Company.Prior to Employee’s termination for Cause, the Company must give written notice toEmployee describing the act or omission of Employee giving rise to the determination ofCause and, in respect of circumstances capable of cure, such circumstances must remainuncured for 15 days following receipt by Employee of such written notice, provided,that Employee shall not be entitled to cure any4 such acts or omissions if Employee has previously cured any acts or omissions in theimmediately preceding six months.(b) Company’s Right to Terminate for Convenience. The Company shall have the right to terminateEmployee's employment for convenience at any time and for any reason, or no reason at all,with written notice to Employee, subject to the provisions of Section 6(g) regarding theseverance benefits. For purposes of this Agreement, the Company's failure to renew theAgreement at the end of Initial Term or a Renewal Term shall be deemed a termination ofEmployee's employment for convenience.(c) Employee’s Right to Terminate for Good Reason. Employee shall have the right to terminateEmployee's employment with the Company at any time for “Good Reason.” For purposes ofthis Agreement, “Good Reason” shall mean:(i) a material breach by the Company of any of its covenants or obligations underthis Agreement or any other material agreement with Employee;(ii) any material reduction in Employee’s Base Salary, other than a reduction that isgenerally applicable to all similarly situated employees of the Company;(iii) a material reduction by the Company in Employee's duties, authority,responsibilities, job title or reporting relationships as in effect immediately priorto such reduction, or the assignment to Employee of such reduced duties,authority, responsibilities, job title or reporting relationships;(iv) a material reduction of the facilities and perquisites available to Employeeimmediately prior to such reduction, other than a reduction that is generallyapplicable to all similarly situated employees of the Company; or(v) the relocation of the geographic location of Employee's principal place ofemployment by more than 50 miles from the location of Employee’s principalplace of employment as of the Effective Date.Notwithstanding the foregoing provisions of this Section 6(c) or any other provision ofthis Agreement to the contrary, any assertion of Employee of a termination for GoodReason shall not be effective unless all of the following conditions are satisfied: (A) thecondition giving rise to Employee’s termination of employment must have arisenwithout Employee’s written consent;5 (B) Employee must provide written notice to the Board of such condition within 30 daysof the initial existence of the condition; (C) the condition specified in such notice mustremain uncorrected for 30 days after receipt of such notice by the Board; and (D) thedate of Employee's termination of employment must occur within the 90-day period afterthe initial existence of the condition specified in such notice, in which case, if GoodReason is found to exist and Employee otherwise complies with Section 6(g), Employeewill be entitled to receive the severance benefits provided in Section 6(g).(d) Death or Disability. Upon the death or Disability (as defined below) of Employee, Employee'semployment with Company shall terminate and the Company shall have no further obligation toEmployee, or Employee's successor(s) in interest; provided, that the Company shall pay toEmployee or the estate of Employee the amounts set forth in Section 6(h), plus any AnnualBonus or Outperformance Bonus provided for in Section 3(b). For purposes of this Agreement,“Disability” shall mean that Employee is unable to perform the essential functions ofEmployee’s position, with reasonable accommodation, due to an illness or physical or mentalimpairment or other incapacity which continues for a period in excess of 20 consecutive weeks.The determination of Disability will be made by a physician selected by Employee andacceptable to the Company or its insurers, with such agreement to the acceptability not to beunreasonably withheld.(e) Employee’s Right to Terminate for Convenience. Employee shall have the right to terminateEmployee’s employment with the Company for convenience at any time and for any reason, orno reason at all, upon 30 days' advance written notice to the Company.(f) Termination upon Non-Renewal of the Agreement. Except as otherwise mutually agreedbetween the Company and Employee, if the Company or Employee provides the other partywith a written notice of non-renewal of this Agreement in accordance with Section 4,Employee’s employment with Company shall automatically terminate upon the expiration of thethen-applicable Initial Term or Renewal Term, as applicable.(g) Effect of Termination for Convenience or Good Reason Resignation. If Employee incurs aSeparation from Service (as defined below) due to Employee’s employment terminatingpursuant to Sections 6(b) or 6(c) (regarding termination for convenience and resignation forGood Reason) above and Employee: (x) executes within 45 days following the date ofEmployee’s Separation from Service, and does not revoke, a release of all claims in a formsatisfactory to the Company, which such form will be promptly provided by Company toEmployee on or before his Separation from Service substantially in the form of releasecontained at Exhibit A6 (the “Release”); and (y) abides by Employee’s continuing obligations hereunder, including,without limitation, the provisions of Sections 8 and 9 hereof (regarding confidentiality and non-competition), then Employee shall be entitled to the following, in addition to the amountsdescribed in Section 6(h), and any Annual Bonus or Outperformance Bonus provided for inSection 3(b):(i) Severance Pay. The Company shall make severance payments to Employee inan aggregate amount equal to one times Employee's Base Salary as in effect asof the date of Employee's termination of employment (or Base Salary for anypreceding year in the Employment Period, if greater) (the “SeverancePayment”). If payable, the Severance Payment will be made, as applicable, inequal semi-monthly installments over the one-year period following the date ofEmployee's Separation from Service (the “Severance Period”), in accordancewith the Company’s regular payroll practices, provided, that any such installmentpayments that would otherwise be paid prior to the Company’s first regularpayroll date that occurs on or after the 60th day following the date ofEmployee’s Separation from Service (the “First Pay Date”) shall be paid on theFirst Pay Date. Notwithstanding the foregoing, in the event of Employee’s deathduring the Severance Period, all remaining Severance Payments due him shall bepaid in a lump sum within 30 days of Employee's death. Likewise,notwithstanding the other provisions of this Section 6(g)(i), in the event of atermination for convenience by the Company or termination by Employee forGood Reason within two years following the occurrence of a “change in controlevent” within the meaning of Treasury Regulation Section 1.409A-3(i)(5), theSeverance Payment shall be paid in a lump sum on the Company's first regularpayroll date that occurs on or after 30 days of the date of Employee’s Separationfrom Service.(ii) Continued Health Insurance Benefits. For a period of 24 months followingEmployee’s Separation from Service (which period of 24 months shall includeand run concurrently with any so-called COBRA continuation period applicableto Employee and/or his eligible dependents under Section 4980B of the Code,and may be subject to Employee and/or his eligible dependents electing suchcontinuation coverage), provided, however, that (A) during the first 12 monthsof such coverage, the Company shall continue to provide health insurancebenefits to Employee and any eligible dependents at the7 Company’s expense (other than Employee’s monthly cost-sharing contributionunder the Company’s group health plan, as in effect on the date of Employee’sSeparation from Service), and (B) during the remaining 12 months of suchcoverage, the Company shall continue to provide health insurance benefits toEmployee and any eligible dependents at Employee's expense. Notwithstandingthe previous sentence, if the Company determines in its sole discretion that itcannot provide the foregoing benefit without potentially violating applicable law(including, without limitation, Section 2716 of the Public Health Service Act andany applicable non-discrimination requirement thereunder or otherwise), theCompany shall in lieu thereof provide to Employee a taxable monthly paymentin an amount equal to the monthly COBRA premium that Employee would berequired to pay to continue his and his covered dependents’ group healthcoverage in effect on the Date of Termination for the 12 month period followingthe date of Employee's Separation from Service (which amount shall be based onthe premium for the first month of COBRA coverage), less the amount ofEmployee's monthly cost-sharing contribution under the Company’s grouphealth plan, as in effect on the date of Employee’s Separation from Service atemployee rates in effect thereunder as of the Separation from Service.(h) Effect of Termination. Subject to Section 24 hereof (regarding section 409A compliance), uponthe termination of Employee’s employment for any reason, all earned, unpaid Base Salary andall accrued, unused Paid Time Off shall be paid to Employee within 30 days of the date ofEmployee’s termination of employment, or earlier if required by law. With the exception of anypayments to which Employee may be entitled pursuant to Section 5(a) (regarding businessexpenses) and Section 6(g) (regarding severance benefits), the Company shall have no furtherobligation under this Agreement to make any payments to Employee.7. Conflicts of Interest. Employee agrees that Employee shall promptly disclose to the Board any conflictof interest involving Employee upon Employee becoming aware of such conflict.8. Confidentiality. Employee acknowledges and agrees that, in the course of Employee's employmentwith the Company and the performance of Employee’s duties on behalf of the Company Group hereunder, Employeewill be provided with, and have access to, valuable Confidential Information (as defined below) of the CompanyGroup and exchange for other8 valuable consideration provided hereunder, Employee agrees to comply with this Section 8 and Section 9.(a) Employee covenants and agrees, both during the term of the Employment Period and thereafterthat, except as expressly permitted by this Agreement or by directive of the Board, Employeeshall not disclose any Confidential Information to any person or entity and shall not use anyConfidential, Information except for the benefit of the Company Group. Employee shall take allreasonable precautions to protect the physical security of all documents and other materialcontaining Confidential Information (regardless of the medium on which the ConfidentialInformation is stored). This covenant shall apply to all Confidential Information, whether nowknown or later to become known to Employee during the Employment Period.(b) Notwithstanding Section 5(a), Employee may make the following disclosures and uses ofConfidential Information:(i) disclosures to other employees of the Company Group in connection with thefaithful performance of duties for the Company Group;(ii) disclosures to customers and suppliers when, in the reasonable and good faithbelief of Employee, such disclosure is in connection with Employee’sperformance of services under this Agreement and is in the best interests of theCompany Group;(iii) disclosures and uses that are approved by the Board;(iv) disclosures to a person or entity that has been retained by the Company Group toprovide services to the Company Group, and has agreed in writing to abide bythe terms of a confidentiality agreement;(v) disclosures for the purpose of complying with any applicable laws or regulatoryrequirements;(vi) disclosures to Employee’s legal, tax or financial advisors for the purpose ofassisting such advisors in providing advice to Employee, provided, however,that such advisors agree to maintain the confidentiality of such disclosures; or(vii) disclosures that Employee is legally compelled to make by deposition,interrogatory, request for documents, subpoena, civil investigative demand, orderof a court of competent jurisdiction, or similar process, or otherwise by law;9 provided, however, that, prior to any such disclosure, Employee shall, to theextent legally permissible:(A) provide the Board with prompt notice of such requirements so that theBoard may seek a protective order or other appropriate remedy or waivecompliance with the terms of this Section;(B) consult with the Board on the advisability of taking steps to resist ornarrow such disclosure; and(C) cooperate with the Board (at the Company’s cost and expense) in anyattempt the Board may make to obtain a protective order or otherappropriate remedy or assurance that confidential treatment will beafforded the Confidential Information; and in the event such protectiveorder or other remedy is not obtained, Employee agrees (y) to furnishonly that portion of the Confidential Information that is legally requiredto be furnished, as advised by counsel to Employee, and (z) to exercise(at the Company’s reasonable cost and expense) all reasonable efforts toobtain assurance that confidential treatment will be accorded suchConfidential Information.(c) Upon the expiration of the Employment Period and at any other time upon request of theCompany, Employee shall surrender and deliver to the Company all documents (including,without limitation, electronically stored information) and other material of any nature containingor pertaining to all Confidential Information in Employee’s possession and shall not retain anysuch document or other material. Within 10 days of any such request, Employee shall certify tothe Company in writing that all such materials have been returned to the Company.(d) All non-public information, designs, ideas, concepts, improvements, product developments,discoveries and inventions, whether patentable or not, that are conceived, made, developed oracquired by Employee, individually or in conjunction with others, during the EmploymentPeriod (whether during business hours or otherwise and whether on the Company’s premises orotherwise) that relate to the Company Group’s businesses or properties, products or services(including, without limitation, all such information relating to corporate opportunities, businessplans, strategies for developing business and market share, research, financial and sales data,pricing terms, evaluations, opinions, interpretations, acquisition prospects, the identity ofcustomers or their requirements, the identity of key contacts within customers' organizations10 or within the organization of acquisition prospects, or marketing and merchandising techniques,prospective names and marks) is defined as “Confidential Information.” Moreover, alldocuments, videotapes, written presentations, brochures, drawings, memoranda, notes, records,files, correspondence, manuals, models, specifications, computer programs, e-mail, voice mail,electronic databases, maps, drawings, architectural renditions, models and all other writings ormaterials of any type including or embodying any of such information, ideas, concepts,improvements, discoveries, inventions and other similar forms of expression are and shall be thesole and exclusive property of the Company Group and be subject to the same restrictions ondisclosure applicable to all Confidential Information pursuant to this Agreement.9. Non-Competition.(a) The Company shall provide Employee access to the Confidential Information for use onlyduring the Employment Period, and Employee acknowledges and agrees that the CompanyGroup will be entrusting Employee, in Employee’s unique and special capacity, withdeveloping the goodwill of the Company Group, and in consideration thereof and inconsideration of the access to Confidential Information, has voluntarily agreed to the covenantsset forth in this Section. Employee further agrees and acknowledges that the limitations andrestrictions set forth herein, including, but not limited to, geographical and temporal restrictionson certain competitive activities, are reasonable and not oppressive and are material andsubstantial parts of this Agreement intended and necessary to prevent unfair competition and toprotect the Company Group’s Confidential Information and substantial and legitimate businessinterests and goodwill.(b) During the Employment Period and for a period of two years (the “Restricted Period”)following the termination of the Employment Period for any reason, Employee shall not, forwhatever reason and with or without cause, either individually or in partnership or jointly or inconjunction with any other Person or Persons as principal, agent, employee, shareholder (otherthan holding equity interests listed on a United States stock exchange or automated quotationsystem that do not exceed 5% of the outstanding shares so listed), owner, investor, partner or inany other manner whatsoever, directly or indirectly, engage in or compete with the Businessanywhere in the world.(c) During the Restricted Period, Employee shall not (i) knowingly induce or attempt to induce anyother Person known to Employee to be a customer of the Company or its affiliates (each, a“Customer”) to cease doing any business with the Company or its affiliates anywhere in theworld or (ii) solicit business involving the Business from, or provide services related to theBusiness to, any Customer.11 (d) During the Restricted Period, Employee shall not solicit the employment of any individual whois an employee of the Company or its affiliates, except that Employee shall not be precludedfrom soliciting the employment of, or hiring, any such individual (i) whose employment with theCompany or one of its affiliates has been terminated before entering into employmentdiscussions with such Seller, (ii) who initiates discussions with Employee regardingemployment opportunities with Employee or (iii) responds to a general advertisement or othersimilarly broad form of solicitation for employees.(e) For purposes of this Section 9, the following terms shall have the following meanings:(i) “Business” shall mean the business of providing natural gas compressionservices through the deployment and maintenance of on-site compressorpackages and any other line of business in which the Company Group isengaged at the time of termination or has taken substantial steps to enter duringthe Employment Period and is actively pursuing at the time of termination.(ii) “Person” means any individual, corporation, partnership, limited liabilitycompany, association, trust, incorporated organization, other entity or group (asdefined in Section 13(d)(3) of the Securities Exchange Act of 1934, asamended).(f) Because of the difficulty of measuring economic losses to the Company Group as a result of abreach of the foregoing covenants, and because of the immediate and irreparable damage thatcould be caused to the Company Group for which it would have no other adequate remedy,Employee agrees that the foregoing covenant may be enforced by the Company, in the event ofbreach by Employee, by injunctions and restraining orders and that such enforcement shall notbe the Company's exclusive remedy for a breach but instead shall be in addition to all otherrights and remedies available to the Company.(g) The covenants in this Section 9 are severable and separate, and the unenforceability of anyspecific covenant shall not affect the provisions of any other covenant. Moreover, in the eventany arbitrator or court of competent jurisdiction shall determine that the scope, time or territorialrestrictions set forth are unreasonable, then it is the intention of the parties that such restrictionsbe enforced to the fullest extent which the panel or court deems reasonable, and this Agreementshall thereby be reformed.(h) All of the covenants in this Section 9 shall be construed as an agreement independent of anyother provision in this Agreement; and the existence of12 any claim or cause of action of Employee against the Company, whether predicated on thisAgreement or otherwise, shall not constitute a defense to the enforcement by the Company ofsuch covenants.10. Ownership of Intellectual Property. Employee agrees that the Company shall own, and Employeeagrees to assign and does hereby assign, all right, title and interest (including, but not limited, to patent rights,copyrights, trade secret rights, mask work rights, trademark rights, and all other intellectual and industrial propertyrights of any sort throughout the world) relating to any and all inventions (whether or not patentable), works ofauthorship, mask works, designs, ideas and information authored, created, contributed to, made or conceived orreduced to practice, in whole or in part, by Employee during the Employment Period which either (a) relate, at the timeof conception, reduction to practice, creation, derivation or development, to the Company Group’s businesses or actualor anticipated research or development, or (b) were developed on any amount of the Company’s time or with the use ofany of the Company Group’s equipment, supplies, facilities or trade secret information (all of the foregoing collectivelyreferred to herein as “Company Intellectual Property”); and Employee will promptly disclose all Company IntellectualProperty to the Company. All of Employee’s works of authorship and associated copyrights created during theEmployment Period and in the scope of Employee's employment shall be deemed to be “works made for hire” withinthe meaning of the Copyright Act. Employee agrees to perform, during and after the Employment Period, allreasonable acts deemed necessary by the Company Group to assist the Company, at the Company’s expense, inobtaining and enforcing its rights throughout the world in the Company Intellectual Property. Such acts may include,but are not limited to, execution of documents and assistance or cooperation (a) in the filing, prosecution, registration,and memorialization of assignment of any applicable patents, copyrights, mask work, or other applications, (b) in theenforcement of any applicable patents, copyrights, mask work, moral rights, trade secrets, or other proprietary rights,and (c) in other legal proceedings related to the Company Intellectual Property.11. Arbitration.(a) Subject to Section 11(b), any dispute, controversy or claim between Employee and theCompany arising out of or relating to this Agreement or Employee's employment with theCompany will be finally settled by arbitration in Austin, Texas before, and in accordance withthe rules for the resolution of employment disputes then in effect of, the American ArbitrationAssociation (“AAA”). The arbitration award shall be final and binding on both parties.(b) Any arbitration conducted under this Section 11 shall be heard by a single arbitrator (the“Arbitrator”) selected in accordance with the then applicable rules of the AAA. The Arbitratorshall expeditiously (and, if possible, within 90 days after the selection of the Arbitrator) hear anddecide all matters concerning the dispute. Except as expressly provided to the contrary in thisAgreement, the Arbitrator shall have the power to (i) gather such materials, information,testimony and evidence as he or she deems relevant to the dispute before him or her (and eachparty will13 provide such materials, information, testimony and evidence requested by the Arbitrator, exceptto the extent any information so requested is subject to an attorney-client or other privilege and,if the information so requested is proprietary or subject to a third party confidentiality restriction,the arbitrator shall enter an order providing that such material will be subject to a confidentialityagreement), and (ii) grant injunctive relief and enforce specific performance. The decision of theArbitrator shall be rendered in writing, be final, non-appealable and binding upon the disputingparties and the parties agree that judgment upon the award may be entered by any court ofcompetent jurisdiction; provided, that the parties agree that the Arbitrator and any courtenforcing the award of the Arbitrator shall not have the right or authority to award punitive orexemplary damages to any disputing party.(c) Each side shall share equally the cost of the arbitration and bear its own costs and attorneys’fees incurred in connection with any arbitration, unless the Arbitrator determines that compellingreasons exist for allocating all or a portion of such costs and fees to the other side.(d) Notwithstanding Section 11(a), an application for emergency or temporary injunctive relief byeither party shall not be subject to arbitration under this Section; provided, however, that theremainder of any such dispute (beyond the application for emergency or temporary injunctiverelief) shall be subject to arbitration under this Section.(e) By entering into this Agreement and entering into the arbitration provisions of this Section 11,THE PARTIES EXPRESSLY ACKNOWLEDGE AND AGREE THAT THEY AREKNOWINGLY, VOLUNTARILY AND INTENTIONALLY WAIVING THEIR RIGHTSTO A JURY TRIAL.(f) Nothing in this Section 11 shall prohibit a party to this Agreement from (i) instituting litigation toenforce any arbitration award, or (ii) joining another party to this Agreement in a litigationinitiated by a person or entity which is not a party to this Agreement.12. Defense of Claims. Employee agrees that, during the Employment Period and thereafter, upon requestfrom the Company, Employee will reasonably cooperate with the Company Group in the defense of any claims oractions that may be made by or against the Company Group that relate to Employee's actual or prior areas ofresponsibility, except if Employee's reasonable interests are adverse to the Company or its Affiliate(s), as applicable, insuch claim or action. The Company agrees to pay or reimburse Employee for all of Employee's reasonable travel andother direct expenses incurred, or to be reasonably incurred, to comply with Employee's obligations under this Section,provided, Employee provides reasonable documentation of same and obtains the Company's prior approval forincurring such expenses. After the expiration of one year following the date of Employee's Separation from Service,the Company will compensate Employee for the time Employee spends on reasonable cooperation14 and assistance at the Company’s request at a rate per hour calculated, by dividing his annualized Base Salary at the endof the Employment Period by 2,080.13. Withholdings; Deductions. The Company may withhold and deduct from any payments made or to bemade pursuant to this Agreement (a) all federal, state, local and other taxes or other amounts as may be requiredpursuant to any law or governmental regulation or ruling and (b) any deductions consented to in writing by Employee.14. Title and Headings; Construction. Titles and headings to Sections hereof are for the purpose ofreference only and shall in no way limit, define or otherwise affect the provisions hereof. Any and all Exhibits orAttachments referred to in this Agreement are, by such reference, incorporated herein and made a part hereof for allpurposes. The words “herein”, “hereof”, “hereunder” and other compounds of the word “here” shall refer to the entireAgreement and not to any particular provision hereof.15. Applicable Law; Submission to Jurisdiction. This Agreement shall in all respects be construedaccording to the laws of the State of Texas. With respect to any claim or dispute related to or arising under thisAgreement, the parties hereby consent to the arbitration provisions of Section 11 above and recognize and agree thatshould any resort to a court be necessary and permitted under this Agreement, then they consent to the exclusivejurisdiction, forum and venue of the state and federal courts located in Austin, Texas.16. Entire Agreement and Amendment. This Agreement contains the entire agreement of the parties withrespect to the matters covered herein; moreover, this Agreement supersedes all prior and contemporaneous agreementsand understandings, oral or written, between the parties hereto concerning the subject matter hereof (excluding (i)Employee’s current elections and rights under the Company's health or 401(k) benefit plans or (ii) the LTIP grantagreements between USAC and Employee dated as of August 8, 2014, February 19, 2015 and February 11, 2016,each of which remains in place). This Agreement may be amended only by a written instrument executed by bothparties hereto.17. Waiver of Breach. Any waiver of this Agreement must be executed by the party to be bound by suchwaiver. No waiver by either party hereto of a breach of any provision of this Agreement by the other party, or ofcompliance with any condition or provision of this Agreement to be performed by such other party, will operate or beconstrued as a waiver of any subsequent breach by such other party or any similar or dissimilar provision or conditionat the same or any subsequent time. The failure of either party hereto to take any action by reason of any breach willnot deprive such party of the right to take action at any time while such breach continues.18. Assignment. This Agreement is personal to Employee, and neither this Agreement nor any rights orobligations hereunder shall be assignable or otherwise transferred by Employee. The Company may assign thisAgreement to any member of the Company Group and to any successor (whether by merger, purchase or otherwise) toall or substantially all of the equity, assets or businesses of the Company, if such successor expressly agrees to assumethe obligations of the Company hereunder.15 19. Affiliates. For purposes of this Agreement, the term “Affiliates” means any person or entityControlling, Controlled by or Under Common Control with such person or entity, but with respect to the Company,specifically does not mean Riverstone, the entities Controlling it, and its investment funds, partners of its investmentfunds, and its portfolio companies other than the Company and its subsidiaries. The term “Control,” including thecorrelative terms “Controlling,” “Controlled by,” and “Under Common Control with” means possession, directly orindirectly, of the power to direct or cause the direction of management or policies (whether through ownership ofsecurities or any Company or other ownership interest, by contract or otherwise) of a person or entity. For the purposesof the preceding sentence, Control shall be deemed to exist when a person or entity possesses, directly or indirectly,through one or more intermediaries (a) in the case of a corporation more than 50% of the outstanding voting securitiesthereof; (b) in the case of a limited liability company, partnership or joint venture, the right to more than 50% of thedistributions therefrom (including liquidating distributions); or (c) in the case of any other person or entity, more than50% of the economic or beneficial interest therein.20. Notices. Notices provided for in this Agreement shall be in writing and shall be deemed to have beenduly received (a) when delivered in person or sent by facsimile transmission, (b) on the first business day after suchnotice is sent by air express overnight courier service, or (c) on the third business day following deposit in the UnitedStates mail, registered or certified mail, return receipt requested, postage prepaid and addressed, to the followingaddress, as applicable:If to the Company, addressed to:USA Compression Management Services, LLC100 Congress Avenue, Suite 1550Austin, TX 78701Attn: J. Gregory HollowayFacsimile: (512) 473-2616and a copy to:R/C IV USACP Holdings, L.P. c/o Riverstone Holdings, LLC 712 Fifth Avenue, 51 Floor New York, NY 10019Attn: Andrew W. WardFacsimile: (212) 993-007716 stand a copy to:Vinson & Elkins1001 Fannin StreetSuite 2500Houston, Texas 77002-6760Attn: E. Ramey LayneFacsimile: (713) 751-5396If to Employee, addressed to:Sean T. Kimble16904 Dawn Flower CoveAustin, Texas 78738Facsimile: (____) ___-___21. Counterparts. This Agreement may be executed in any number of counterparts, including by electronicmail or facsimile, each of which when so executed and delivered shall be an original, but all such counterparts shalltogether constitute one and the same instrument. Each counterpart may consist of a copy hereof containing multiplesignature pages, each signed by one party, but together signed by both parties hereto.22. Deemed Resignations. Unless otherwise agreed to in writing by the Company and Employee prior tothe termination of Employee’s employment, any termination of Employee's employment shall constitute: (a) anautomatic resignation of Employee as an officer of the Company and each member of the Company Group, asapplicable, and (b) an automatic resignation of Employee from the Board (if applicable), from the board of directors ormanagers of any member of the Company Group (if applicable) and from the board of directors or managers or anysimilar governing body of any corporation, limited liability entity or other entity in which the Company or any Affiliateholds an equity interest and with respect to which board or similar governing body Employee serves as the Company'sor such Affiliate's designee or other representative (if applicable).23. Key Person Insurance. At any time during the Employment Period, the Company shall have the rightto insure the life of Employee for the Company’s sole benefit. The Company shall have the right to determine theamount of insurance and the type of policy. Employee shall cooperate with the Company in obtaining such insuranceby submitting to physical examinations, by supplying all information reasonably required by any insurance carrier andby executing all necessary documents reasonably required by any insurance carrier. Employee shall incur no financialobligation by executing any required document, and shall have no interest in any such policy.24. Compliance with Section 409A.(a) The severance pay and benefits provided under this Agreement are intended to be exempt fromor comply with Section 409A of the Internal Revenue Code (the “Code”), and any ambiguousprovision shall be17 construed in a manner consistent with such intent. For purposes of this Agreement, a“Separation from Service” shall mean Employee’s “separation from service” as such term isdefined in Treasury Regulation Section 1.409A-1(h) or any successor regulation. Each separateseverance payment and each severance installment payment shall be treated as a separatepayment under this Agreement for all purposes. To the extent that Employee is a “specifiedemployee” within the meaning of Section 1.409A-1(i)(1) of the Department of TreasuryRegulations, any amounts that would otherwise be payable by reason of such separation fromservice and are not otherwise exempt from the provisions of Section 409A of the Code willdelayed for a period of six months from the date of such Separation from Service, in which casethe payments that would otherwise have been paid during such six month period shall be paid ina lump sum on the first day of the seventh month after the date of the Separation from Serviceand the remainder of such payments, if any, will be made pursuant to their terms.(b) Notwithstanding anything to the contrary in this Agreement, in-kind benefits andreimbursements provided under this Agreement during any calendar year shall not affect in-kindbenefits or reimbursements to be provided in any other calendar year, other than an arrangementproviding for the reimbursement of medical expenses referred to in Section 105(b) of the Code,and are not subject to liquidation or exchange for another benefit. Notwithstanding anything tothe contrary in this Agreement, reimbursement requests must be timely submitted by Employeeand, if timely submitted, reimbursement payments shall be promptly made to Employeefollowing such submission, but in no event later than December 31st of the calendar yearfollowing the calendar year in which the expense was incurred. In no event shall Employee beentitled to any reimbursement payments after December 31st of the calendar year following thecalendar year in which the expense was incurred. This paragraph shall only apply to in-kindbenefits and reimbursements that would result in taxable compensation income to Employee.(c) If any amount payable hereunder would be subject to additional taxes and interest under Section409A of the Code because the timing of such payment is not delayed as provided in Section409A(a)(2)(B) of the Code, then the payment of such amount shall be delayed and paid, withoutinterest, in a lump sum on the earliest of: (i) Employee’s death, (ii) the date that is six monthsafter the date of Employee’s Separation from Service with the Company (or if such paymentdate does not fall on a business day of Company, the next following business day of theCompany), or (iii) such earlier date upon which such payment can be paid under Section 409Aof the Code without being subject to such additional taxes and interest.[Signature Page Follows] 18 IN WITNESS WHEREOF, Employee and the Company each have caused this Agreement to be executed in itsname and on its behalf, as of the Effective Date. EMPLOYEE: /s/ Sean T. Kimble Sean T. Kimble COMPANY: USA COMPRESSION MANAGEMENT SERVICES,LLC /s/ Matthew C. Liuzzi Matthew C. Liuzzi President SIGNATURE PAGE TOEMPLOYMENT AGREEMENT EXHIBIT AFORM OF RELEASE AGREEMENTThis Release Agreement (this “Agreement”) constitutes the release referred to in that certain EmploymentAgreement (the “Employment Agreement”) dated as of July 1, 2016 by and among Sean T. Kimble (“Employee”)and USA Compression Management Services, LLC (the “Company”).(a) For good and valuable consideration, including the Company's provision of a severancepayment to Employee in accordance with Section 6(f) of the Employment Agreement, Employee herebyreleases, discharges and forever acquits each member of the Company Group and their respective Affiliates(each as defined in the Employment Agreement, provided, however, that for purposes of this Agreement,"Affiliates" shall expressly include Riverstone, the entities Controlling it, and its investment funds, partners ofits investment funds, and its and their portfolio companies other than the Company) and subsidiaries and thepast, present and future stockholders, members, partners, directors, managers, employees, agents, attorneys,heirs, representatives, successors and assigns of the foregoing, in their personal and representative capacities(collectively, the “Company Parties”), from liability for, and hereby waives, any and all claims, damages, orcauses of action of any kind related to Employee's employment with any Company Party, the termination ofsuch employment, and any other acts or omissions related to any matter on or prior to the date of the executionof this Agreement including, without limitation, any alleged violation through the date of this Agreement of: (i)the Age Discrimination in Employment Act of 1967, as amended; (ii) Title VII of the Civil Rights Act of 1964,as amended; (iii) the Civil Rights Act of 1991; (iv) Section 1981 through 1988 of Title 42 of the United StatesCode, as amended; (v) Employee Retirement Income Security Act of 1974, as amended; (vi) the ImmigrationReform Control Act, as amended; (vii) the Americans with Disabilities Act of 1990, as amended; (viii) theNational Labor Relations Act, as amended; (ix) the Occupational Safety and Health Act, as amended; (x) theFamily and Medical Leave Act of 1993; (xi) any state anti-discrimination law; (xii) any state wage and hourlaw; (xiii) any other local, state or federal law, regulation or ordinance; (xiv) any public policy, contract, tort, orcommon law claim; (xv) any allegation for costs, fees, or other expenses including attorneys’ fees incurred inthese matters; (xvi) any and all rights, benefits or claims Employee may have under any employment contract,incentive compensation plan or stock option plan with any Company Party or to any ownership interest in anyCompany Party except as expressly provided in the Employment Agreement and any stock option or otherequity compensation agreement between Employee and the Company and (xvii) any claim for compensation orbenefits of any kind not expressly set forth in the Employment Agreement or any such stock option or otherequity compensation agreement (collectively, the “Released Claims”). In no event shall the Released Claimsinclude (i) any claim which arises after the date of this Agreement, (ii) any claim to vested benefits under anemployee benefit plan, or (iii) any claims for contractual payments under the Employment Agreement. ThisAgreement is not intended to indicate that any such claims exist or that, if they do exist, they are meritorious.Rather,Exhibit A-1  Employee is simply agreeing that, in exchange for the consideration recited in the first sentence of thisparagraph, any and all potential claims of this nature that Employee may have against the Company Parties,regardless of whether they actually exist, are expressly settled, compromised and waived. By signing thisAgreement, Employee is bound by it. Anyone who succeeds to Employee's rights and responsibilities, such asheirs or the executor of Employee's estate, is also bound by this Agreement. This release also applies to anyclaims brought by any person or agency or class action under which Employee may have a right or benefit.Notwithstanding the release of liability contained herein, nothing in this Agreement prevents Employee fromfiling any non-legally waivable claim (including a challenge to the validity of this Agreement) with the EqualEmployment Opportunity Commission (“EEOC”) or comparable state or local agency or participating in anyinvestigation or proceeding conducted by the .EEOC or comparable state or local agency; however, Employeeunderstands and agrees that Employee is waiving any and all rights to recover any monetary or personal reliefor recovery as a result of such EEOC or comparable state or local agency proceeding or subsequent legalactions. THIS RELEASE INCLUDES MATTERS ATTRIBUTABLE TO THE SOLE OR PARTIALNEGLIGENCE (WHETHER GROSS OR SIMPLE) OR OTHER FAULT, INCLUDING STRICTLIABILITY, OF ANY OF THE COMPANY PARTIES.(b) Employee agrees not to bring or join any lawsuit against any of the Company Parties in anycourt relating to any of the Released Claims. Employee represents that Employee has not brought or joined anylawsuit or filed any charge or claim against any of the Company Parties in any court or before any governmentagency and has made no assignment of any rights Employee has asserted or may have against any of theCompany Parties to any person or entity, in each case, with respect to any Released Claims.(c) By executing and delivering this Agreement, Employee acknowledgesthat:(i) He has carefully read this Agreement;(ii) He has had at least [21] [45] days to consider this Agreement before theexecution and delivery hereof to the Company. [Add if 45 days applies: , andhe acknowledges that attached to this Agreement are (A) a list of thepositions and ages of those employees selected for termination (orparticipation in the exit incentive or other employment terminationprogram); (B) a list of the ages of those employees not selected fortermination (or participation in such program); and (C) information aboutthe unit affected by the employment termination program of which histermination was a part, including any eligibility factors for such programand any time limits applicable to such program];Exhibit A-2 (iii) He has been and hereby is advised in writing that he may, at his option, discussthis Agreement with an attorney of his choice and that he has had adequateopportunity to do so;(iv) He fully understands the final and binding effect of this Agreement; the onlypromises made to him to sign this Agreement are those stated in the EmploymentAgreement and herein; and he is signing this Agreement voluntarily and of hisown free will, and that he understands and agrees to each of the terms of thisAgreement; and(v) With the exception of any sums that he may be owed pursuant to Section 6(f) ofthe Employment Agreement, he has been paid all wages and other compensationto which he is entitled under the Agreement and received all leaves (paid andunpaid) to which he was entitled during the Employment Period (as defined inthe Employment Agreement).Notwithstanding the initial effectiveness of this Agreement, Employee may revoke the delivery (and thereforethe effectiveness) of this Agreement within the seven-day period beginning on the date Employee delivers thisAgreement to the Company (such seven day period being referenced to herein as the “Release Revocation Period”).To be effective, such revocation must be in writing signed by Employee and must be delivered to [name, address]before 11:59 p.m., Austin, Texas time, on the last day of the Release Revocation Period. If an effective revocation isdelivered in the foregoing manner and timeframe, this Agreement shall be of no force or effect and shall be null andvoid ab initio. No consideration shall be paid if this Agreement is revoked by Employee in the foregoing manner.Executed on this _______ day of __________________, 201_. Sean T. Kimble Exhibit A-3Exhibit 10.21 USA COMPRESSION PARTNERS, LP AMENDED AND RESTATED ANNUAL CASH INCENTIVE PLAN 1. Purpose. The purpose of this Plan is to motivate management personnel (at or above director level) plus otherselected key salaried personnel who perform services for the Partnership and/or its affiliates and subsidiaries toearn annual cash awards through the achievement of performance and target goals. 2. Definitions. As used in this Plan, the following terms shall have the meanings herein specified: 2.1 Actual Results means the amount of Adjusted EBITDA, Distributable Cash Flow, Leverage Ratio, SafetyTarget or other applicable measure specified for the Budget Target(s) for a Plan Year actually achieved forsuch Plan Year as determined by the Partnership following the end of such Plan Year. 2.2 Adjusted EBITDA means the definition of Adjusted EBITDA as provided in the Partnership’s AnnualReport on Form 10-K for the Plan Year. 2.3 Annual Bonus means the cash bonus paid to an Eligible Employee for the Plan Year. 2.4 Annual Target Bonus means, for an Eligible Employee, a percentage of such Eligible Employee’s EligibleEarnings, and shall be dependent on a number of factors which may include but are not limited to anemployee’s position title, job responsibilities, and reporting level within the Company. For each EligibleEmployee who also maintains an employment agreement with the Company (or its subsidiary), their AnnualTarget Bonus will be governed both by the Plan and their respective employment agreement. 2.5 Annual Target Bonus Pool means, for a Plan Year, the Annual Target Bonus of the Eligible Employees ofthe Company, collectively, for that Plan Year. 2.6 Board means the Board of Directors of the Company. 2.7 Bonus Pool Payout Factor means the multiplier factor applied to the Annual Target Bonus Pool todetermine the Funded Bonus Pool for the applicable Plan Year. The payout is determined by the comparisonof the Budget Target(s) for the Plan Year to Actual Results. General guidelines for the Budget Target and theBonus Pool Payout Factor associated with such Budget Target for a Plan Year are set forth below, but eachare subject to the sole discretion of the Compensation Committee. The Bonus Pool Payout Factor forpurposes of the Plan shall be adjusted each Plan Year based on the specific allocation of Annual TargetBonus Pools to each of the specified Budget Target(s). Such allocations of each Budget Target to the totalAnnual Bonus Pool shall be determined on an annual basis by the Compensation Committee. The AdjustedEBITDA Budget Target shall comprise 30% of the total Annual Target Bonus Pool, the Distributable CashFlow Budget Target shall comprise 30% of the total Annual Target Bonus Pool, the Leverage Ratio BudgetTarget shall comprise 30% of the total Annual Target Bonus Pool, the Safety Target shall comprise theremaining 10% of the total Annual Target Bonus Pool. While the Funded Bonus Pool will reflect anaggregation of performance under each Bonus Pool Payout Factor the performance of Adjusted EBITDABudget Target shall drive calculation of the Bonus Pool, as no other targets shall be considered unless theAdjusted EBITDA Budget Target results is at least 80% of its Budget Target. Adjusted EBITDA Budget Target Payout Factor Guidelines - 30% % of Budget TargetBonus Pool Payout Factor>=110.01.20x109.9 – 105.01.10x104.9 – 95.01.00x94.9 – 90.0.90x89.9 – 80.0.75x< 80.0.0x 2 Distributable Cash Flow Budget Target Payout Factor Guidelines – 30% % of Budget TargetBonus Pool Payout Factor>=110.01.20x109.9 – 105.01.10x104.9 – 95.01.00x94.9 – 90.0.90x89.9 – 80.0.75x< 80.0.0x Leverage Ratio Budget Target Payout Factor Guidelines – 30% Range within Budget TargetBonus Pool Payout FactorMore than 0.250 below Budget Target1.20x0.250 – 0.125 below1.10x0.124 below – 0.125 above1.00x0.126 – 0.375 above.70x0.376 – 0.500 above.50x>0.500 above.0x Safety Budget Target Payout Factor Guidelines – 10% % of TargetBonus Pool Payout Factor<100%1.00x100% - 105%.90x105.1% - 110%.80x110.1% - 115%.70x115.1% - 125%.60x>125%.0x3 2.8 Budget Target means the specific amount of Adjusted EBITDA, Distributable Cash Flow, Leverage Ratio,Safety Target and/or other measure(s) established by the Compensation Committee for the Company for aPlan Year. 2.9 Company means USA Compression GP, LLC, a Delaware limited liability company. The term “Company”shall include any successor to USA Compression GP, LLC, any subsidiary of USA Compression GP, LLC,or affiliate thereof that has adopted the Plan, or any entity succeeding to the business of USA CompressionGP, LLC, or any subsidiary or affiliate, by merger, consolidation, liquidation, or purchase of assets orequity, or similar transaction. 2.10 Compensation Committee means the Compensation Committee of the Company’s Board. 2.11 Distributable Cash Flow means the definition of Distributable Cash Flow as provided in the Partnership’sAnnual Report on Form 10-K for the Plan Year. 2.12 Eligible Earnings means the aggregate regular earnings received by an Eligible Employee during the PlanYear. For the avoidance of doubt, neither distribution payments or distribution equivalent payments on anyPartnership phantom or common units nor any other bonus or sign-on payments received by an EligibleEmployee during the Plan Year shall be included in the calculation of Eligible Earnings for an EligibleEmployee. 2.13 Eligible Employee has the meaning set forth in Section 4 below. 2.14 Funded Bonus Pool means the Annual Target Bonus Pool for a Plan Year multiplied by the applicableBonus Pool Payout Factor for such Plan Year. The establishment and amount of a Funded Bonus Pool is100% discretionary and subject to the final approval of and/or adjustment by the Compensation Committee. 2.15 Leverage Ratio has the meaning assigned to such term in the Partnership’s revolving credit facility as ofthe first day of any given Plan Year; provided, that, for the purposes of calculating the Leverage Ratio forthis Plan, EBITDA, as defined in the Partnership’s revolving credit facility, attributable to the full Plan Yearshall be used in lieu of any other time period.4  2.16 Partnership means USA Compression Partners, LP, a Delaware master limited partnership. 2.17 Person means an individual, corporation, limited liability company, partnership, joint venture, trust,unincorporated organization, association, government agency or political subdivision thereof or other entity. 2.18 Plan means the Partnership’s Amended and Restated Annual Bonus Plan as set forth herein, as the samemay be amended from time to time. 2.19 Plan Year means the performance (calendar) year for the measurement and determination of the BudgetTarget and the calculation of Actual Results. Unless otherwise determined by the Compensation Committee,each Plan Year shall be the one year period commencing on January 1 and ending on December 31 of thecalendar year. 2.20 Safety Target means the Total Incident Recordable Rate (TRIR) as calculated by the U.S. OccupationalSafety and Health Administration for the Plan Year. 3. Plan Guidelines and Administration. The administration of the Plan and any potential Annual Bonus awardedpursuant to the Plan are subject to the sole determination and discretion of the Compensation Committee. TheCompensation Committee will review the Partnership’s performance results for the designated Plan Year, theBudget Target and Bonus Pool Payout Factor for each Plan Year and thereafter will determine, in consultationwith the Company’s Chief Executive Officer, whether or not and to what extent to approve the Funded BonusPool under the Plan. The Compensation Committee may delegate the responsibility for the administration and operation of the Planto the Chief Executive Officer of the Company or his/her designee(s). The Compensation Committee or theperson(s) to which administrative authority has been delegated (the Committee or such person referred to as the“Plan Administrator”) shall have the authority to interpret and construe any and all provisions of the Plan,including the establishment for any designated Plan Year or from time to time any Budget Targets, BudgetTarget guidelines, Bonus Pool Payout Factors and/or such other economic or performance factors as the PlanAdministrator shall determine and whether and to what extent any such targets, guidelines or factors has beenachieved. Any determination made by the Plan Administrator shall be final and conclusive and binding on allpersons.5 4. Eligible Employees. Subject to the discretion of the Compensation Committee and such other criteria as may beestablished by the Compensation Committee in general or for a particular Plan Year, management personnel (ator above director level) plus other selected key salaried personnel of the Company providing services to thePartnership and its subsidiaries are eligible to participate in the Annual Target Bonus Pool for a Plan Year. NoEligible Employee shall be entitled to receive an Annual Bonus for a Plan Year unless he or she is activelyemployed by the Company on the date the Annual Bonus for such Plan Year is paid by the Company even ifsuch payment date is after the Plan Year. Notwithstanding the foregoing, in the event of an Eligible Employee’s Disability (as such term is defined by thePartnership’s 2013 Long-Term Incentive Plan, as amended) or death after the completion of a Plan Year butprior to the payment of the Annual Bonus, such Eligible Employee or his/her estate, as applicable shall beeligible to receive such Eligible Employee’s Annual Bonus. Additionally, in a situation where an EligibleEmployee is displaced as a result of a transaction and such transaction closes on or after December 31 of thePlan Year but prior to payment of the Annual Bonus, such Eligible Employee will be able to receive a bonusaward even though he/she is not employed on the date of payment of the Annual Bonus. Employees of Energy Transfer LP and its subsidiaries (other than the Company, the Partnership and theirrespective subsidiaries) and Sunoco GP LLC and its subsidiaries shall participate in the Amended and RestatedEnergy Transfer LP Annual Bonus Plan and the Sunoco GP LLC Annual Cash Incentive Plan, respectively andshall not be eligible to participate under this Plan. 5. Annual Bonus Payments for Eligible Employees. As soon as reasonably practicable following the end of thePlan Year, management of the Company will determine the Annual Target Bonus for each Eligible Employee.The Funded Bonus Pool from which Annual Bonuses are paid to Eligible Employees shall equal (a) theaggregate of the Annual Target Bonuses of all Eligible Employees multiplied by (b) the Bonus Pool PayoutFactor for such Plan Year, as determined by the Compensation Committee after review of the performanceresults for the Plan year. The amount of the Annual Bonus for an Eligible Employee from the Funded BonusPool shall be determined in management’s sole discretion and shall be based on a number of factors includingan employee’s performance, length of employment and such other factors as may be determined bymanagement in its sole discretion, which factors may not be the same for all Eligible Employees.Notwithstanding the foregoing, the Compensation Committee shall make determination of the Annual Bonus ofall of the Company’s named executive officers and such other executive officers as may be determined fromtime to time. The Annual Bonus, if any, shall be paid within one week following delivery by the Partnership’sindependent auditor of the audit of the Partnership’s financial statements for the Plan Year in which the AnnualBonus relates, but in no case later than March 15 of the year following the Plan Year in which the AnnualBonus relates. In no event, shall the aggregate amount of the Annual Bonus payments for the Plan Year exceed, in total, theFunded Bonus Pool for such Plan Year. Notwithstanding any6 provision herein, funds allocated under this Plan for distribution to Eligible Employees is 100% discretionary. 6. Amendment and Termination. The Compensation Committee, at its sole discretion, may, without prior noticeto or consent of any Eligible Employees, amend the Plan or terminate the Plan at any time and at all times. 7. Indemnification. Neither the Company, any participating affiliate, nor the Board, or the CompensationCommittee, of the Company or any participating affiliate, nor any officer or employee of the Company or anyparticipating affiliate shall be liable for any act, omission, interpretation, construction or determination made inconnection with the Plan in good faith; and the members of the Company’s Board, the CompensationCommittee and/or management of the Company shall be entitled to indemnification and reimbursement by theCompany to the maximum extent permitted by law in respect of any claim, loss, damage or expense (includingcounsel’s fees) arising from their acts, omission and conduct in their official capacity with respect to the Plan. 8. General provisions. 8.1 Non-Guarantee of Employment or Participation in the Plan. Nothing contained in this Plan shall beconstrued as a contract of employment between the Company, the Partnership and/or any of its affiliates andany employee of the Company or any of its affiliates, and nothing in this Plan shall confer upon anyemployee, including an Eligible Employee, any right to continued employment with the Company and/or itsaffiliate, or interfere with the right of the Company, the Partnership and/or its affiliate to terminate theemployment, with or without cause, of an employee, including an Eligible Employee. Nothing in this Planshall give any employee any right to participate in the Plan and/or to receive an Annual Bonus with respectto any Plan Year. Notwithstanding the foregoing, for each Eligible Employee who also maintains anemployment agreement with the Company (or its subsidiary), their Annual Target Bonus and participation inthe Plan will be governed both by the Plan and their respective employment agreement. 8.2 Interests Not Transferable. No right, interest or benefit under the Plan shall be subject in any manner toalienation, sale, transfer, assignment, pledge, attachment or other legal process, or encumbrance of anykind, and any attempt to do so shall be void. 8.3 Controlling Law. To the extent not superseded by federal law, the law of the State of Texas, without regardto the conflicts of laws provisions thereunder, shall be controlling in all matters relating to the Plan.7 8.4 Severability. If any Plan provision or any Annual Bonus award hereunder is or becomes or is deemed to beinvalid, illegal, or unenforceable in any jurisdiction or as to any person or award, or would disqualify thePlan or any award under the law deemed applicable by the Compensation Committee, such provision shallbe construed or deemed amended to conform to the applicable laws, or if it cannot be construed or deemedamended without, in the determination of the Compensation Committee, materially altering the intent of thePlan or the award, such provision shall be stricken as to such jurisdiction, person or award and theremainder of the Plan and any such award shall remain in full force and effect. 8.5 No Trust or Fund Created. Neither the Plan nor any award shall create or be construed to create a trust orseparate fund of any kind or a fiduciary relationship between the Company and its affiliates and anemployee, including an Eligible Employee or any other person. The Plan shall constitute an unfundedmechanism for the Company to pay bonus compensation to participants from its general assets. Noparticipant shall have any security or other interest in the assets of the Company. 8.6 Headings. Headings are given to the sections of the Plan solely as a convenience to facilitate reference.Such headings shall not be deemed in any way material or relevant to the construction or interpretation ofthe Plan or any provision of it. 8.7 Tax Withholding. The Company and/or any participating affiliate will deduct from any payment otherwisedue under this Plan to a Participant (or beneficiary) amounts required by law to be withheld for purposes offederal, state or local taxes. 8.8 Off-set. The Company reserves the right to withhold any or all portions of an award or to reduce an awardto a participant up to an amount equal to any amount the participant owes to the Company or any of itsaffiliates. 8.9 Effective Date. This Plan is effective for the Plan Year commencing on January 1, 2019. 8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 CDM Resource Management LLC, a Delaware limited liability company CDM Environmental & Technical Services LLC, a Delaware limited liability company Exhibit 23.1 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We have issued our reports dated February 19, 2019, with respect to the consolidated financial statements andinternal control over financial reporting included in the Annual Report of USA Compression Partners, LP on Form10-K for the year ended December 31, 2018. We consent to the incorporation by reference of said reports in theRegistration Statements of USA Compression Partners, LP on Forms S-3 (File No. 333-228361, File No. 333-217391, and File No. 333-211167) and on Forms S-8 (File No. 333-228362 and File No. 333-187166). /s/ GRANT THORNTON LLP Houston, TexasFebruary 19, 2019 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 amaterial fact necessary to make the statements 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, fairlypresent in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, theperiods presented in this report; 4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controlsand procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (asdefined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to bedesigned under our supervision, to ensure that material information relating to the registrant, including itsconsolidated subsidiaries, is made known to us by others within those entities, particularly during the period inwhich this report is being prepared; b)designed such internal control over financial reporting, or caused such internal control over financial reportingto be designed under our supervision, to provide reasonable assurance regarding the reliability of financialreporting and the preparation of financial statements for external purposes in accordance with generallyaccepted accounting principles; c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this reportour conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the periodcovered 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 occurredduring the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annualreport) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal controlover financial reporting; and 5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internalcontrol over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (orpersons performing the equivalent functions): a)all significant deficiencies and material weaknesses in the design or operation of internal control over financialreporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarizeand report financial information; and b)any fraud, whether or not material, that involves management or other employees who have a significant role inthe registrant’s internal control over financial reporting. /s/ Eric D. Long Name:Eric D. Long Title:President and Chief Executive Officer Dated: February 19, 2019Exhibit 31.2 CERTIFICATION I, Matthew C. Liuzzi, 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 amaterial fact necessary to make the statements 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, fairlypresent in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, theperiods presented in this report; 4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controlsand procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (asdefined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to bedesigned under our supervision, to ensure that material information relating to the registrant, including itsconsolidated subsidiaries, is made known to us by others within those entities, particularly during the period inwhich this report is being prepared; b)designed such internal control over financial reporting, or caused such internal control over financial reportingto be designed under our supervision, to provide reasonable assurance regarding the reliability of financialreporting and the preparation of financial statements for external purposes in accordance with generallyaccepted accounting principles; c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this reportour conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the periodcovered 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 occurredduring the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annualreport) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal controlover financial reporting; and 5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internalcontrol over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (orpersons performing the equivalent functions): a)all significant deficiencies and material weaknesses in the design or operation of internal control over financialreporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarizeand report financial information; and b)any fraud, whether or not material, that involves management or other employees who have a significant role inthe registrant’s internal control over financial reporting. /s/ Matthew C. Liuzzi Name:Matthew C. Liuzzi Title:Vice President, Chief Financial Officer and Treasurer Dated: February 19, 2019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 yearended December 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Eric D.Long, as President and Chief Executive Officer 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 of1934; and (2) the information contained in the Report fairly presents, in all material respects, the financial condition andresults of operations of the Partnership. /s/ Eric D. Long Eric D. Long President and Chief Executive Officer Dated: February 19, 2019 A signed original of this written statement required by Section 906, or other document authenticating, acknowledging,or otherwise adopting the signature that appears in typed form within the electronic version of this written statement requiredby Section 906, has been provided to the Partnership and will be retained by the Partnership and furnished to the Securitiesand 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 yearended December 31, 2018 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), MatthewC. Liuzzi, as Vice President, Chief Financial Officer and Treasurer of 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, tohis knowledge: (1) the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of1934; and (2) the information contained in the Report fairly presents, in all material respects, the financial condition andresults of operations of the Partnership. /s/ Matthew C. Liuzzi Matthew C. Liuzzi Vice President, Chief Financial Officer and Treasurer Dated: February 19, 2019 A signed original of this written statement required by Section 906, or other document authenticating, acknowledging,or otherwise adopting the signature that appears in typed form within the electronic version of this written statement requiredby Section 906, has been provided to the Partnership and will be retained by the Partnership and furnished to the Securitiesand Exchange Commission or its staff upon request. Exhibit 99.1 Unaudited Pro Forma Condensed Consolidated Financial Statements Introduction The Unaudited Pro Forma Condensed Consolidated Financial Statements (the “pro forma financial statements”)combine the historical consolidated financial statements of CDM Resource Management LLC and CDM Environmental& Technical Services LLC (collectively, “CDM”), the accounting acquirer of USA Compression Partners, LP (the“Partnership”), and the historical consolidated financial statements of the Partnership, the acquired entity, to illustratethe effect of the Transactions described below. The following pro forma financial statements were based on, and should be read in conjunction with, (i) theaccompanying notes to the Unaudited Pro Forma Condensed Consolidated Financial Statements, (ii) the auditedhistorical consolidated financial statements and related notes thereto of the Partnership, included in its AnnualReport on Form 10-K for the year ended December 31, 2018 and (iii) the unaudited historical condensed consolidatedfinancial statements and related notes thereto of the Partnership, included in its quarterly report on Form 10-Q for thethree months ended March 31, 2018. The historical consolidated financial statements have been adjusted in the pro forma financial statements to giveeffect to pro forma events that are (a) directly attributable to the transactions described below, (b) factually supportableand (c) expected to have a continuing impact on the combined results. The Unaudited Pro Forma CondensedConsolidated Statement of Operations (the “pro forma statement of operations”) for the year ended December 31, 2018,gives effect to the transactions described below as if they occurred on January 1, 2018. The pro forma statement ofoperations for the year ended December 31, 2018 includes (i) the audited historical consolidated statement of operationsof the Partnership for the year ended December 31, 2018, which includes the results of operations for CDM for the threemonths ended March 31, 2018 and the results of the combined businesses for the nine months ended December 31,2018, (ii) the historical unaudited condensed consolidated statement of operations for USA Compression Partners, LP forthe three months ended March 31, 2018, which reflects the results of operations prior to the Transactions describedbelow, and (iii) the pro forma adjustments described in Note 1. The Unaudited Condensed Consolidated Balance Sheetas of December 31, 2018 is not presented since the transactions are reflected in the Partnership’s historical balance sheetas of December 31, 2018 and no pro forma adjustments for the Transactions are required. The pro forma financial statements have been prepared under the rules and regulations of the Securities andExchange Commission. The pro forma financial statements have been presented for informational purposes only and arebased upon available information and certain assumptions that the Partnership’s management believes are reasonableunder the circumstances. These pro forma financial statements are not necessarily indicative of what the combinedentity’s results of operations would have been had the Transactions been completed on the date indicated. We haveincurred and expect to incur additional costs to integrate CDM and the Partnership’s businesses. The pro forma financialstatements do not reflect the cost of any integration activities or benefits that may result from synergies related to theTransactions that may be derived from any integration activities. In addition, the pro forma financial statements do notpurport to project the future results of operations of the combined entity. Description of the Transactions General Partner Purchase Agreement On April 2, 2018 (the “Transactions Date”), and in connection with the closing of the CDM Acquisition discussedbelow, the transactions contemplated by the Purchase Agreement dated January 15, 2018, by and among EnergyTransfer Equity, L.P. (“ETE”), Energy Transfer Partners, L.L.C., USA Compression Holdings, LLC (“USA CompressionHoldings”) and, solely for certain purposes therein, R/C IV USACP Holdings, L.P. and Energy Transfer Partners, L.P.(“ETP”) were consummated, pursuant to which, among other things, ETE acquired from USA Compression Holdings(i) all of the outstanding limited liability company interests in the Partnership’s general partner and (ii) 12,466,912common units representing limited partner interests in the Partnership (the “common units”) for cash consideration paidby ETE to USA Compression Holdings equal to $250.0 million (the “GP Purchase”). In October 2018, ETE and ETP completed the merger of ETP with a wholly owned subsidiary of ETE in a unit-for-unit exchange (the “ETE Merger”). Following the closing of the ETE Merger, ETE changed its name to “EnergyTransfer LP” and ETP changed its name to “Energy Transfer Operating, L.P.” Upon the closing of the ETE Merger, ETEcontributed to ETP 100% of the limited liability company interests in the General Partner. Equity Restructuring Agreement On the Transactions Date, and in connection with the closing of the CDM Acquisition discussed below, weconsummated the transactions contemplated by the Equity Restructuring Agreement dated January 15, 2018, pursuantto which, among other things, the Partnership, USA Compression GP, LLC (the “General Partner”) and ETE agreed tocancel the Partnership’s Incentive Distribution Rights (“IDRs”) and convert the General Partner Interest (as defined inthe Equity Restructuring Agreement) into a non-economic general partner interest, in exchange for the Partnership’sissuance of 8,000,000 common units to the General Partner (the “Equity Restructuring”). CDM Acquisition On the Transactions Date, the Partnership consummated the transactions contemplated by the ContributionAgreement dated January 15, 2018, pursuant to which, among other things, the Partnership acquired all of the issued andoutstanding membership interests of CDM from ETP (the “CDM Acquisition”), in exchange for aggregate considerationof approximately $1.7 billion, consisting of (i) 19,191,351 common units, (ii) 6,397,965 Class B units representinglimited partner interests in us (“Class B Units”) and (iii) $1.2 billion in cash (including customary closing adjustments). The GP Purchase, Equity Restructuring and CDM Acquisition are collectively referred to as the “Transactions.” Senior Notes On March 23, 2018, to finance a portion of the cash purchase price for the CDM Acquisition, the Partnership andUSA Compression Finance Corp. co-issued $725.0 million aggregate principal amount of senior notes that mature onApril 1, 2026. The notes accrue interest from March 23, 2018 at the rate of 6.875% per year. Interest on the notes ispayable semi-annually in arrears on April 1 and October 1, with the first such payment having occurred on October 1,2018. Preferred Units and Warrants On the Transactions Date, to finance a portion of the cash purchase price for the CDM Acquisition, thePartnership consummated the transactions contemplated by the Series A Preferred Unit and Warrant Purchase Agreement(the “Purchase Agreement”), dated January 15, 2018, between the Partnership and certain investment funds managed orsub-advised by EIG Global Energy Partners (“EIG”) and FS Energy and Power Fund (collectively, the “Purchasers”),whereby the Partnership issued and sold in a private placement (i) $500.0 million in the aggregate of newly authorizedand established Series A Preferred Units representing limited partner interests in the Partnership (the “Preferred Units”) and (ii) two tranches of warrants to purchase our common units (collectively, the“Warrants”). Pursuant to the terms of the Purchase Agreement, on the Transactions Date, the Partnership issued (i)500,000 Preferred Units to the Purchasers at a price of $1,000 per Preferred Unit, (ii) Warrants to purchase 5,000,000common units with a strike price of $17.03 per unit and (iii) Warrants to purchase 10,000,000 common units with astrike price of $19.59 per unit. The Warrants may be exercised by the holders thereof at any time beginning on the oneyear anniversary of the Transactions Date and before the tenth anniversary of the Transactions Date. Upon exercise ofthe Warrants, we may, at our option, elect to settle the Warrants in common units on a net basis. Revolving Credit Facility On the Transactions Date, the Partnership entered into the Sixth Amended and Restated Credit Agreement (the“Credit Agreement”). The Credit Agreement, among other things, (a) increased the borrowing capacity under the CreditAgreement from $1.1 billion to $1.6 billion, (b) extended the termination date (and the maturity date of the obligationsthereunder) from January 6, 2020 to April 2, 2023, (c) subject to the terms in the Credit Agreement, permits up to $400.0million of future increases in borrowing capacity and (d) made certain changes to the covenants under the CreditAgreement. Accounting Acquirer CDM is deemed to be the accounting acquirer of the Partnership in the business combination because its ultimateparent company obtained control of the Partnership through its acquisition of the limited liability company interests inthe General Partner. Consequently, CDM is the predecessor of the Partnership for financial reporting purposes and thehistorical consolidated financial statements of the Partnership relating to periods prior to the Transactions Date, but filedsubsequently reflect those of CDM, as the accounting acquirer. CDM’s assets and liabilities retained their historicalcarrying values. The Partnership’s assets acquired and liabilities assumed by CDM have been recorded at their fairvalues measured as of the Transactions Date. The excess of the assumed purchase price of the Partnership over theestimated fair values of the Partnership’s net assets acquired has been recorded as goodwill. The assumed purchase priceand fair value of the Partnership was determined using a combination of an income and cost valuation methodology, thefair value of the Partnership’s common units as of the Transactions Date and the consideration paid by ETE for thelimited liability company interests in the General Partner and IDRs. The valuation and purchase price allocation isconsidered final. USA Compression Partners, LPPro Forma Condensed Consolidated Statement of OperationsYear ended December 31, 2018(unaudited, in thousands) USA Compression USACompression Partners, LP Partners, LP Pro Forma Historical Historical Three Combined Year Ended Months Ended Pro Forma Year Ended December 31, 2018 March 31, 2018 Adjustments December 31, 2018Revenues: Contract operations $546,896 $76,716 $ — $623,612Parts and service 20,402 1,023 — 21,425Related party revenues 17,054 — — 17,054Total revenues 584,352 77,739 — 662,091Costs and expenses: Cost of operations, exclusive of depreciation andamortization 214,724 25,543 (310)(a) 239,957Selling, general and administrative 68,995 33,495 (36,626)(b) 65,864Depreciation and amortization 213,692 25,112 2,664(c) 241,468Loss (gain) on sale of assets 12,964 (324) — 12,640Impairment of compression equipment 8,666 — — 8,666Total costs and expenses 519,041 83,826 (34,272) 568,595Operating income (loss) 65,311 (6,087) 34,272 93,496Other income (expense): Interest expense, net (78,377) (9,219) (15,069)(d) (102,665)Other 41 6 — 47Total other expense (78,336) (9,213) (15,069) (102,618)Net income (loss) before income tax expense(benefit) (13,025) (15,300) 19,203 (9,122)Income tax expense (benefit) (2,474) 70 — (2,404)Net income (loss) (10,551) (15,370) 19,203 (6,718)Less: Preferred unit distributions (36,430) — (12,320)(e) (48,750)Net income (loss) attributable to Common andClass B unitholders' interests $(46,981) $(15,370) $6,883 $(55,468) Net income (loss) allocated to: General partner’s interest in net income $ — $(773) $773(f) $ —Limited partners’ interest in net income (loss): Common units $(32,053) $(14,597) $10,781(g) $(35,869)Class B Units $(14,928) $ — $(4,671)(g) $(19,599) Weighted average common units outstanding -basic and diluted 74,481 62,264 — 74,481 Weighted average Class B Units outstanding -basic and diluted 6,398 — — 6,398 Basic and diluted net loss per common unit $(0.43) $(0.23) $(0.48) Basic and diluted net loss per Class B Unit $(2.33) $ — $(3.06) Distributions declared per common unit $1.575 $0.525 $2.100 USA Compression Partners, LPNotes to Pro Forma Condensed Consolidated Financial Statements(unaudited) Note 1:Adjustments to the Unaudited Pro Forma Condensed Consolidated Statement of Operations a.Reflects adjustment to remove $0.3 million of severance charges representing operating expenses that arehistorical direct and incremental transaction expenses related to the CDM Acquisition. b.Reflects adjustment to remove historical direct and incremental transaction expenses related to the CDMAcquisition. These transaction expenses include: (i) $3.9 million of severance charges, (ii) $6.8 million for non-cash unit-based compensation expenses for the change in control of the General Partner which resulted inimmediate vesting of outstanding time and performance based phantom units granted to certain employees and(iii) $25.9 million of legal, accounting and other fees. c.Adjustments to depreciation and amortization resulting from the adjustment of the Partnership's assets andliabilities to their estimated fair values. Under the acquisition method of accounting, the tangible and intangibleassets acquired and liabilities assumed are recorded at their estimated fair values. d.Reflects the estimated interest expense associated with the debt incurred to fund the CDM Acquisition and thefees and expenses related to the Transactions. Debt incurred to finance the CDM Acquisition consists of(i) $707.8 million aggregate principal amount of senior notes, net of related debt issuance costs, and(ii) $83.3 million of borrowings under the Credit Agreement. To the extent the actual interest rates are higherthan estimated, additional interest expense will be incurred and such expense could be material. A 0.125%increase in the interest rate associated with the Credit Agreement would increase interest expense $0.3 millionfor the year ended December 31, 2018. Incremental Interest Expense(in thousands) Year Ended December 31,2018Cash interest (i) $13,225Amortization of debt issuance costs 1,844Total incremental interest expense $15,069 (i)Cash interest expense was calculated using a 3.67% annual average interest rate on the Credit Agreement and 6.875% annualinterest rate on the senior notes. e.Reflects the pro forma distribution associated with the 500,000 Preferred Units. The Preferred Units have a facevalue of $1,000 per Preferred Unit and accrue distributions at a rate of 9.75% per annum, or $48.8 million peryear. The distributions are payable quarterly. f.Reflects the conversion of the general partner interest into a non-economic general partner interest in connectionwith the Equity Restructuring. g.Reflects allocation of USA Compression Partners, LP net loss for the three months ended March 31, 2018 and thepro forma adjustments to the common units and Class B Units discussed above.

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