USA Compression Partners
Annual Report 2017

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, 2017 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 and posted on its corporate Web site, if any, every Interactive Data File required to besubmitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit andpost 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 ☐(Do not check if a 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 (treating directors and executive officers of the registrant’s general partnerand holders of 5% or more of the common units outstanding, for this purpose, as if they were affiliates of the registrant) as of June 30, 2017, the last business day ofthe registrant’s most recently completed second fiscal quarter was $369,969,262. This calculation does not reflect a determination that such persons are affiliates forany other purpose. As of February 8, 2018, there were 62,194,405 common units outstanding. DOCUMENTS INCORPORATED BY REFERENCE: NONE Table of ContentsTable of Contents PART I 1 Item 1.Business2 Item 1A.Risk Factors15 Item 1B.Unresolved Staff Comments38 Item 2.Properties38 Item 3.Legal Proceedings38 Item 4.Mine Safety Disclosures39 PART II 39 Item 5.Market For Registrant’s Common Equity, Related Stockholder Matters and IssuerPurchases of Equity Securities39 Item 6.Selected Financial Data40 Item 7.Management’s Discussion and Analysis of Financial Condition and Results ofOperations48 Item 7A.Quantitative and Qualitative Disclosures About Market Risk63 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 Information65 PART III 66 Item 10.Directors, Executive Officers and Corporate Governance66 Item 11.Executive Compensation72 Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters81 Item 13.Certain Relationships and Related Transactions, and Director Independence83 Item 14.Principal Accountant Fees and Services86 PART IV 87 Item 15.Exhibits and Financial Statement Schedules87 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” orsimilar words or the negative 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 gasindustry 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; ·the effects of future litigation; and ·the failure to consummate the CDM Acquisition. 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. 1 Table of Contents ITEM 1.Business References in this report to “USA Compression,” “we,” “our,” “us,” “the Partnership” or like terms refer to USACompression Partners, LP and its wholly owned subsidiaries, including USA Compression Partners, LLC (“USACOperating”) and USAC OpCo 2, LLC (“OpCo 2” and, together with USAC Operating, the “Operating Subsidiaries”).References to our “general partner” refer to USA Compression GP, LLC. References to “USA Compression Holdings” referto USA Compression Holdings, LLC, the owner of our general partner. References to “USAC Management” refer to USACompression Management Services, LLC, a wholly owned subsidiary of our general partner. References to “Riverstone”refer to Riverstone/Carlyle Global Energy and Power Fund IV, L.P., and affiliated entities, including Riverstone Holdings,LLC. 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. We have beenproviding compression services since 1998 and completed our initial public offering in January 2013. As of December 31,2017, we had 1,799,781 horsepower in our fleet and 153,020 horsepower on order for expected delivery during 2018 and2019. We provide compression services to our customers primarily in connection with infrastructure applications, includingboth allowing for the processing and transportation of natural gas through the domestic pipeline system and enhancing crudeoil production through artificial lift processes. As such, our compression services play a critical role in the production,processing and transportation of both natural 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. The demand for our services is driven by the domestic production of natural gas and crude oil; as such,we have focused our activities in areas with attractive natural gas and crude oil production growth, which are generally foundin these 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, thus reducing the hydrostatic pressure and allowing the oil to flowat a higher rate, and other artificial lift technologies are critical to the enhancement of production of oil 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 the redeployment risk of our horsepowerin the field. Our modern and standardized fleet, decentralized field level operating structure and technical proficiency inpredictive and preventive maintenance and overhaul operations have enabled us to achieve average service run timesconsistently at or above the levels required by our customers. 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.2 Table of Contents 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 help generate themaximum throughput of product, reduce fuel costs and minimize emissions. While we are currently focused on our existingservice areas, our customers may have compression demands in other areas of the U.S. in conjunction with their fielddevelopment projects. We continually consider expansion of our 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. 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 DevelopmentsOn January 15, 2018, we entered into a Contribution Agreement (the “Contribution Agreement”) with Energy TransferPartners, L.P. (“ETP”), Energy Transfer Partners GP, L.P., the general partner of ETP (“ETP GP”), ETC Compression, LLC(“ETC” and, together with ETP and ETP GP, the “Contributors”) and, solely for certain purposes therein, Energy TransferEquity, L.P. (“ETE” and together with ETP, the “Energy Transfer Parties”), pursuant to which, among other things, ETP willcontribute to us, and we will acquire from ETP, all of the issued and outstanding membership interests of CDM ResourceManagement LLC (“CDM Management”) and CDM Environmental & Technical Services LLC (“CDM E&T” and, togetherwith CDM Management, “CDM”) for aggregate consideration of approximately $1.7 billion consisting of units representinglimited partner interests in the Partnership and an amount in cash equal to $1.225 billion, subject to certain adjustments (the“CDM Acquisition”).The CDM Acquisition is expected to close in the first half of 2018, subject to customary closing conditions, including(i) the concurrent closing of the GP Purchase (as defined below), and (ii) the transactions contemplated by the EquityRestructuring Agreement (as defined below), including the Restructuring (as defined below), shall be able to beconsummated immediately following the Closing (as defined below), and as otherwise described in the ContributionAgreement (the “Closing”). On January 15, 2018, and in connection with the execution of the Contribution Agreement, ETE entered into a PurchaseAgreement (the “GP Purchase Agreement”) with Energy Transfer Partners, L.L.C. (together with ETE, the “GP Purchasers”),USA Compression Holdings, and, solely for certain purposes therein, R/C IV USACP Holdings, L.P. and ETP, pursuant towhich the GP Purchasers will acquire from USA Compression Holdings (i) all of the outstanding limited liability companyinterests in our general partner, and (ii) 12,466,912 common units (the “GP Purchase”). On January 15, 2018, and in connection with the execution of the Contribution Agreement, we entered into an EquityRestructuring Agreement (the “Equity Restructuring Agreement”) with our general partner and ETE, pursuant to which,among other things, we, our general partner and ETE have agreed to cancel our incentive distribution rights (the“Cancellation”) and convert our General Partner Interest (as defined in the Equity Restructuring Agreement) into a non-economic general partner interest (the “Conversion” and, together with the Cancellation, the “Restructuring”), in exchangefor our issuance of 8,000,000 common units to the general partner, effective at the Closing.3 Table of Contents On January 15, 2018, we entered into a Series A Preferred Unit and Warrant Purchase Agreement (the “Series A PurchaseAgreement”) with certain investment funds managed or sub-advised by EIG Global Energy Partners (“EIG”) and otherinvestment vehicles unaffiliated with EIG (collectively, the “Purchasers”) to issue and sell in a private placement (the“Private Placement”) $500 million in the aggregate of (i) newly authorized and established Series A Perpetual Preferred Unitsrepresenting limited partner interests in the Partnership (the “Preferred Units”) and (ii) warrants to purchase common units(the “Warrants”). We will issue 500,000 Preferred Units to the Purchasers at a price of $1,000 per Preferred Unit (the“Preferred Unit Purchase Price”), less a 1.0% structuring and origination fee, for total net proceeds, before expenses, of $495million. In addition, we will pay a 1.0% commitment fee to the Purchasers at the closing, as well as reimburse the Purchasersfor up to $400,000 of certain expenses incurred in connection with the transaction. We will also issue two tranches ofWarrants to the Purchasers, which will include Warrants to purchase 5,000,000 common units with a strike price of $17.03per unit and Warrants to purchase 10,000,000 common units with a strike price of $19.59 per unit. The Warrants may beexercised by the holders thereof at any time beginning on the one year anniversary of the closing date and before the tenthanniversary of the closing date. Upon exercise of the Warrants, we may, at our option, elect to settle the Warrants in commonunits on a net basis. The Series A Purchase Agreement contains customary representations, warranties and covenants of thePartnership and the Purchasers. The closing of the Private Placement is subject to customary closing conditions, includingthat we will have increased the aggregate commitments under our revolving credit facility to (or entered into a similarrevolving facility with minimum aggregate commitments of) at least $1.3 billion. In connection with the CDM Acquisition, on January 15, 2018, we entered into a commitment letter (the “BridgeCommitment”) with JPMorgan Chase Bank, N.A. and Barclays Bank PLC, as modified by the joinder to commitment letterand bridge fee letter entered into by the Partnership, JPMorgan Chase Bank, N.A. and Barclays Bank PLC with eachof Regions Bank, Royal Bank of Canada, Wells Fargo Bank, N.A., MUFG Union Bank, N.A., a member of MUFG, a globalfinancial group, The Bank of Nova Scotia and SunTrust Bank and certain affiliates of such parties (the “CommitmentLetter”). The Commitment Letter provides for senior unsecured bridge loans in an aggregate amount up to $725 million (the“Bridge Loans”). The proceeds of such Bridge Loans may be used (a) to finance a portion of the purchase price of the CDMAcquisition and (b) to pay fees and expenses incurred in connection therewith. The availability of the borrowings is subjectto the satisfaction of certain customary conditions. The Bridge Commitment will expire upon the earliest to occur of (1) theOutside Date as defined in the Contribution Agreement (as the same may be extended thereunder), (2) the consummation ofthe CDM Acquisition without use of the Bridge Loans, (3) the termination of the Contribution Agreement in accordance withits terms, or (4) September 30, 2018. The Bridge Loans are available to backstop a portion of the CDM Acquisition purchaseprice that we expect to fund with the net proceeds of other debt financing. Our historical financial and other information in this Annual Report on Form 10-K do not give effect to any of thetransactions described in this section titled “Recent Developments.” Business Strategies Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over timewhile ensuring the ongoing stability and growth of our business. We expect to achieve this objective by executing on thefollowing 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 both in emerging shaleplays and conventional basins. 4 Table of Contents·Continue to execute on attractive organic growth opportunities. From 2007 to 2017, we grew the horsepower in ourfleet of compression units and our compression revenues each at a compound annual growth rate of 15% primarilythrough organic growth. We believe organic growth opportunities will continue to be a source of near-term growthand we expect such organic growth levels in 2018 will be consistent with the growth seen in the second half of2017. We seek to achieve continued organic growth by (i) increasing our business with existing customers,(ii) obtaining new customers in our existing areas of operations and (iii) expanding our operations into newgeographic areas. ·Partner with customers who have significant compression needs. We actively seek to identify customers withmeaningful acreage positions or significant infrastructure development in active and growing areas. We work withthese 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 be able to take advantage of growthopportunities. Historically, we have utilized our cash flow from operations, borrowings under our revolving creditfacility and issuances of equity securities to fund capital expenditures to expand our compression services business.This approach has allowed us to significantly grow our fleet and the amount of cash we generate, while maintainingour debt at levels we believe are manageable for our business. We believe the appropriate management of ourfinancial position and the resulting access to capital positions us to take advantage of future growth opportunities asthey arise. 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 for established customers, we will agree to service third-party owned equipment. We do not own anycompression fabrication facilities. 5 Table of ContentsOur 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. Approximately 98% of our fleet horsepower as of December 31, 2017 was purchased newand the average age of our compression units was approximately five years. Our modern, standardized compression unit fleetis powered primarily by the Caterpillar 3400, 3500 and 3600 engine classes, which range from 401 to 4,735 horsepower perunit. These larger horsepower units, which we define as 400 horsepower per unit or greater, represented 83.0% of our totalfleet horsepower (including compression units on order) as of December 31, 2017. In addition, a portion of our fleet consistsof smaller horsepower units ranging from 30 horsepower to 399 horsepower that are primarily used in gas lift applications.We believe the young age and overall composition of our compressor fleet result in fewer mechanical failures, lower fuelusage, and reduced environmental emissions. The following table provides a summary of our compression units by horsepower as of December 31, 2017: Unit Horsepower FleetHorsepower NumberofUnits Horsepoweron Order (1) Numberof Unitson Order TotalHorsepower NumberofUnits Percent ofTotalHorsepower Percent ofTotalUnits Small horsepower <400 333,004 2,227 — — 333,004 2,227 17.1% 65.0%Large horsepower >400 and <1,000 161,822 284 — — 161,822 284 8.3% 8.3%>1,000 1,304,955 844 153,020 69 1,457,975 913 74.7% 26.7%Total 1,799,781 3,355 153,020 69 1,952,801 3,424 100.0% 100.0% (1)As of December 31, 2017, we had 147,500 and 5,520 horsepower on order for delivery during 2018 and 2019, respectively. The following table sets forth certain information regarding our compression fleet as of the dates and for the periodsindicated: Year Ended Percent December 31, Change Operating Data: 2017 2016 2015 2017 2016 Fleet horsepower (at period end) (1) 1,799,781 1,720,547 1,712,196 4.6% 0.5% Total available horsepower (at period end) (2) 1,950,301 1,730,547 1,712,196 12.7% 1.1% Revenue generating horsepower (at period end) (3) 1,624,377 1,387,073 1,424,537 17.1% (2.6)% Average revenue generating horsepower (4) 1,505,657 1,377,966 1,408,689 9.3% (2.2)% Revenue generating compression units (at period end) 2,830 2,552 2,737 10.9% (6.8)% Average horsepower per revenue generatingcompression unit (5) 554 534 517 3.7%3.3% Horsepower utilization (6): At period end 94.8% 87.1% 89.2% 8.8% (2.4)% Average for the period (7) 92.0% 87.4% 90.5% 5.3% (3.4)% (1)Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order). As of December 31,2017, we had 147,500 and 5,520 horsepower on order for delivery during 2018 and 2019, respectively.(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.6 Table of Contents(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 and thatis subject to a purchase order, divided by (ii) total available horsepower less idle horsepower that is under repair. Horsepower utilizationbased on revenue generating horsepower and fleet horsepower at each applicable period end was 90.3%, 80.6% and 83.2% for the yearsended December 31, 2017, 2016 and 2015, 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 85.9%, 80.3% and 85.1% for each year endedDecember 31, 2017, 2016, and 2015, respectively. 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 2018 where beneficial from an operating 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 to avoid excessive annual maintenance capital expenditures and minimize 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 applicable 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, 2017, approximately 51% 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.7 Table of ContentsAvailability is reduced by instances of “down-time” that are attributable to anything other than events of force majeure oracts or failures to act by the customer. Down-time under our contracts usually begins when our services stop being providedor when we receive notice from the customer of the problem. Down-time due to scheduled maintenance is excluded from ouravailability commitment. Our failure to meet a stated availability guarantee may result in a service fee credit to the customer.As a consequence of our availability guarantee, we are incentivized to perform predictive and preventive maintenance on ourfleet as well as promptly respond to a problem to meet our contractual commitments and ensure our customers thecompression availability on which their business and our service relationship are based. For service contracts that do nothave a stated availability guarantee, we work with those customers to ensure that our compression services meet theiroperational needs. 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 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 and field technicians qualify, analyze and scope new compression applications as well as regularly visit ourcustomers to ensure customer satisfaction, to determine a customer’s needs related to existing services being provided and todetermine the customer’s future compression service requirements. This ongoing communication allows us to quicklyidentify and respond to our customers’ compression requirements. Customers Our customers consist of more than 250 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 43% of our revenue for each of the years ended December 31, 2017 and 2016. 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 Ariel8 Table of ContentsCorporation, 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 S&RCompression, LLC (“S&R”), to package and assemble our compression units. Although we rely primarily on these suppliers,we believe alternative sources for natural gas compression equipment are generally available if needed. However, relying onalternative sources may increase our costs and change the standardized nature of our fleet. We have not experienced anymaterial supply problems to date. Although lead-times for new Caterpillar engines and new Ariel compressor frames have inthe past been in excess of one year due to increased demand and supply allocations imposed on equipment packagers andend-users, currently lead-times for such engines and frames are approximately one year or shorter. Please read Part I, Item 1A(“Risk Factors—Risks Related to Our Business—We depend on a limited number of suppliers and are vulnerable to productshortages 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, aswell as greater financial and other resources than we do. On a regional basis, we experience competition from numeroussmaller companies that may be able to more quickly adapt to changes within our industry and changes in economicconditions as a whole, more readily take advantage of available opportunities and adopt more aggressive pricing policies.Additionally, the historical availability of attractive financing terms from financial institutions and equipment manufacturershas made the purchase of individual compression units affordable to our customers. We believe that we compete effectivelyon the basis of price, equipment availability, customer service, flexibility in meeting customer needs, quality and reliabilityof our compressors 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 reflected any material seasonality, and we do not currently have reason tobelieve 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 our9 Table of Contentsoperations and limit our growth and revenue. Moreover, failure to comply with these laws and regulations may result in theassessment of administrative, civil and criminal penalties, imposition of remedial obligations and the issuance of injunctionsdelaying or prohibiting operations. Private parties may also have the right to pursue legal actions to enforce compliance aswell as to seek damages for non-compliance with environmental laws and regulations or for personal injury or propertydamage. While we believe that our operations are in substantial compliance with applicable environmental laws andregulations and that continued compliance with current requirements would not have a material adverse effect on us, there isno assurance that this trend of compliance will continue in the future. Thus, any changes in, or more stringent enforcement of,these laws and regulations that result in more stringent and costly pollution control equipment, waste handling, storage,transport, disposal or remediation requirements could have a material adverse effect on our operations and financial position. We do not believe that compliance with federal, state or local environmental laws and regulations will have a 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 the 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 emission 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 Standard (“NAAQs”) for several air pollutants. Forexample, in 2015, the EPA finalized a rule strengthening the primary and secondary standards for ground level ozone, bothof which are 9-hour concentration standards of 70 parts per billion (“ppb”). After the EPA revises a NAAQS standard, thestates are expected to establish revised attainment/non-attainment regions. State implementation of the revised NAAQScould result 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 emission 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 emission 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 these methane gas and VOC emissions. These Subpart10 Table of ContentsOOOOa standards will expand the 2012 New Source Performance Standards by using certain equipment-specific emissionscontrol practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposingleak detection and repair requirements for natural gas compressor and booster stations. However, the EPA announced in April2017 that it intends to reconsider certain aspects of the 2016 New Source Performance Standards, and in May 2017, the EPAissued an administrative stay of key provisions of the rule, but was promptly ordered by the D.C. Circuit to implement therule. The EPA also proposed 60-day and two-year stays of certain provisions in June 2017 and published a Notice of DataAvailability in November 2017 seeking comment and providing clarification regarding the agency’s legal authority to staythe rule. Subpart OOOOa and any additional regulation of air emissions from the oil and gas sector could result in increasedexpenditures for pollution control equipment, which could impact our customers’ operations and negatively impact ourbusiness. 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 emission 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. In recent years, the U.S. Congress has considered legislation to reduceemissions of greenhouse gases. It presently appears unlikely that comprehensive climate legislation will be passed by eitherhouse of Congress in the near future, although energy legislation and other initiatives are expected to be proposed that maybe relevant to greenhouse gas emissions issues. However, almost half of the states have begun to address greenhouse gasemissions, primarily through the planned development of emission inventories or regional greenhouse gas cap and tradeprograms. Depending on the particular program, we could be required to control greenhouse gas emissions or to purchase andsurrender allowances for greenhouse gas emissions resulting from our operations. Independent of Congress, the EPA undertook to adopt regulations controlling greenhouse gas emissions under itsexisting CAA authority. For example, in 2009, the EPA officially published its findings that emissions of carbon dioxide,methane and other greenhouse gases endanger human health and the environment, allowing the agency to proceed with theadoption of regulations that restrict emissions of greenhouse gases under existing provisions of the CAA. In 2009 and 2010,the EPA adopted rules regarding regulation of greenhouse gas emissions from motor vehicles and requiring the reporting ofgreenhouse gas emissions in the U.S. from specified large greenhouse gas emission sources, including petroleum and naturalgas facilities such as natural gas transmission compression facilities that emit 25,000 metric tons or more of carbon dioxideequivalent per year. In 2015, the EPA published standards of performance for greenhouse gas 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 emission reduction that EPA has determined has been adequately demonstrated for each type of unit. Therule 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 (“CCP”), 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 stay11 Table of Contentsof the implementation of the CPP, which will remain in effect throughout the pendency of the appeals process including atthe U.S. Court of Appeals of the D.C. Circuit and the Supreme Court through any certiorari petition that may be granted. It isnot yet clear how the courts will rule on the legality of the CPP. Additionally, in October 2017 the EPA proposed to repealthe CPP, although the final outcome of this action and the pending litigation regarding the CPP is uncertain at this time. Inconnection with the proposed repeal, EPA issued an Advance Notice of Proposed Rulemaking (“ANPRM”) in December2017 regarding emission guidelines to limit emissions of greenhouse gases (“GHGs”) from existing electricity utilitygenerating units. The ANPRM seeks comment regarding what the EPA should include in a potential new, existing-sourceregulation under the Clean Air Act of GHG emissions from electric utility generating units that it may propose. If the effort torepeal the rules is unsuccessful and the rules are upheld at the conclusion of this appellate process and were implemented intheir current form, or if the ANPRM results in a different proposal to control GHG emissions from electric utility generatingunits, demand for the oil and natural gas our customers produce may decrease. In addition, the costs of electricity for ouroperations 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. In 2015, the BLM promulgated new requirements relating to well construction, water management, and chemicaldisclosure for companies drilling on federal and tribal land. The agency subsequently finalized a rule in December 2017rescinding the 2015 rule. 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 (“BLM Venting Rule”). The rule requires operators to usecertain technologies and equipment to reduce flaring and to periodically inspect their operations for leaks. The rule alsospecifies when operators owe the government royalties for flared gas. In November 2016, state and industry groupschallenged this BLM rule in the U.S. District Court for the District of Wyoming, asserting that the BLM lacks authority toprescribe air quality regulations. The court stayed the case in December 2017, however, when the BLM finalized a decisionto delay implementation of key requirements in the rule for one year. If the BLM Venting Rule is not repealed and surviveslegal challenge, it could increase the costs of operations for our clients who operate on BLM land, and negatively impact ourbusiness.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 greenhouse gas legislation,regulation, agreements or initiatives will impact our business, any legislation or regulation of greenhouse gas emissions thatmay be imposed in areas in which we conduct business could result in increased compliance costs or additional operatingrestrictions or reduced demand for our services, and could have a material adverse effect on our business, financial conditionand results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in the earth’satmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity ofstorms, droughts, and floods and other climatic events. If any of those effects were to occur, they could have an adverse effecton 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 U.S. Thedischarge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPAor an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge andfill 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, if required, to help prevent the contamination ofnavigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak at12 Table of Contentssuch facilities. In addition, the CWA and analogous state laws require individual permits or coverage under general permitsfor 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 U.S. In any event,our customers assume responsibility under the majority of our standard natural gas compression contracts for obtaining anypermits that may be required under the CWA whether for discharges or developing the property by filling wetlands.Considerable legal uncertainty exists surrounding the standard for what constitutes jurisdictional waters and wetlandssubject to the protections and requirements of the CWA. A 2015 rulemaking by the EPA to revise the standard was stayednationwide by the U.S. Court of Appeals for the Sixth Circuit and stayed for certain primarily western states by a U.S. DistrictCourt in North Dakota. For now, the EPA and the Army Corps of Engineers (“Corps”) will continue to apply the existingstandard for what constitutes a water of the U.S. as determined by the Supreme Court in the Rapanos case and post-Rapanosguidance. Should the 2015 rule take effect, or should a different rule expanding the definition of what constitutes a water ofthe U.S. be promulgated as a result of the EPA and the Corps’ rulemaking process, our customers could face increased costsand delays due to additional permitting 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. Hydraulic fracturing involves theinjection of water, sand and chemicals under pressure into the formation to stimulate gas production. Legislation to amendthe Safe Drinking 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 also has 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 the development of new interpretations of those requirements bythe agencies that issue the permits, that could lead to delays, increased operating costs and process prohibitions that couldreduce demand for our compression services, which would 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 original conducton certain classes of persons that contributed to the release of a hazardous substance into the environment. These personsinclude the owner and operator of a disposal site where a hazardous substance release occurred and any company13 Table of Contentsthat transported, disposed of or arranged for the transport or disposal of hazardous substances released at the site. UnderCERCLA, 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 the 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, a wholly owned subsidiary of our general partner, performs certain management and otheradministrative services for us, such as accounting, corporate development, finance and legal. All of our employees, includingour executive officers, are employees of USAC Management. As of December 31, 2017, USAC Management had 426 fulltime employees. None of our employees are subject to collective bargaining agreements. We consider our employee relationsto be good. Available Information Our website address is usacompression.com. We make available, free of charge at the “Investor Relations” portion 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 Securities and Exchange Commission (“SEC”). The information contained on our website does not constitute part ofthis report. The SEC maintains a website that contains these reports at sec.gov. Any materials we file with the SEC also may be reador copied at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information concerning theoperation of the Public Reference Room may be obtained by calling the SEC at (800) 732-0330. 14 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 occur, our business, financial condition or results of operations could be materially and adversely affected. Inthat case, we might not be able to continue to pay our current quarterly distribution on our common units or grow suchdistributions and the trading price of our common units could decline. Risks Related to Our Business We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees andexpenses, including cost reimbursements to our general partner, to enable us to make cash distributions at our currentdistribution rate to our unitholders. In order to make cash distributions at our current distribution rate of $0.525 per unit per quarter, or $2.10 per unit peryear, we will require available cash of $33.1 million per quarter, or $132.2 million per year, based on the number of commonunits and the 1.2% general partner interest outstanding as of February 8, 2018. Under our cash distribution policy, theamount of cash we can distribute to our unitholders principally depends upon the amount of cash we generate from ouroperations, 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 locations 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, including the CDM Acquisition; ·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 capital expenditures and expansion capital expenditures; ·the level of our operating costs and expenses; ·our debt service requirements and other liabilities; ·fluctuations in our working capital needs; ·restrictions contained in our revolving credit facility; ·the cost of acquisitions; ·fluctuations in interest rates; ·the financial condition of our customers; ·our ability to borrow funds and access the capital markets; and15 Table of Contents ·the amount of cash reserves established by our 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 general demand for energy. Any prolonged, substantial reduction inthe demand for natural gas or crude oil would likely depress the level of production activity and result in a decline in thedemand for our compression services, which could result in a reduction in our revenues and our cash available fordistribution. 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 $1.92 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 2017, the North American rig count was 929 rigs, as WTIcrude oil spot prices hovered near their highest level since the summer of 2015 at $60.46 per barrel and Henry Hub naturalgas spot prices were $2.81 per MMBtu. Although commodity prices and our utilization increased during 2016 and 2017, theincreased activity resulting from such increased commodity prices may not continue or the trend of increasing commodityprices may reverse. In addition, a small portion of our fleet is used in connection with crude oil production using horizontaldrilling techniques. During the period of low crude oil prices, we experienced pressure on service rates from our customers ingas lift applications; if commodity prices decline from current levels, we may 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 be uneconomic to drill and produce, which could in turnnegatively impact the demand for our services. Further, if demand for our services decreases, we may be asked to renegotiateour service contracts at lower rates. In addition, governmental regulation and tax policy may impact the demand for naturalgas or crude oil or impact the economic feasibility of development of new fields or production of existing fields, which areimportant 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. Our ten largestcustomers accounted for approximately 43% of our revenue for each of the years ended December 31, 2017 and 2016. Theloss of all or even a portion of the compression services we provide to our key customers, as a result of competition orotherwise, could have a material adverse effect on our business, results of operations, financial condition and cash availablefor 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 cost16 Table of Contentsproviders, not renewing month-to-month contracts or determining not to enter into any new compression service contracts. Asignificant decline in commodity prices may cause certain of our customers to reconsider near-term capital budgets, whichmay impact 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. In addition, in the course of ourbusiness we hold accounts receivable from our customers. In the event that any such customer was to enter into bankruptcy,we could lose all or a portion of such outstanding accounts receivable associated with that customer. Further, if a customerwas to enter into bankruptcy, it could also result in the cancellation of all or a portion of our service contracts with suchcustomer at significant expense to us. We face significant competition that may cause us to lose market share and reduce our cash available for distribution. The compression business is highly competitive. Some of our competitors have a broader geographic scope, as well asgreater financial and other resources than we do. Our ability to renew or replace existing contracts with our customers at ratessufficient to maintain current revenue and cash flows could be adversely affected by the activities of our competitors and ourcustomers. 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 fleetsthat would create additional competition for us. All of these competitive pressures could have a material adverse effect on ourbusiness, results of operations, financial condition and reduce our cash available for distribution. Our customers may choose to vertically integrate their operations by purchasing and operating their own compressionfleet, expanding the amount 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 in decreased demand forour compression services, which may have a material adverse effect on our business, results of operations, financial conditionand 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 applicable 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, 2017, approximately 51% 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 with us.These customers can generally terminate their month-to-month compression services contracts on 30-days’ written notice. If asignificant number of these customers were to terminate their month-to-month services, or attempt to renegotiate their month-to-month contracts at substantially lower rates, it could have a material adverse effect on our business, results of operations,financial condition and cash available for distribution. 17 Table of ContentsWe may be unable to grow our cash flows if we are unable to expand our business, which could limit our ability tomaintain or increase distributions to our unitholders. A principal focus of our strategy is to continue to grow the per unit distribution on our units by expanding our businessover time. Our future growth will depend upon a number of factors, some of which we cannot control. These factors includeour ability to: ·develop new business and enter into service contracts with new customers; ·retain our existing customers and maintain or expand the services we provide them; ·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 distributions to our unitholders, inwhich event the market price of our units will likely decline materially. We may be unable to grow successfully through acquisitions, and we may not be able to integrate effectively the businesseswe may acquire, which may impact our operations and limit our ability to increase distributions to our unitholders. From time to time, we may choose to make business acquisitions, such as the CDM Acquisition, to pursue marketopportunities, increase our existing capabilities and expand into new areas of operations. While we have reviewedacquisition opportunities in the past and will continue to do so in the future, we may not be able to identify attractiveacquisition opportunities or successfully acquire identified targets. In addition, we may not be successful in integrating anyfuture acquisitions, including the CDM Acquisition, into our existing operations, which may result in unforeseen operationaldifficulties or diminished financial performance or require a disproportionate amount of our management’s attention. Even ifwe are successful in integrating future acquisitions into our existing operations, we may not derive the benefits, such asoperational or administrative synergies, that we expected from such acquisitions, which may result in the commitment of ourcapital resources without the expected returns on such capital. Furthermore, competition for acquisition opportunities mayescalate, increasing our cost of making acquisitions or causing us to refrain from making acquisitions. Our inability to makeacquisitions, or to integrate acquisitions successfully into our existing operations, may adversely impact our operations andlimit our ability to increase distributions to our unitholders. Our ability to grow in the future is dependent on our ability to access external expansion capital. Our partnership agreement requires us to distribute to our unitholders all of our available cash, which excludes prudentoperating reserves. We expect that we will rely primarily upon cash generated by operating activities and, where necessary,borrowings under our revolving credit facility 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 theextent we are unable to efficiently finance growth externally, our ability to increase distributions to our unitholders could besignificantly impaired. In addition, because we distribute all of our available cash, which excludes prudent operatingreserves, we may not grow as quickly as businesses that reinvest their available cash to expand ongoing operations. To theextent we issue additional units including the Preferred Units described in Item 1 (“Business—Recent Developments”), thepayment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our perunit distribution level. There are no limitations in our partnership agreement on our ability to issue additional units,including units ranking senior to the common units, subject to certain18 Table of Contentsrestrictions in our partnership agreement that will take effect when the Preferred Units are issued. Similarly, the incurrence ofborrowings or other debt by us to finance our growth strategy would result in interest expense, which in turn would affect ourcash available for distribution. Our debt levels may limit our flexibility in obtaining additional financing, pursuing other business opportunities andpaying distributions. We have a $1.1 billion revolving credit facility that matures in January 2020. In addition, we have the option to increasethe amount of total commitments under the revolving credit facility by $200 million, subject to receipt of lendercommitments and satisfaction of other conditions. As of December 31, 2017, we had outstanding borrowings of $782.9million with a leverage ratio of 4.65x, borrowing base availability (based on our borrowing base) of $272.1 million and,subject to compliance with the applicable financial covenants, available borrowing capacity under the revolving creditfacility of $101.6 million. Financial covenants permit a maximum leverage ratio of (A) 5.25 to 1.0 as of the end of the fiscalquarter ending December 31, 2017 and (B) 5.00 to 1.0 thereafter. As of February 8, 2018, we had outstanding borrowings of$815.0 million. Our ability to incur additional debt is subject to limitations in our revolving credit facility, 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. 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 revolving credit facility could beimpacted by market interest rates, as all of our outstanding borrowings are subject to interest rates that fluctuate withmovements in interest rate markets. A substantial increase in the interest rates applicable to our outstanding borrowingscould have a material impact on our cash available for distribution. If our operating results are not sufficient to service ourcurrent or future indebtedness, we could be forced to take actions such as reducing distributions, reducing or delaying ourbusiness activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt orseeking additional equity capital. We may be unable to effect any of these actions on terms satisfactory to us, or at all. Restrictions in our revolving credit facility may limit our ability to make distributions to our unitholders and may limit ourability to capitalize on acquisition and other business opportunities. The operating and financial restrictions and covenants in our revolving credit facility and any future financingagreements could restrict our ability to finance future operations or capital needs or to expand or pursue our businessactivities. Our revolving credit facility restricts or limits our ability (subject to exceptions) to: ·grant liens; ·make certain loans or investments; ·incur additional indebtedness or guarantee other indebtedness; ·enter into transactions with affiliates; 19 Table of Contents·merge or consolidate; ·sell our assets; or ·make certain acquisitions. Furthermore, our revolving credit facility contains certain operating and financial covenants. Our ability to comply withthese covenants and restrictions may be affected by events beyond our control, including prevailing economic, financial andindustry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may beimpaired. If we violate any of the restrictions, covenants, ratios or other tests in our revolving credit facility, a significantportion of our indebtedness may become immediately due and payable, our lenders’ commitment to make further loans to usmay terminate, and we may be prohibited from making distributions to our unitholders. We might not have, or be able toobtain, sufficient funds to make these accelerated payments. We may not be able to replace such revolving credit facility, orif we are, any subsequent replacement of our revolving credit facility or any new indebtedness could have similar or greaterrestrictions. Please read Part II, Item 7 (“Management’s Discussion and Analysis of Financial Condition and Results ofOperations—Liquidity and Capital Resources—Description of Revolving Credit Facility”). Restrictions in our partnership agreement related to the Preferred Units may limit our ability to make distributions to ourunitholders and may limit our ability to capitalize on acquisition and other business opportunities. The operating and financial restrictions and covenants in our 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. If the PreferredUnits are issued, our partnership agreement will restrict or limit our ability (subject to exceptions) to: ·pay distributions on any junior securities, including the 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 commonunits; and ·incur Indebtedness (as defined in our revolving credit facility) if, after giving pro forma effect to such incurrence, theLeverage Ratio (as defined in our revolving credit facility) determined as of the last day of the most recently endedfiscal quarter would exceed 6.5x, subject to certain exceptions. An impairment of goodwill or other intangible assets could reduce our earnings. We have recorded $35.9 million of goodwill and $71.7 million of other intangible assets as of December 31, 2017.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 of our estimates of futurecash flows and growth rates in our business. These events could cause us to record impairments of goodwill or otherintangible assets. If we determine that any of our goodwill or other intangible assets are impaired, we will be required to takean immediate charge to earnings with a corresponding reduction of partners’ capital resulting in an increase in balance sheetleverage as measured by debt to total capitalization. There was no impairment recorded for goodwill or other intangibleassets for the years ended December 31, 2017 and 2016. For the year ended December 31, 2015, we recognized a $172.2million impairment of goodwill due primarily to the decline in our unit price, the sustained decline in global commodityprices, expected reduction in the capital budgets of certain of our customers and the impact these factors have on ourexpected future cash flows (see Note 2 of our consolidated financial statements). There was no impairment recorded for otherintangible assets for the year ended December 31, 2015. 20 Table of ContentsImpairment in the carrying value of long-lived assets could reduce our earnings. We have a significant amount of long-lived assets on our consolidated balance sheet. Under GAAP, long-lived assets arerequired to be reviewed for impairment when events or circumstances indicate that its carrying value may not be recoverableor will no longer be utilized in the operating fleet. The carrying value of a long-lived asset is not recoverable if it exceeds thesum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If businessconditions or other factors cause the expected undiscounted cash flows to decline, we may be required to record non-cashimpairment charges. Events and conditions that could result in impairment in the value of our long-lived assets includechanges in the industry in which we operate, competition, advances in technology, adverse changes in the regulatoryenvironment, or other factors leading to reduction in expected long-term profitability. For example, during the fiscal yearsended December 31, 2017 and 2016, we evaluated the future deployment of our idle fleet under then-current marketconditions and determined to retire and either sell or re-utilize the key components of 40 and 29 compressor units, orapproximately 11,000 and 15,000 horsepower, that were previously used to provide services in our business. As a result, werecognized impairments of $5.0 million and $5.8 million during the years ended December 31, 2017 and 2016, respectively. Our ability to manage and grow our business effectively may be adversely affected if we lose management or operationalpersonnel. We depend on the continuing efforts of our executive officers. The departure of any of our executive officers could havea significant negative effect on our business, operating results, financial condition and on our ability to compete effectivelyin 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 good, 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 S&R, to package and assemble our compression units. We do not havelong-term contracts with these suppliers or packagers, and a partial or complete loss of any of these sources could have anegative 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 units. We 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, emission controls and other environmental protection andoccupational health and safety concerns, as discussed in detail in Item 1 (“Business Environmental and Safety Regulations”).Environmental laws and regulations may, in certain circumstances, impose strict liability for environmental contamination,which may render us liable for remediation costs, natural resource damages and other damages as a result of our conduct thatwas lawful at the time it occurred or the conduct of, or conditions caused by, prior owners or operators or other third parties.In addition, where contamination may be present, it is not uncommon for neighboring land owners and other third parties tofile claims for personal injury, property damage and recovery of21 Table of Contentsresponse costs. Remediation costs and other damages arising as a result of environmental laws and regulations, and costsassociated with new information, changes in existing environmental laws and regulations or the adoption of newenvironmental laws and regulations could be substantial and could negatively impact our financial condition or results ofoperations. Moreover, failure to comply with these environmental laws and regulations may result in the imposition ofadministrative, civil and criminal penalties and the issuance of injunctions delaying or prohibiting operations. We conduct operations in a wide variety of locations across the continental U.S. These operations require U.S. federal,state or local environmental permits or other authorizations. 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 asemission 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 in 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, as discussed in detail in Item1 (“Business Environmental and Safety Regulations”), may lead to adverse impacts on our business, financial condition,results of operations, and cash available for distribution. For example, in 2015, the EPA finalized a rule strengthening theprimary and secondary National Ambient Air Quality Standards (“NAAQS”) for ground level ozone, both of which are 8-hourconcentration standards of 70 parts per billion (“ppb”). After the EPA revises a NAAQS standard, the states are expected toestablish revised attainment/non-attainment regions. State implementation of the revised NAAQS could result in stricterpermitting requirements, delay or prohibit our customers’ ability to obtain such permits, and result in increased expendituresfor pollution control equipment, which could impact our customers’ operations, increase the cost of additions to property,plant, and equipment, and negatively impact our business. In 2012, the EPA finalized rules that establish new air emission 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 emission 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 these methane gas and volatile organic compound emissions. These Subpart OOOOa standardswill expand the 2012 New Source Performance Standards by using certain equipment-specific emissions control practices,requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection andrepair requirements for natural gas compressor and booster22 Table of Contentsstations. However, the EPA announced in April 2017 that it intends to reconsider certain aspects of the 2016 New SourcePerformance Standards, and in May 2017, the EPA issued an administrative stay of key provisions of the rule, but waspromptly ordered by the D.C. Circuit to implement the rule. The EPA also proposed 60-day and two-year stays of certainprovisions in June 2017 and published a Notice of Data Availability in November 2017 seeking comment and providingclarification regarding the agency’s legal authority to stay the rule. If implemented, Subpart OOOOa and any additional regulation of air emissions from the oil and gas sector could result inincreased expenditures for pollution control equipment, which could impact our customers’ operations and negativelyimpact 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. In recent years,the U.S. Congress has considered legislation to reduce emissions of greenhouse gases. It presently appears unlikely thatcomprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislationand other initiatives are expected to be proposed that may be relevant to greenhouse gas emissions issues. However, almosthalf of the states have begun to address greenhouse gas emissions, primarily through the planned development of emissioninventories or regional greenhouse gas cap and trade programs. Depending on the particular program, we could be required tocontrol greenhouse gas emissions or to purchase and surrender allowances for greenhouse gas emissions resulting from ouroperations. Independent of Congress, and as discussed in detail in Item 1 (“Business Environmental and Safety Regulations”), theEPA undertook to adopt regulations controlling greenhouse gas emissions under its existing CAA authority. For example, in2015, the EPA published standards of performance for greenhouse gas 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 emission reduction that EPA has determined has been adequately demonstrated for each type of unit. Therule 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, 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 Clean Power Plan, which will remain in effect throughout the pendency of the appeals processincluding at the United States Court of Appeals of the D.C. Circuit and the Supreme Court through any certiorari petition thatmay be granted. The stay suspends the rule, including the requirement that states must start submitting implementation plans.Additionally, in October 2017 EPA proposed to repeal the CPP, although the final outcome of this action and the pendinglitigation regarding the CPP is uncertain at this time. In connection with the proposed repeal, EPA issued an Advance Noticeof Proposed Rulemaking (“ANPRM”) in December 2017 regarding emission guidelines to limit GHG emissions from existingelectricity utility generating units. The ANPRM seeks comment regarding what the EPA should include in a potential new,existing-source regulation under the Clean Air Act of GHG emissions from electric utility generating units that it maypropose. If the effort to repeal the rules is unsuccessful and the rules are upheld at the conclusion of this appellate process andenforced in their current form, or if the ANPRM results in a different proposal to control GHG emissions from electric utilitygenerating units, demand for the oil and natural gas our customers produce may decrease. Although it is not currently possible to predict with specificity how any proposed or future greenhouse gas legislation,regulation, agreements or initiatives will impact our business, any legislation or regulation of greenhouse gas emissions thatmay be imposed in areas in which we conduct business could result in increased compliance costs or additional operatingrestrictions or reduced demand for our services, and could have a material adverse effect on our business, financial conditionand results of operations. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in the earth’satmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity ofstorms, droughts, and floods and other climatic events. If any of those effects were to occur, they could have an adverse effecton our assets and operations. 23 Table of ContentsIncreased regulation of hydraulic fracturing could result in reductions 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 formation to stimulate gas production. Legislation to amend the Safe Drinking Water Act(“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. 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 by region,and that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, thelikely 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 permits, that could lead to delays, increasedoperating costs and process prohibitions that could reduce demand for our compression services, which would materiallyadversely affect our revenue and results of operations. We do not insure against all potential losses and could be seriously harmed by unexpected liabilities. Our operations are subject to inherent risks such as equipment defects, malfunction and failures, and natural 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. 24 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 certain types ofinsurance 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 as a result of terrorismor war could also affect our ability to raise capital. If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial resultsaccurately or prevent fraud, which would likely have a negative impact on the market price of our units. In connection with the closing of our initial public offering, we became subject to the public reporting requirements ofthe Exchange Act. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and tooperate successfully as a publicly traded partnership. We continue to 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, among other things, toreview and report annually on the effectiveness of our internal control over financial reporting. We were required to complywith Section 404(a) beginning with our fiscal year ended December 31, 2013. In addition, our independent registered publicaccountants will be required to assess the effectiveness of internal control over financial reporting at the end of the fiscal yearafter we are no longer an “emerging growth company” under the Jumpstart Our Business Startups Act, which will occur at theend of 2018. Any failure to develop, implement or maintain effective internal controls or to improve our internal controlscould harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in thedesign and operation of internal controls over financial reporting, we can provide no assurance as to our independentregistered public accounting firm’s conclusions about the effectiveness of our internal controls, and we may incur significantcosts in our efforts to comply with Section 404. Ineffective internal controls will subject us to regulatory scrutiny and 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 units. Risks Inherent in an Investment in Us Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors. Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on mattersaffecting our business and, therefore, limited ability to influence management’s decisions regarding our business.Unitholders have no right to elect our general partner or its board of directors. USA Compression Holdings is the sole memberof our general partner and has the right to appoint our general partner’s entire board of directors, including its independentdirectors. If the unitholders are dissatisfied with the performance of our general partner, they have little ability to remove ourgeneral partner. As a result of these limitations, the price of our common units may be diminished because of the absence orreduction of a takeover premium in the trading price. Furthermore, our partnership agreement also contains provisionslimiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisionslimiting the unitholders’ ability to influence the manner or direction of management. If the GP Purchase is completed, all ofthe risks relative to USA Compression Holdings in this paragraph will subsequently apply to the Energy Transfer Parties. 25 Table of ContentsThe owner of our general partner has sole responsibility for conducting our business and managing our operations. Ourgeneral partner and its affiliates, including the owner thereof, have conflicts of interest with us and limited fiduciary dutiesand they may favor their own interests to the detriment of us and our unitholders. USA Compression Holdings, which is principally owned and controlled by Riverstone, owns and controls our generalpartner and appointed all of the officers and directors of our general partner, some of whom are also officers and directors ofUSA Compression Holdings. Although our general partner has a fiduciary duty to manage us in a manner that is beneficial tous and our unitholders, the directors and officers of our general partner have a fiduciary duty to manage our general partner ina manner that is beneficial to its owner. Conflicts of interest will arise between our general partner and its owner, on the onehand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor itsown interests and the interests of its owner over our interests and the interests of our unitholders. These conflicts include thefollowing situations, among others: ·neither our partnership agreement nor any other agreement requires the owner of our general partner to pursue abusiness strategy that favors us; ·our general partner is allowed to take into account the interests of parties other than us, such as its owner, inresolving conflicts of interest; ·our partnership agreement limits the liability of and reduces the fiduciary duties owed by our 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, our general partner has the power and authority to conduct our business withoutunitholder approval; ·our 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; ·our 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 and to our general partner; ·our general partner determines which costs incurred by it are reimbursable by us; ·our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if thepurpose or effect of the borrowing is to make incentive distributions; ·our 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. Thiscash may be used to fund distributions as operating surplus from non-operating sources to our general partner inrespect of its General Partner Interest (as defined under Part II, Item 5 (“Market for Registrant’s Common Equity,Related Stockholder Matters and Issuer Purchases of Equity Securities”) or the incentive distribution rights (or“IDRs”); ·our partnership agreement does not restrict our 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; ·our general partner intends to limit its liability regarding our contractual and other obligations; 26 Table of Contents·our general partner may exercise its right to call and purchase all of the common units not owned by it and itsaffiliates if they own more than 80% of the common units; ·our general partner controls the enforcement of the obligations that it and its affiliates owe to us; ·our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and ·our general partner may elect to cause us to issue common units to it in connection with a resetting of the targetdistribution levels related to the IDRs without the approval of the conflicts committee of the board of directors ofour general partner or our unitholders. This election may result in lower distributions to our common unitholders incertain situations. Our general partner’s liability regarding our obligations is limited. Our 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 our general partner or its assets. Our general partner may therefore cause us to incurindebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that anyaction taken by our general partner to limit its liability is not a breach of our general partner’s fiduciary duties, even if wecould have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse orindemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement orindemnification payments would reduce the amount of cash otherwise available for distribution. Our partnership agreement limits our general partner’s fiduciary duties to our unitholders. Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our generalpartner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our generalpartner to make a number of decisions in its individual capacity, as opposed to its capacity as our general partner, orotherwise free of fiduciary duties to us and our unitholders. This entitles our 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 our 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 units it owns; ·whether to elect to reset target distribution levels; and ·whether or not to consent to any merger or consolidation of the Partnership or amendment to the partnershipagreement. By purchasing a unit, a unitholder agrees to become bound by the provisions in the partnership agreement, including theprovisions discussed above. Even if holders of our common units are dissatisfied, they currently cannot remove our general partner without USACompression Holdings’ consent. The unitholders are currently unable to remove our general partner because our general partner and its affiliates ownsufficient units to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding common unitsis required to remove our general partner. USA Compression Holdings currently owns over 331/3% of our27 Table of Contentsoutstanding common units and, after giving effect to the CDM Acquisition and the other transactions described in Item 1(“Business—Recent Developments”), the Energy Transfer Parties will own over 331/3% of our outstanding common units. Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our generalpartner that might otherwise constitute breaches of fiduciary duty. Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by ourgeneral partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, ourpartnership agreement: ·provides that whenever our general partner makes a determination or takes, or declines to take, any other action inits capacity as our general partner, our 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 our partnershipagreement, Delaware law, or any other law, rule or regulation, or at equity; ·provides that our general partner will not have any liability to us or our unitholders for decisions made in itscapacity as a general partner so long as such decisions are made in good faith, meaning that it believed that thedecisions were in the best interest of our partnership; ·provides that our general partner and its officers and directors will not be liable for monetary damages to us, 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 our 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 our 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 of directors of our general partner, although our generalpartner is not obligated to seek such approval; (b)approved by the vote of a majority of the outstanding common units, excluding any common units ownedby our 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 connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by ourgeneral partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approvedby our common unitholders or the conflicts committee and the board of directors of our general partner determines that theresolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of thestandards set forth in subclauses (c) and (d) above, then it will conclusively be deemed that, in making its decision, the boardof directors of our general partner acted in good faith. 28 Table of ContentsOur general partner may elect to cause us to issue common units to it in connection with a resetting of the targetdistribution levels related to its IDRs, without the approval of the conflicts committee of its board of directors of ourgeneral partner or the holders of our common units. This could result in lower distributions to holders of our commonunits. Our general partner has the right, at any time when it has received incentive distributions at the highest level to which itis entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higherlevels based on our distributions at the time of the exercise of the reset election. Following a reset election by our generalpartner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the targetdistribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimumquarterly distribution. If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common unitsand to maintain its general partner interest. The number of common units to be issued to our general partner will equal thenumber of common units which would have entitled the holder to an average aggregate quarterly cash distribution in theprior two quarters equal to the average of the distributions to our general partner on the IDRs in the prior two quarters. Ourgeneral partner’s general partner interest in us (currently 1.2%) will be maintained at the percentage that existed immediatelyprior to the reset election. Our general partner could exercise this reset election at a time when it is experiencing, or expectsto experience, declines in the cash distributions it receives related to its IDRs and may, therefore, desire to be issued commonunits rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, areset election may cause our common unitholders to experience a reduction in the amount of cash distributions that ourcommon unitholders would have otherwise received had we not issued new common units to our general partner inconnection with resetting the target distribution levels. On January 15, 2018, our general partner entered into an agreementpursuant to which it agreed to, among other things, convert the General Partner Interest into a non-economic general partnerinterest and cancel the IDRs. The transactions are expected to close in the first half of 2018. See Item 1 (“Business—RecentDevelopments”) for more information. Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units. Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units heldby a person or group that owns 20% or more of any class of units then outstanding, other than our general partner, itsaffiliates, their direct transferees and their indirect transferees approved by our general partner (which approval may begranted in its sole discretion) and persons who acquired such units with the prior approval of our general partner, cannot voteon any matter. Our general partner interest or the control of our general partner may be transferred to a third party without unitholderconsent. Our 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 unitholders. Furthermore, our partnership agreement does not restrict the ability ofUSA Compression Holdings to transfer all or a portion of its ownership interest in our general partner to a third party. Thenew owner of our general partner would then be in a position to replace the board of directors and officers of our generalpartner with its own designees and thereby exert significant control over the decisions made by the board of directors andofficers of our general partner. On January 15, 2018, USA Compression Holdings entered into an agreement pursuant towhich it agreed to, among other things, sell 100% of its ownership interests in our general partner to ETE. The transactionsare expected to close in the first half of 2018. See Item 1 (“Business—Recent Developments”) for more information. An increase in interest rates may cause the market price of our common units to decline. Like all equity investments, an investment in our common units is subject to certain risks. In exchange for acceptingthese risks, investors may expect to receive a higher rate of return than would otherwise be obtainable from lower-riskinvestments. Accordingly, as interest rates rise, the ability of investors to obtain higher risk-adjusted rates of return bypurchasing government-backed debt securities may cause a corresponding decline in demand for riskier investments29 Table of Contentsgenerally, including yield based equity investments such as publicly traded partnership interests. Reduced demand for ourcommon units resulting from investors seeking other more favorable investment opportunities may cause the trading price ofour common units to decline. We may issue additional units without the approval of the common unitholders, which would dilute your existingownership interests. Our partnership agreement does not limit the number or timing of additional limited partner interests that we may issuewithout the approval of our common unitholders. The issuance by us of additional common units, including pursuant to ourDistribution Reinvestment Plan (“DRIP”), or other equity securities of equal or senior rank, will have the following effects: ·our existing unitholders’ proportionate ownership interest in us will decrease; ·the amount of cash available for distribution on each unit may decrease; ·the ratio of taxable income to distributions may increase; ·the relative voting strength of each previously outstanding unit may be diminished; ·the market price of the common units may decline; ·assuming the distribution per unit remains unchanged or increases, the cash distributions to the holder of the IDRswill increase; and ·On January 15, 2018, we entered into an agreement pursuant to which we agreed, among other things, to issuePreferred Units to certain investors. The transactions are expected to close in the first half of 2018. See Item 1(“Business—Recent Developments”) for more information. USA Compression Holdings, Argonaut and the Energy Transfer Parties may sell units in the public or private markets, andsuch sales could have an adverse impact on the trading price of the common units. As of December 31, 2017, USA Compression Holdings holds an aggregate of 25,092,196 common units. ArgonautPrivate Equity, L.L.C. (“Argonaut”) holds an aggregate of 7,715,948 common units. In addition, USA Compression Holdingsand Argonaut may acquire additional common units in connection with our DRIP. After giving effect to the CDMAcquisition and the other transactions described in Item 1 (“Business—Recent Developments”), the Energy Transfer Partieswill own an aggregate of 46,056,228 common units (after giving effect to the conversion of 6,397,965 Class B Unitsrepresenting limited partner interests in the Partnership), and USA Compression Holdings will own an aggregate of12,625,284 common units. We have agreed to provide USA Compression Holdings and the Energy Transfer Parties withcertain registration rights for any common units they own. The sale of these common units in the public or private marketscould have an adverse impact on the price of the common units or on any trading market that may develop. Our general partner has a call right that may require you to sell your common units at an undesirable time or price. If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will havethe right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of thecommon units held by unaffiliated persons at a price that is not less than their then-current market price, as calculatedpursuant to the terms of our partnership agreement. As a result, you may be required to sell your common units at anundesirable time or price. You may also incur a tax liability upon a sale of your units. USA Compression Holdings owns anaggregate of approximately 40% of our outstanding common units and, after giving effect to the CDM Acquisition and theother transactions described in Item 1 (“Business—Recent Developments”), the Energy Transfer Parties would own anaggregate of approximately 49% of our outstanding common units. 30 Table of ContentsYour 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 our general partner. Our partnership isorganized under Delaware law, and we conduct business in a number of other states. The limitations on the liability ofholders of limited partner interests for the obligations of a limited partnership have not been clearly established in some ofthe other states in which we do business. You could be liable for any and all of our obligations as if you were a generalpartner if a court or government agency were to determine that: ·we were conducting business in a state but had not complied with that particular state’s partnership statute; or ·your right to act with other unitholders to remove or replace our general partner, to approve some amendments to ourpartnership agreement or to take other actions under our partnership agreement constitute “control” of our business. Unitholders may have liability to repay distributions that were wrongfully distributed to them. Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. UnderSection 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make adistribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law 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. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourseto the partnership are counted for purposes of determining whether a distribution is permitted. The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate 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 our general partner’s board of directors or to establish a compensation committeeor a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded toinvestors in certain corporations that are subject to all of the NYSE corporate governance requirements. Please readPart III, Item 10 (“Directors, Executive Officers and Corporate Governance”). Pursuant to certain federal securities laws, our independent registered public accounting firm will not be required to attestto the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes Oxley Act of2002 for so long as we are an emerging growth company. We are required to disclose changes made in our internal control over financial reporting on a quarterly basis, and we arerequired to assess the effectiveness of our controls annually. However, for as long as we are an “emerging growth company”under federal securities laws, our independent registered public accounting firm will not be required to attest to theeffectiveness of our internal control over financial reporting pursuant to Section 404. We will be an emerging growthcompany until the end of the fiscal year ending December 31, 2018. Even if we conclude that our internal control overfinancial reporting is effective, our independent registered public accounting firm may still decline to attest to ourassessment or may issue a report that is qualified if it is not satisfied with our controls or the level at which our controls aredocumented, designed, operated or reviewed, or if it interprets the relevant requirements differently from us. 31 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 the common units depends largely on our being treated asa 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. Our 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 minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect theimpact of that law on us. 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 Revised Texas Franchise Tax each year at a maximum effective rate of 0.75% of our “margin”, as defined in the law,apportioned to Texas in the prior year. Imposition of any similar taxes by any other state may substantially reduce the cashavailable for distribution 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 interpretation at any time. From time totime, members of the U.S. Congress propose and consider such substantive changes to the existing federal income tax lawsthat affect publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal wouldhave eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations uponwhich we rely for our treatment as a partnership for U.S. federal income tax purposes. In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within themeaning of Section 7704 of the Code (the “Final Regulations”) were published in the Federal Register. The FinalRegulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We donot believe the Final Regulations affect our ability to be treated as a partnership for U.S. federal income tax purposes. 32 Table of ContentsHowever, any modification to the federal income tax laws may be applied retroactively and could make it more difficultor impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for federalincome tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted.Any similar or future legislative changes could negatively impact the value of an investment in our common units. You areurged to consult with your own tax advisor with respect to the status of regulatory or administrative developments andproposals and their potential 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 our 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, ourgeneral 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 our 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,33 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 a 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. Further, with respect to taxable years beginning after December 31, 2017, a tax-exemptentity with more than one unrelated trade or business (including by attribution from investment in a partnership such as oursthat is engaged in one or more unrelated trade or business) is required to compute the unrelated business taxable income ofsuch tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any netoperating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exemptentities to utilize losses from an investment in our partnership to offset unrelated business taxable income from anotherunrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our commonunits.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 U.S. on income effectivelyconnected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gainfrom the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result,distributions to a Non-U.S. unitholder will be subject to withholding at the highest applicable34 Table of Contentseffective 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 will treat each purchaser of 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 the 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 prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors andtransferees of our units each month based upon the ownership of our units on the first day of each month, instead of on thebasis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocationof items of income, gain, loss and deduction among our unitholders. We prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors andtransferees 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 certain deductionsfor depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion ofthe general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the AllocationDate. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specificallyauthorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required tochange 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 as having disposed of the loanedcommon units, he may no longer be treated for federal income tax purposes as a partner with respect to those common unitsduring the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition.Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units maynot be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could befully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognitionfrom a securities loan are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerageaccount agreements to prohibit their brokers from borrowing their common units. 35 Table of ContentsWe have adopted certain valuation methodologies in determining unitholder’s allocations of income, gain, loss anddeduction. The IRS may challenge these methods or the resulting allocations, and such a challenge could adversely affectthe 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 in several states, many of which currently impose a personal income tax on individuals.Many of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand ourbusiness, we may control assets or conduct business in additional states or foreign jurisdictions that impose a personalincome tax. It is your responsibility to file all foreign, federal, state and local tax returns. Risks Related to the CDM Acquisition Our pending acquisition of CDM may not be consummated. Our pending acquisition of CDM is expected to close in the first half of 2018 and is subject to closing conditions. Ifthese conditions are not satisfied or waived, the acquisition will not be consummated. If the closing of the acquisition issubstantially delayed or does not occur at all, we may not realize the anticipated benefits of the acquisition fully or at all.Certain of the conditions remaining to be satisfied include: ·the continued accuracy of the representations and warranties contained in the Contribution Agreement; ·the performance by each party of its obligations under the Contribution Agreement; and ·the absence of any order from any governmental authority that enjoins or otherwise prohibits, or of any law beingenacted which would enjoin or prohibit, the consummation of the transactions contemplated in the ContributionAgreement. In addition, the Contribution Agreement may be terminated by mutual written consent of the parties or by either us orETP (i) if the acquisition has not closed on or before June 30, 2018 (subject to a 90 day extension by either party if theregulatory approvals have not then been obtained or certain other conditions have not been satisfied) (the “Outside Date”),(ii) if the other has breached its obligations under the Contribution Agreement, which breaches have not been cured within30 days, (iii) if any order from any governmental authority permanently prohibiting the consummation of the transactionscontemplated thereby has become final and non-appealable or (iv) if the GP Purchase Agreement is terminated in accordancewith its terms.36 Table of Contents The closing of the CDM Acquisition is not subject to a financing condition and the Bridge Loans do not backstop theequity portion of the purchase price. The closing of the CDM Acquisition is not subject to a financing condition; however, the Series A Purchase Agreementcontains a condition to closing that we will have increased the aggregate commitments under our revolving credit facility to(or entered into a similar revolving facility with minimum aggregate commitments of) at least $1.3 billion. The Series APurchase Agreement, the proceeds of which are to fund a portion of the purchase price of the CDM Acquisition, and theBridge Loans, which is available to backstop a portion of the CDM Acquisition purchase price that we expect to fund withthe net proceeds of other debt financing, is each subject to certain closing conditions. Furthermore, the Bridge Commitmentdoes not backstop the equity portion of the purchase price. The Bridge Commitment will expire upon the earliest to occur of(1) the Outside Date as defined in the Contribution Agreement (as the same may be extended thereunder), (2) theconsummation of the CDM Acquisition without use of the Bridge Loans, (3) the termination of the Contribution Agreementin accordance with its terms or (4) September 30, 2018. Although obtaining the equity or debt financing is not a condition tothe completion of the CDM Acquisition, our failure to have sufficient funds available to pay the purchase price is likely toresult in the failure of the CDM Acquisition to be completed or could require us to sell assets in order to satisfy ourobligations to close. The representations, warranties, and indemnifications by ETP are limited in the Contribution Agreement and our diligenceof CDM may not identify all material matters related to CDM; as a result, the assumptions on which our estimates of futureresults of CDM’s business have been based may prove to be incorrect in a number of material ways, resulting in us notrealizing the expected benefits of the CDM Acquisition. The representations and warranties by ETP are limited in the Contribution Agreement and our diligence into CDM’sbusiness may not identify all material matters related to CDM. In addition, the Contribution Agreement does not provide anyindemnities other than those described therein. As a result, the assumptions on which our estimates of future results of CDM’sbusiness have been based may prove to be incorrect in a number of material ways, resulting in us not realizing our expectedbenefits of the CDM Acquisition, including anticipated increased cash flow. Financing the CDM Acquisition will substantially increase our indebtedness. We may not be able to obtain debt financingfor the acquisition on expected or acceptable terms, which would make the acquisition less accretive. We intend to finance the CDM Acquisition and related fees and expenses with the proceeds of the issuance of debt andequity, including the private placement of Preferred Units, and, to the extent necessary or desirable, with borrowing under ourrevolving credit facility, other debt financing, borrowings under the Bridge Loans, and/or cash on hand. After completion ofthe CDM Acquisition, we expect our total outstanding indebtedness will increase from approximately $782.9 million as ofDecember 31, 2017 to approximately $1.6 billion. The increase in our indebtedness may reduce our flexibility to respond tochanging business and economic conditions or to fund capital expenditures or working capital needs. We intend to raise long term debt in advance of closing of the CDM Acquisition. The assumptions underlying ourestimate that the CDM Acquisition will be accretive to our distributable cash flow includes assumptions about the interestrate we will be able to obtain in connection with such long term debt. We may not be able to obtain debt financing for theacquisition on expected or acceptable terms, which would make the acquisition less accretive than anticipated. The CDM Acquisition could expose us to additional unknown and contingent liabilities. The acquisition of CDM could expose us to additional unknown and contingent liabilities. We have performed a certainlevel of due diligence in connection with the CDM Acquisition and have attempted to verify the representations made byETP, but there may be unknown and contingent liabilities related to CDM of which we are unaware. ETP has not agreed toindemnify us for losses or claims relating to the operation of the business or otherwise except to the limited extent describedin the Contribution Agreement. There is a risk that we could ultimately be liable for unknown obligations relating to CDMfor which indemnification is not available, which could materially adversely affect our business, results of operations andcash flow.37 Table of Contents We may have difficulty attracting, motivating and retaining executives and other employees in light of the CDMAcquisition. Uncertainty about the effect of the CDM Acquisition on employees of us or CDM may have an adverse effect on us. Thisuncertainty may impair our ability to attract, retain and motivate personnel until the CDM Acquisition is completed.Employee retention may be particularly challenging during the pendency of the CDM Acquisition, as employees may feeluncertain about their future roles with the combined organization. In addition, we or CDM may have to provide additionalcompensation in order to retain employees. If employees of us or CDM depart because of issues relating to the uncertaintyand difficulty of integration or a desire not to become employees of the combined organization, our ability to realize theanticipated benefits of the CDM Acquisition could be adversely affected. We are subject to business uncertainties and contractual restrictions while the proposed CDM Acquisition is pending,which could adversely affect our business and operations. In connection with the pending CDM Acquisition, it is possible that some customers, suppliers and other persons withwhom we or CDM have business relationships may delay or defer certain business decisions, or might decide to seek toterminate, change or renegotiate their relationship with us or CDM as a result of the CDM Acquisition, which couldnegatively affect our revenue, earnings and cash available for distribution, as well as the market price of our common units,regardless of whether the CDM Acquisition is completed. Under the terms of the Contribution Agreement, we and CDM are each subject to certain restrictions on the conduct ofour businesses prior to completing the CDM Acquisition, which may adversely affect our ability to execute certain of ourbusiness strategies. Such limitations could negatively affect each party’s business and operations prior to the completion ofthe CDM Acquisition. Furthermore, the process of planning to integrate the acquired entity for the post-acquisition periodcan divert management attention and resources and could ultimately have an adverse effect on each party. We will incur substantial transaction-related costs in connection with the CDM Acquisition. We expect to incur a number of non-recurring transaction-related costs associated with completing the CDM Acquisitionand achieving desired synergies. These fees and costs will be substantial. Non-recurring transaction costs include, but are notlimited to, fees paid to legal, financial and accounting advisors, lender and other financing fees, filing fees and printing costs.Additional unanticipated costs may be incurred in the integration of CDM’s business. There can be no assurance that theelimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of theacquired entity, will offset the incremental transaction-related costs over time. Thus, any net benefit may not be achieved inthe near term, the long term or at all. 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, 2017, our headquarters consisted of 12,342 square feet of leased space located at 100 CongressAvenue, Austin, Texas 78701. ITEM 3.Legal Proceedings Please refer to Note 13 of our consolidated financial statements included in this report for a description of our LegalProceedings. 38 Table of Contents ITEM 4.Mine Safety Disclosures None. PART II ITEM 5.Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of EquitySecurities Our Partnership Interests As of February 8, 2018, we had outstanding 62,194,405 common units, a 1.2% general partner interest (“General PartnerInterest”) and the IDRs. USA Compression Holdings owns a 100% membership interest in our general partner. As of February8, 2018, USA Compression Holdings owned approximately 40% of our outstanding common units. Our general partnercurrently owns the General Partner Interest in us and all of the IDRs. As discussed below under “Selected Information fromOur Partnership Agreement—General Partner Interest and IDRs,” the IDRs represent the right to receive increasingpercentages, up to a maximum of 48%, of the cash we distribute from operating surplus (as defined below) in excess of$0.4888 per unit per quarter. Our common units, which represent limited partner interests in us, are listed on the New YorkStock Exchange (“NYSE”) under the symbol “USAC.” The following table sets forth high and low sales prices per common unit and cash distributions per common unit tocommon unitholders for the periods indicated. The last reported sales price for our common units on February 8, 2018, was$17.47. Cash Distribution Price Range Declared Per Period High Low CommonUnit Date Paid First Quarter 2016 $11.89 $7.03 $0.525 May 13, 2016 Second Quarter 2016 $16.42 $10.50 $0.525 August 12, 2016 Third Quarter 2016 $18.90 $14.02 $0.525 November 14, 2016 Fourth Quarter 2016 $19.33 $15.41 $0.525 February 14, 2017 First Quarter 2017 $19.78 $16.13 $0.525 May 12, 2017 Second Quarter 2017 $17.85 $14.30 $0.525 August 11, 2017 Third Quarter 2017 $17.84 $14.55 $0.525 November 10, 2017 Fourth Quarter 2017 $17.64 $15.48 $0.525 February 14, 2018 Holders At the close of business on February 8, 2018, based on information received from the transfer agent of the common units,we had 54 holders of record of our common units. The number of record holders does not include holders of common units in“street names” or persons, partnerships, associations, corporations or other entities identified in security position listingsmaintained by depositories. Selected Information from our Partnership Agreement Set forth below is a summary of the significant provisions of our partnership agreement that relate to available cash andthe General Partner Interest and the IDRs. Available Cash Our 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. Our partnership agreement generally defines available cash, foreach quarter, as cash on hand at the end of a quarter plus cash on hand resulting from working capital39 Table of Contentsborrowings made after the end of the quarter less the amount of reserves established by our general partner to provide for theproper conduct of our business, comply with applicable law, our revolving credit facility or other agreements; and providefunds for distributions to our unitholders for any one or more of the next four quarters. Working capital borrowings areborrowings made under a credit facility, commercial paper facility or other similar financing arrangement, and in all cases areused solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay suchborrowings within twelve months from sources other than working capital borrowings. General Partner Interest and IDRs Our partnership agreement provides that our general partner is entitled to its General Partner Interest of all distributionsthat we make. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to usto maintain its General Partner Interest if we issue additional units. Our general partner’s General Partner Interest, and thepercentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in thefuture (other than the issuance of common units upon a reset of the IDRs) and our general partner does not contribute aproportionate amount of capital to us in order to maintain its General Partner Interest. Our partnership agreement does notrequire that our general partner fund its capital contribution with cash and our general partner may fund its capitalcontribution by the contribution to us of common units or other property. The IDRs represent the right to receive increasing percentages (13.0%, 23.0% and 48.0%) of quarterly distributions ofavailable cash from operating surplus after the target distribution levels have been achieved. Our general partner currentlyholds the IDRs, but may transfer these rights separately from its General Partner Interest without the consent of our limitedpartners. On January 15, 2018, our general partner entered into an agreement pursuant to which it agreed to, among other things,convert the General Partner Interest into a non-economic general partner interest and cancel the IDRs. The transactions areexpected to close in the first half of 2018. See Item 1 (“Business—Recent Developments”) for more information. 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 for each of theyears in the five-year period ended December 31, 2017, which has been derived from our audited consolidated financialstatements. The following information should be read together with Management’s Discussion and Analysis of FinancialCondition and Results 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 of40 Table of ContentsOperations” contained in Part II, Item 7 of this report. In addition, a discussion of the risk factors that could affect ourbusiness and future financial condition and results of operations is included under Part I, Item 1A (“Risk Factors”) of thisreport. Additionally, Note 2 – Summary of Significant Accounting Policies and Note 13 – Commitments and Contingenciesunder Part II, Item 8 (“Financial Statements and Supplementary Data”) of this report provide descriptions of areas whereestimates and judgments and contingent liabilities could result in different amounts being recognized in our accompanyingconsolidated financial statements. We believe that investors benefit from having access to the same financial measures utilized by management. Thefollowing table includes the non-GAAP financial measure of gross operating margin, Adjusted EBITDA and DistributableCash Flow (or “DCF”). For definitions of gross operating margin, Adjusted EBITDA and DCF, and41 Table of Contentsreconciliations of such measures to their most directly comparable financial measures calculated and presented in accordancewith GAAP, please read “Non-GAAP Financial Measures” below. Year Ended December 31, 2017 2016 2015 2014 2013 (in thousands, except per unit amounts) Revenues: Contract operations $264,315 $246,950 $263,816 $217,361 $150,360 Parts and service 15,907 18,971 6,729 4,148 2,558 Total revenues 280,222 265,921 270,545 221,509 152,918 Costs of operations, exclusive of depreciation andamortization: Cost of operations 92,591 88,161 81,539 74,035 48,097 Gross operating margin (1) 187,631 177,760 189,006 147,474 104,821 Other operating and administrative costs and expenses: Selling, general and administrative 47,483 44,483 40,950 38,718 27,587 Depreciation and amortization 98,603 92,337 85,238 71,156 52,917 Loss (gain) on disposition of assets (507) 772 (1,040) (2,233) 284 Impairment of compression equipment 4,972 5,760 27,274 2,266 203 Impairment of goodwill — — 172,189 — — Total other operating and administrative costs and expenses 150,551 143,352 324,611 109,907 80,991 Operating income (loss) 37,080 34,408 (135,605) 37,567 23,830 Other income (expense): Interest expense, net (25,129) (21,087) (17,605) (12,529) (12,488) Other 27 35 22 11 9 Total other expense (25,102) (21,052) (17,583) (12,518) (12,479) Income (loss) before income tax expense 11,978 13,356 (153,188) 25,049 11,351 Income tax expense 538 421 1,085 103 280 Net income (loss) 11,440 12,935 (154,273) 24,946 11,071 Adjusted EBITDA (1) $155,703 $146,648 $153,572 $114,409 $81,130 DCF (1) $118,330 $118,329 $120,850 $85,927 $56,210 Basic and diluted net income (loss) per common unit: $0.16 $0.27 $(3.15) $0.60 $0.32 Cash distributions declared per common unit $2.10 $2.10 $2.09 $2.01 $1.73 Other Financial Data: Capital expenditures $129,490 $48,665 $265,798 $404,429 $175,393 Cash flows provided by (used in): Operating activities $124,644 $103,697 $117,401 $101,891 $68,190 Investing activities $(105,231) $(50,831) $(278,158) $(380,523) $(153,946) Financing activities $(19,431) $(52,808) $160,758 $278,631 $85,756 Balance Sheet Data (at period end): Working capital (2) $3,118 $16,558 $(8,455) $(44,064) $(24,177) Total assets $1,492,087 $1,472,412 $1,509,771 $1,516,482 $1,185,884 Long-term debt $782,902 $685,371 $729,187 $594,864 $420,933 Partners' equity $633,853 $729,517 $718,288 $839,520 $707,727 (1)Please refer to “—Non-GAAP Financial Measures” section below.(2)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. We define Adjusted EBITDA as EBITDA plus impairment of compression equipment, impairment of goodwill,interest income on capital lease, unit-based compensation expense, management fees, severance charges, certain transactionfees, loss (gain) on disposition of assets and other. We view Adjusted EBITDA as one of our primary management tools, andwe track this item on a monthly basis both as an absolute amount and as a percentage of revenue compared to the priormonth, year-to-date, prior year and to budget. Adjusted EBITDA is used as a supplemental financial measure by ourmanagement 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 provides 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. Expense related to unit-based compensation expenseassociated with equity awards to employees is also a necessary component of our business. Therefore, measures that excludethese elements have material limitations. To compensate for these limitations, we believe that it is important to consider bothnet income (loss) and net cash provided by operating activities determined under GAAP, as well as43 Table of ContentsAdjusted EBITDA, to evaluate our financial performance and our liquidity. Our Adjusted EBITDA excludes some, but notall, items that affect net income (loss) and net cash provided by operating activities, and these measures may vary amongcompanies. Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing thecomparable GAAP measures, understanding the differences between the measures and incorporating this knowledge intomanagement’s decision making processes. 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, 2017 2016 2015 2014 2013Net income (loss) $11,440 $12,935 $(154,273) $24,946 $11,071Interest expense, net 25,129 21,087 17,605 12,529 12,488Depreciation and amortization 98,603 92,337 85,238 71,156 52,917Income tax expense 538 421 1,085 103 280EBITDA $135,710 $126,780 $(50,345) $108,734 $76,756Impairment of compression equipment (1) 4,972 5,760 27,274 2,266 203Impairment of goodwill (2) — — 172,189 — —Interest income on capital lease 1,610 1,492 1,631 1,274 —Unit-based compensation expense (3) 11,708 10,373 3,863 3,034 1,343Riverstone management fee (4) — — — — 49Transaction expenses for acquisitions (5) 1,406 894 — 1,299 2,142Severance charges 314 577 — — —Other 490 — — — —Loss (gain) on disposition of assets and other (507) 772 (1,040) (2,198) 637Adjusted EBITDA $155,703 $146,648 $153,572 $114,409 $81,130Interest expense, net (25,129) (21,087) (17,605) (12,529) (12,488)Income tax expense (538) (421) (1,085) (103) (280)Interest income on capital lease (1,610) (1,492) (1,631) (1,274) —Non-cash interest expense and other 2,186 2,108 1,702 1,189 1,839Riverstone management fee — — — — (49)Transaction expenses for acquisitions (1,406) (894) — (1,299) (2,142)Severance charges (314) (577) — — —Other (490) — — — —Changes in operating assets and liabilities (3,758) (20,588) (17,552) 1,498 180Net cash provided by operating activities $124,644 $103,697 $117,401 $101,891 $68,190(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 we recognized for the year ended December 31, 2015, please refer to Item 7(“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Goodwill Impairment Assessments”).(3)For the years ended December 31, 2017, 2016, 2015, 2014 and 2013, unit-based compensation expense included $2.5 million, $2.8million, $0.9 million, $0.5 million and $0, respectively, of cash payments related to quarterly payments of distribution equivalent rights onoutstanding phantom unit awards and $0.4 million, $0.1 million, $0.2 million, $0.3 million and $0, respectively, related to the cash portionof any settlement of phantom unit awards upon vesting. The remainder of the unit-based compensation expense for 2017, 2016, 2015 and2014 is related to non-cash adjustments to the unit-based compensation liability, and for 2013 is related to the non-cash amortization ofunit-based compensation in equity.(4)Represents management fees paid to Riverstone for services performed during 2013. We are no longer responsible for these feesfollowing the closing of our initial public offering in January 2013. As such, we believe it is useful to investors to view our resultsexcluding these fees.(5)Represents certain transaction expenses related to potential acquisitions and other items. We believe it is useful to investors to excludethese fees. 44 Table of ContentsDistributable Cash Flow We define DCF as net income (loss) plus non-cash interest expense, non-cash income tax expense, depreciation andamortization expense, unit-based compensation expense, impairment of compression equipment, impairment of goodwill,certain transaction fees, severance charges, loss (gain) on disposition of assets, proceeds from insurance recovery and other,less maintenance capital expenditures. We believe DCF is an important measure of operating performance because it allows management, investors and othersto compare basic cash flows we generate (prior to any retained cash reserves established by our general partner and the effectof the DRIP) to the cash distributions we expect to pay our unitholders. Using DCF, management can quickly compute thecoverage ratio of estimated cash flows to planned cash distributions. 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. Expense related to unit-basedcompensation expense associated with equity awards to employees is also a necessary component of our business. Therefore,measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it isimportant to consider both net income (loss) and net cash provided by operating activities determined under GAAP, as wellas DCF, to evaluate our financial performance and our liquidity. Our DCF excludes some, but not all, items that affect netincome (loss) and net cash provided by operating activities, and these measures may vary among companies. Managementcompensates for the limitations of DCF as an analytical tool by reviewing the comparable GAAP measures, understanding thedifferences between the measures and incorporating this knowledge into management’s decision making processes. 45 Table of ContentsThe 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, 2017 2016 2015 2014 2013Net income (loss) $11,440 $12,935 $(154,273) $24,946 $11,071Plus: Non-cash interest expense 2,186 2,108 1,702 1,224 2,201Plus: Non-cash income tax expense 278 239 874 — —Plus: Depreciation and amortization 98,603 92,337 85,238 71,156 52,917Plus: Unit-based compensation expense (1) 11,708 10,373 3,863 3,034 1,343Plus: Impairment of compression equipment 4,972 5,760 27,274 2,266 203Plus: Impairment of goodwill — — 172,189 — —Plus: Transaction expenses for acquisitions (2) 1,406 894 — 1,299 2,142Plus: Severance charges 314 577 — — —Plus: Other 490 — — — —Plus: Loss (gain) on disposition of assets and other (507) 772 (1,040) (2,198) 637Plus: Proceeds from insurance recovery — 73 1,157 — —Less: Maintenance capital expenditures (3) (12,560) (7,739) (16,134) (15,800) (14,304)DCF $118,330 $118,329 $120,850 $85,927 $56,210Plus: Maintenance capital expenditures 12,560 7,739 16,134 15,800 14,304Plus: Change in working capital (3,758) (20,588) (17,552) 1,498 180Less: Transaction expenses for acquisitions (1,406) (894) — (1,299) (2,142)Less: Other (1,082) (889) (2,031) (35) (362)Net cash provided by operating activities $124,644 $103,697 $117,401 $101,891 $68,190(1)For the years ended December 31, 2017, 2016, 2015, 2014 and 2013, unit-based compensation expense includes $2.5 million, $2.8million, $0.9 million, $0.5 million and $0, respectively, of cash payments related to quarterly payments of distribution equivalent rights onphantom unit awards and $0.4 million, $0.1 million, $0.2 million, $0.3 million and $0, respectively, related to the cash portion of anysettlement of phantom units upon vesting. The remainder of the unit-based compensation expense for 2017, 2016, 2015 and 2014 isrelated to non-cash adjustments to the unit-based compensation liability, and for 2013 is related to the non-cash amortization of unit-basedcompensation in equity.(2)Represents certain transaction expenses related to potential acquisitions and other items. We believe it is useful to investors to excludethese fees.(3)Reflects maintenance capital expenditures for the period presented. Maintenance capital expenditures are capital expenditures made tomaintain the operating capacity of our assets and extend their useful lives, to 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 less cash distributions to be paid to our general partner and IDRs in respect ofsuch period, divided by distributions declared to limited partner unitholders in respect of such period. Cash Coverage Ratiois defined as DCF less cash distributions to be paid to our general partner and IDRs in respect of such period, divided by cashdistributions expected to be paid to limited partner unitholders in respect of such period, after taking into account the non-cash impact of the DRIP. We believe DCF Coverage Ratio and Cash Coverage Ratio are important measures of operatingperformance because they allow management, investors and others to gauge our ability to pay cash distributions to limitedpartner unitholders using the cash flows that we generate. Our DCF Coverage Ratio and Cash Coverage Ratio as presentedmay not be comparable to similarly titled measures of other companies. 46 Table of ContentsThe following table summarizes our coverage ratios for the periods presented (dollars in thousands): Year Ended December 31, 2017 2016 2015 2014 2013DCF $118,330 $118,329 $120,850 $85,927 $56,210General partner interest in DCF 3,007 2,866 2,658 1,947 1,188Pre-IPO DCF — — — — 2,323DCF attributable to limited partner interest $115,323 $115,463 $118,192 $83,980 $52,699 Distributions for DCF coverage ratio (1) $129,657 $115,881 $101,266 $85,098 $55,961 Distributions reinvested in the DRIP (2) 16,592 24,441 55,489 52,556 36,694 Distributions for Cash Coverage Ratio (3) $113,065 $91,440 $45,777 $32,542 $19,267 DCF Coverage Ratio (4) 0.89 1.00 1.17 0.99 0.94 Cash Coverage Ratio (5) 1.02 1.26 2.58 2.58 2.74(1)Represents distributions to the holders of our limited partnership units, after giving effect to the weighted average common unitsoutstanding, due to our December 2016, September 2015 and May 2014 equity offerings and an acquisition we completed in August2013 for the years ended December 31, 2016, 2015, 2014 and 2013, as applicable. Without giving effect to the weighted average commonunits outstanding due to our December 2016, September 2015 and May 2014 equity offerings and an acquisition we completed in August2013 for the years ended December 31, 2016, 2015, 2014 and 2013, actual distributions to holders of our limited partnership units were$118.1 million, $103.1 million, $86.5 million and $58.2 million, respectively.(2)Represents distributions to holders enrolled in the DRIP as of the record date for each period.(3)Represents cash distributions declared for our limited partnership units not participating in the DRIP, after giving effect to the weightedaverage of limited partnership units outstanding for each period due to our December 2016, September 2015 and May 2014 equityofferings and an acquisition we completed in August 2013 for the years ended December 31, 2016, 2015, 2014 and 2013, as applicable.(4)For the years ended December 31, 2016, 2015, 2014 and 2013, the DCF Coverage Ratio based on actual limited partnership unitsoutstanding as of the respective record dates was 0.98x, 1.15x, 0.97x and 0.91x, respectively.(5)For the years ended December 31, 2016, 2015, 2014 and 2013, the Cash Coverage Ratio based on actual limited partnership unitsoutstanding as of the respective record dates was 1.23x, 2.48x, 2.46x and 2.74x, respectively. 47 Table of Contents ITEM 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations The following discussion and analysis of our financial condition and results of operations should be read 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”). 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. The demand for our services is driven by the domestic production of natural gas and crude oil; as such,we have 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 the flexibility of our compression units positions us well to meet these changing operatingconditions. While our business focuses largely on compression services serving infrastructure applications, includingcentralized natural gas gathering systems and processing facilities, which utilize large horsepower compression units,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, thus reducing the hydrostatic pressure and allowing 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. General Trends and Outlook While our business does not have direct exposure to commodity prices, the general activity levels of our customers canbe affected by commodity prices. A significant amount of our assets are utilized in natural gas infrastructure applications,primarily in centralized natural gas gathering systems and processing facilities. Given the project nature of these applicationsand long-term investment horizon of our customers, we have generally experienced stability in rates and higher sustainedutilization rates relative to other businesses more tied to drilling activity and wellhead economics. In addition to assetsutilized in infrastructure applications, a small portion of our fleet is used in connection with crude oil production usinghorizontal drilling techniques. The relative increase in, and stabilization of, commodity prices during the second-half of 2016 and throughout 2017 hasallowed our customers to increase their capital budgets in regards to crude oil exploration and production activities and thebuild-out of large-scale natural gas infrastructure projects, particularly in areas with favorable economics. These projectsincreased demand for our compression services throughout 2017 as we saw our horsepower utilization increase from 87.1% atDecember 31, 2016 to 94.8% at December 31, 2017, while also increasing the horsepower in our fleet from 1,720,547 atDecember 31, 2016 to 1,799,781 at December 31, 2017. The U.S. Energy Information Administration January 2018 Short-Term Energy Outlook (“EIA Outlook”) expects drynatural gas production to rise by 6.9 billion cubic feet per day (“Bcf/day”) in 2018 and by 2.6 Bcf/day in 2019. If achieved,the forecasted 6.9 Bcf/day increase in 2018 would be the highest on record for any single year. The EIA Outlook expectsgrowth to be concentrated in Appalachia’s Marcellus and Utica regions, along with the Permian Basin region, all regions inwhich we provide compression services. Much of the expected increase in natural gas production is the result of increasingpipeline takeaway capacity out of the Marcellus and Utica producing regions to end-use markets. Additionally, EIA Outlookprojects liquefied natural gas (“LNG”) gross exports will average 3.0 Bcf/day in 2018, up from 1.9 Bcf/day in 2017. The EIAOutlook expects U.S. liquefaction capacity will continue to expand as several new projects are expected to enter serviceduring 2018 and 2019. Also from the EIA Outlook, natural gas pipeline exports to Mexico through October increased by 0.4Bcf/day in 2017 compared to the same period in 2016. A relatively low natural48 Table of Contentsgas export price, rising demand from Mexico’s power sector, and increased pipeline capacity in both the U.S. and Mexicohave led to increased exports. 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 2018 although we cannot predict any possible changes in suchdemand with reasonable certainty. We intend to prudently deploy capital for new compressor units in 2018. We have already entered into commitments topurchase most of our large horsepower compressor units in 2018, as the lead time to build these units is approximately oneyear or shorter. Most of our 2018 purchases of large horsepower compressor units are already committed to customers orunder contract with customers due to the high demand and limited supply of these units. The EIA Outlook forecasts total U.S. crude oil production to average 10.3 million barrels per day in 2018, up 1.0 millionbarrels per day from 2017. If achieved, forecasted 2018 production would be the highest annual average on record,surpassing the previous record of 9.6 million barrels per day set in 1970. According to the EIA Outlook, in 2019, crude oilproduction is forecast to rise to an average of 10.8 million barrels per day and the Permian region is expected to produce 3.6million barrels per day of crude oil by the end of 2019 which would represent about 32% of U.S. crude oil production thatyear. With the large geographic area of the Permian region and stacked plays, the EIA Outlook estimates that operators cancontinue to develop multiple tight oil layers and increase production, even with sustained crude oil prices lower than $50 perbarrel. As of February 8, 2018, the WTI crude oil spot price was $61.15 per barrel. WTI crude oil spot prices are forecastwithin the EIA Outlook to average $56 per barrel in 2018 and $57 per barrel in 2019. Daily and monthly average crude oilprices could vary significantly from annual average forecasts due to global economic developments and geopolitical eventsin the coming months that could have the potential to push oil prices higher or lower than forecast. Uncertainty remainsregarding the duration of, and adherence to, the current Organization of the Petroleum Exporting Countries (“OPEC”)production cuts, which could influence prices in either direction. We believe the relative increase in, and stabilization of, crude oil prices in the second half of 2016 and throughout 2017has led to an increase in drilling activity, and combined with the continued development of horizontal drilling technology,operators are able to produce new volumes of crude oil from tight, high pressure reservoirs. Due in part to these higher initialpressures, the increase in demand for gas lift compression in these new areas of drilling could be delayed until reservoirpressures decline to a point where compression is beneficial to the economics of a particular well or basin. However, we haveexperienced an increase in the demand for our smaller horsepower units engaged in gas lift applications and expect that tocontinue. 49 Table of ContentsOperating Highlights The following table summarizes certain horsepower and horsepower utilization percentages for the periods presented. Year Ended December 31, Percent Change Operating Data: 2017 2016 2015 2017 2016 Fleet horsepower (at period end) (1) 1,799,781 1,720,547 1,712,196 4.6%0.5%Total available horsepower (at period end) (2) 1,950,301 1,730,547 1,712,196 12.7%1.1%Revenue generating horsepower (at period end) (3) 1,624,377 1,387,073 1,424,537 17.1%(2.6)%Average revenue generating horsepower (4) 1,505,657 1,377,966 1,408,689 9.3%(2.2)%Average revenue per revenue generating horsepower permonth (5) $15.07 $15.41 $15.90 (2.2)%(3.1)%Revenue generating compression units (at period end) 2,830 2,552 2,737 10.9%(6.8)%Average horsepower per revenuegenerating compression unit (6) 554 534 517 3.7%3.3%Horsepower utilization (7): At period end 94.8% 87.1% 89.2%8.8%(2.4)%Average for the period (8) 92.0% 87.4% 90.5%5.3%(3.4)%(1)Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order). As of December 31,2017, we had 147,500 and 5,520 horsepower on order for delivery during 2018 and 2019, respectively.(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 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 under contractbut is not yet generating revenue, and (c) horsepower not yet in our fleet that is under contract, not yet generating revenue and that issubject to a purchase order, divided by (ii) total available horsepower less idle horsepower that is under repair. Horsepower utilizationbased on revenue generating horsepower and fleet horsepower was 90.3%, 80.6% and 83.2% at December 31, 2017, 2016 and 2015,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 85.9%, 80.3% and 85.1% for the years endedDecember 31, 2017, 2016 and 2015, respectively. The 4.6% increase in fleet horsepower as of December 31, 2017 over the fleet horsepower as of December 31, 2016 wasattributable to new compression units added to our fleet to meet then expected demand by new and current customers forcompression services. The 17.1% increase in revenue generating horsepower as of December 31, 2017 over December 31,2016 was primarily due to organic growth in our active fleet and redeployment of previously idle equipment. The 3.7%increase in average horsepower per revenue generating compression unit as of December 31, 2017 over December 31, 2016was primarily due to the addition of large horsepower compression units in the operating fleet. The 2.2% decrease in averagerevenue per revenue generating horsepower per month for the year ended December 31, 2017 over December 31, 2016 wasprimarily due to (1) reduced pricing in the small horsepower portion of our fleet in the current period and (2) an increase inthe average horsepower per revenue generating compression unit in the current period, resulting from an increase in thenumber of large horsepower compression units which typically generate lower average revenue per revenue generatinghorsepower than do small horsepower compression units. 50 Table of ContentsThe 0.5% increase in fleet horsepower as of December 31, 2016 over the fleet horsepower as of December 31, 2015 wasattributable to new compression units added to our fleet to meet then expected demand by new and current customers forcompression services. The 2.6% decrease in revenue generating horsepower as of December 31, 2016 over December 31,2015 was primarily due to an increase in the amount of time required to contract services for new compression units and anincrease in the amount of compression units returned to us. The 3.3% increase in average horsepower per revenue generatingcompression unit as of December 31, 2016 over December 31, 2015 was primarily due to the addition of large horsepowercompression units in the operating fleet and the decline in utilization of small horsepower units over the year endedDecember 31, 2016. The 3.1% decrease in average revenue per revenue generating horsepower per month for the year endedDecember 31, 2016 over December 31, 2015 was primarily due to (1) reduced pricing in the small horsepower portion of ourfleet in the current period and (2) an increase in the average horsepower per revenue generating compression unit in thecurrent period, resulting from an increase in the number of large horsepower compression units which typically generatelower average revenue per revenue generating horsepower than do small horsepower compression units. Average horsepower utilization increased to 92.0% during the year ended December 31, 2017 compared to 87.4% duringthe year ended December 31, 2016. The 4.6% increase in average horsepower utilization was primarily attributable to thefollowing changes as a percentage of total available horsepower: (1) a 6.9% increase in horsepower that is under contract butnot yet generating revenue and (2) a 1.9% decrease in our average fleet of compression units returned to us not yet undercontract, offset by (3) a 4.0% decrease in idle horsepower under repair, which is excluded from the average horsepowerutilization calculation until such repair is complete. We believe the increase in average horsepower utilization is the resultof increased demand for our services commensurate with increased operating activity in the oil and gas industry. The abovenoted fluctuation in utilization components also describes the changes in period end horsepower utilization as of December31, 2017 compared to December 31, 2016. Average horsepower utilization decreased to 87.4% during the year ended December 31, 2016 compared to 90.5%during the year ended December 31, 2015. The 3.1% decrease in average horsepower utilization was primarily attributable tothe following changes as a percentage of total available horsepower: (1) a 3.7% increase in our average fleet of compressionunits returned to us not yet under contract and (2) a 1.0% decrease in horsepower that was on-contract or pending-contractbut not yet active. The decrease in average horsepower utilization was offset by a 2.6% increase in idle horsepower underrepair, which is excluded from the average horsepower utilization calculation until such repair is complete. We believe thedecrease in average horsepower utilization was the result of a delay in planned projects of certain of our customers, continuedoptimization of existing compression service requirements by our customers and our selective pursuit of what we deemed tobe the most attractive opportunities. The above noted fluctuation in utilization components also describes the changes inperiod end horsepower utilization, except that we experienced a 1.2% increase in horsepower that was on-contract orpending-contract but not yet active as of December 31, 2016 compared to December 31, 2015. Average horsepower utilization based on revenue generating horsepower and fleet horsepower increased to 85.9% duringthe year ended December 31, 2017 compared to 80.3% during the year ended December 31, 2016. The 5.6% increase wasprimarily attributable to the following changes as a percentage of total fleet horsepower: (1) a 4.0% decrease in idlehorsepower under repair and (2) a 2.0% decrease in our average idle fleet composed of new compression units offset by (3) a0.4% increase in our average idle fleet from compression units returned to us. The overall decrease in idle horsepower is theresult of increased demand for our services commensurate with increased operating activity in the oil and gas industry. Thesefactors also describe the variances in period end horsepower utilization based on revenue generating horsepower and fleethorsepower between the year ended December 31, 2017 and the year ended December 31, 2016. Average horsepower utilization based on revenue generating horsepower and fleet horsepower decreased to 80.3% duringthe year ended December 31, 2016 compared to 85.1% during the year ended December 31, 2015. The 4.8% decrease wasprimarily attributable to the following changes as a percentage of total fleet horsepower: (1) a 4.7% increase in our averageidle fleet from compression units returned to us and (2) a 2.6% increase in idle horsepower under repair offset by (3) a 2.4%decrease in our average idle fleet composed of new compression units. The increase in units returned to us is believed to be aresult of our customers’ optimization of their compression service requirements. These51 Table of Contentsfactors also describe the variances in period end horsepower utilization based on revenue generating horsepower and fleethorsepower between the year ended December 31, 2016 and the year ended December 31, 2015. Financial Results of Operations 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 $264,315 $246,950 7.0%Parts and service 15,907 18,971 (16.2)%Total revenues 280,222 265,921 5.4%Costs and expenses: Cost of operations, exclusive of depreciation and amortization 92,591 88,161 5.0%Gross operating margin 187,631 177,760 5.6%Other operating and administrative costs and expenses: Selling, general and administrative 47,483 44,483 6.7%Depreciation and amortization 98,603 92,337 6.8%Loss (gain) on disposition of assets (507) 772 165.7%Impairment of compression equipment 4,972 5,760 (13.7)%Total other operating and administrative costs and expenses 150,551 143,352 5.0%Operating income 37,080 34,408 7.8%Other income (expense): Interest expense, net (25,129) (21,087) 19.2%Other 27 35 (22.9)%Total other expense (25,102) (21,052) 19.2%Income before income tax expense 11,978 13,356 (10.3)%Income tax expense 538 421 27.8%Net income $11,440 $12,935 (11.6)% Contract operations revenue. During 2017, we experienced a year-to-year increase in demand for our compressionservices driven by increased operating activity in natural gas and crude oil production, resulting in a $17.4 million increasein our contract operations revenue. Average revenue generating horsepower increased 9.3% during the year ended December31, 2017 over December 31, 2016 while average revenue per revenue generating horsepower per month decreased from$15.41 for the year ended December 31, 2016 to $15.07 for the year ended December 31, 2017, a decrease of 2.2%,attributable, in part, to reduced pricing in the current period in the small horsepower portion of our fleet. The decrease inaverage revenue per revenue generating horsepower per month was also attributable to the 3.7% increase in the averagehorsepower per revenue generating compression unit in the current period, as large horsepower compression units typicallygenerate lower average monthly revenue per revenue generating horsepower than do small horsepower compression units.Average revenue per revenue generating horsepower per month associated with our compression services provided on amonth-to-month basis did not significantly differ from the average revenue per revenue generating horsepower per monthassociated with our compression services provided under contracts in the primary term. Our contract operations revenue wasnot materially impacted by any renegotiations of our contracts during the period with our customers. Parts and service revenue. Parts and service revenue was earned primarily on the installation of equipment ancillary tocompression operations. The $3.1 million decrease in parts and service revenue was primarily attributable to (1) an $8.3million decrease in revenue associated with installation services offset by (2) a $4.1 million increase in maintenance work onunits at our customers' locations that are outside the scope of our core maintenance activities and (3) a $1.4 million increasein freight and crane charges that are directly reimbursable by our customers. We offer these52 Table of Contentsservices as a courtesy to our customers and the demand fluctuates from period to period based on the varying needs of ourcustomers. Cost of operations, exclusive of depreciation and amortization. The $4.4 million increase in cost of operations wasprimarily attributable to (1) a $7.4 million increase in direct expenses, such as parts and fluids expenses and (2) a $2.4million increase in direct labor expenses offset by (3) a $3.5 million decrease in retail parts and service expenses, which havea corresponding decrease in parts and service revenue, and (4) a $2.7 million decrease in property and other taxes. Theincrease in direct parts, fluids and labor are primarily driven by the increase in average revenue generating horsepower duringthe current period. Gross operating margin. The $9.9 million increase in gross operating margin was primarily due to an increase inrevenues, partially offset by an increase in operating expenses during the year ended December 31, 2017. Selling, general and administrative expense. The $3.0 million increase in selling, general and administrative expensefor the year ended December 31, 2017 was primarily attributable to (1) a $1.3 million increase in unit-based compensationexpense, (2) a $0.8 million increase in bad debt expense, due to a $1.1 million recovery of bad debt expense during the yearended December 31, 2016 compared to a $0.3 million recovery during the year ended December 31, 2017 and (3) $0.5million increase in transaction expenses related to potential acquisitions. Unit-based compensation expense increasedprimarily due to a greater fair value assigned to the 2016 “Performance Units” that are subject to market criteria and whichwere measured using the Monte Carlo simulation model as of December 31, 2017. Depreciation and amortization expense. The $6.3 million increase in depreciation expense was primarily related to anincrease in gross property and equipment balances during the year ended December 31, 2017 compared to gross balancesduring the year ended December 31, 2016. Loss (gain) on disposition of assets. During the year ended December 31, 2017, the $0.5 million gain was primarilyattributable to the sale of select compression equipment. During the year ended December 31, 2016, we abandoned certainassets and incurred a $1.0 million loss. Impairment of compression equipment. The $5.0 million and $5.8 million impairment charge during the yearsended December 31, 2017 and 2016, respectively, were primarily a result of our evaluation of the future deployment of ourcurrent idle fleet under the current market conditions. Our evaluation determined that due to certain performancecharacteristics of the impaired equipment, such as excessive maintenance costs and the inability of the equipment to meetthen-current emission standards without retrofitting, this equipment was unlikely to be accepted by customers under then-current market conditions. As a result of our evaluation during the years ended December 31, 2017 and 2016, we determinedto retire and either sell or re-utilize the key components of 40 and 29 compression units, with a total of approximately 11,000and 15,000 horsepower, respectively, that had been previously used to provide compression services in our business. Interest expense, net. The $4.0 million increase in interest expense, net was primarily attributable to the impact ofan increase in our weighted average interest rate. Our revolving credit facility bore an interest rate of 3.46% and 2.94% atDecember 31, 2017 and 2016, respectively, and a weighted-average interest rate of 3.14% and 2.55% during the years endedDecember 31, 2017 and 2016, respectively. The impact of the increase in interest rate was partially offset by the impact of an$8.9 million decrease in average outstanding borrowings under our revolving credit facility. Average borrowings under thefacility were $734.6 million for the year ended December 31, 2017 compared to $743.5 million for the year endedDecember 31, 2016. Income tax expense. This line item represents the Revised Texas Franchise Tax (“Texas Margin Tax”) and change indeferred tax liability, which is materially consistent between both periods. 53 Table of ContentsYear ended December 31, 2016 compared to the year ended December 31, 2015 The following table summarizes our results of operations for the periods presented (dollars in thousands): Year Ended December 31, Percent 2016 2015 Change Revenues: Contract operations $246,950 $263,816 (6.4)%Parts and service 18,971 6,729 181.9%Total revenues 265,921 270,545 (1.7)%Costs and expenses: Cost of operations, exclusive of depreciation and amortization 88,161 81,539 8.1%Gross operating margin 177,760 189,006 (6.0)%Other operating and administrative costs and expenses: Selling, general and administrative 44,483 40,950 8.6%Depreciation and amortization 92,337 85,238 8.3%Loss (gain) on disposition of assets 772 (1,040) 174.2%Impairment of compression equipment 5,760 27,274 (78.9)%Impairment of goodwill — 172,189 *%Total other operating and administrative costs and expenses 143,352 324,611 (55.8)%Operating income (loss) 34,408 (135,605) 125.4%Other income (expense): Interest expense (21,087) (17,605) 19.8%Other 35 22 59.1%Total other expense (21,052) (17,583) 19.7%Income (loss) before income tax expense 13,356 (153,188) 108.7%Income tax expense 421 1,085 (61.2)%Net income (loss) $12,935 $(154,273) 108.4%* Not meaningful. Contract operations revenue. During 2016, we experienced a year-to-year decrease in demand for our compressionservices driven by decreased operating activity in natural gas and crude oil production and continued optimization ofexisting compression service requirements, resulting in a 2.2% decrease in average revenue generating horsepower and a$16.9 million decrease in our contract operations revenue. Average revenue per revenue generating horsepower per monthdecreased from $15.90 for the year ended December 31, 2015 to $15.41 for the year ended December 31, 2016, a decrease of3.1%, attributable, in part, to reduced pricing in the current period in the small horsepower portion of our fleet. The decreasein average revenue per revenue generating horsepower per month was also attributable to the 3.3% increase in the averagehorsepower per revenue generating compression unit in the current period, as large horsepower compression units generallygenerate lower average monthly revenue per revenue generating horsepower than do small horsepower compression units.Average revenue per revenue generating horsepower per month associated with our compression services provided on amonth-to-month basis was somewhat higher than the average revenue per revenue generating horsepower per monthassociated with our compression services provided under contracts in the primary term due to pressure on service ratesattributable to the small horsepower portion of our fleet. Because the demand for our services is driven primarily byproduction of natural gas, we focus our activities in areas of attractive growth, which are generally found in certain shale andunconventional resource plays, as discussed above under the heading “Overview.” Our contract operations revenue was notmaterially impacted by any renegotiations of our contracts during the period with our customers. Parts and service revenue. Parts and service revenue was earned primarily on the installation of equipment ancillary tocompression operations. During 2016, we recognized $15.7 million of revenue associated with installation services, whichaccounts for the $12.2 million year-over-year increase in parts and service revenue. The remaining component of our partsand service revenue, which was earned primarily on (1) freight and crane charges that are directly reimbursed by ourcustomers, for which we earn little to no margin, and (2) maintenance work on units at our customers’ locations54 Table of Contentsthat are outside the scope of our core maintenance activities, for which we earn lower margins than our contract operations,decreased $3.5 million during the current period. Cost of operations, exclusive of depreciation and amortization. The $6.6 million increase in cost of operations wasprimarily attributable to an $8.3 million increase in retail parts and service expenses, which includes $11.9 million ofadditional costs associated with our installation services. Excluding these costs, retail parts and services expense decreased$3.6 million reflecting a corresponding decrease in this component of parts and services revenue. Additionally during theperiod, we experienced (1) a $2.1 million decrease in direct expenses, such as parts and fluids expenses, (2) a $0.6 milliondecrease in direct labor expenses and (3) a $0.5 million decrease in expenses related to our vehicle fleet, offset by (4) a $1.7million increase in property and other taxes. The decrease in direct parts, fluids, labor and vehicle expenses are primarilydriven by the decrease in average revenue generating horsepower during the current period. Gross operating margin. The $11.2 million decrease in gross operating margin was primarily due to a decrease inrevenues, partially offset by a decrease in operating expenses and the $3.8 million of gross operating margin we earned fromour installation services during the year ended December 31, 2016. Selling, general and administrative expense. The $3.5 million increase in selling, general and administrative expensefor the year ended December 31, 2016 was primarily attributable to a $6.5 million increase in unit-based compensationexpense, partially offset by a $2.9 million decrease in bad debt expense. Unit-based compensation expense increasedprimarily due to (1) the increase in our unit price as of December 31, 2016 compared to December 31, 2015, (2) a greaternumber of outstanding phantom units as of December 31, 2016 compared to December 31, 2015 which resulted from a highernumber of phantom unit grants during 2016 as compared to 2015 (reflecting our sharply lower unit price at the time thegrants were made in 2016 versus our unit price at the time the grants were made in 2015), and (3) a greater number ofphantom units outstanding on which distribution equivalent rights were paid as of each record date during the comparableperiods. The decrease in bad debt expense was due primarily to a $1.1 million decrease in allowance for doubtful accountsduring the year ended December 31, 2016 due in part to collections on accounts that had previously been reserved during theyear ended December 31, 2015 as compared to a $1.8 million increase in the allowance for doubtful accounts during the yearended December 31, 2015. Depreciation and amortization expense. The $7.1 million increase in depreciation expense was related to an increase ingross property and equipment balances during the year ended December 31, 2016 compared to gross balances during the yearended December 31, 2015. There is no variance in amortization expense between the periods, as intangible assets areamortized on a straight-line basis and there has been no change in gross identifiable intangible assets between the periods. Loss (gain) on disposition of assets. During the year ended December 31, 2016, we abandoned certain assets andincurred a $1.0 million loss. The $1.0 million gain on sale of assets during the year ended December 31, 2015 was primarilyattributable to $1.2 million cash insurance recoveries on previously impaired compression equipment received duringthe year and $1.1 million gain on sale of 18 units, or 7,200 horsepower, offset by $1.3 million of losses incurred in thedisposal of various unit and non-unit assets. Impairment of compression equipment. The $5.8 million and $27.3 million impairment charge during the yearsended December 31, 2016 and 2015, respectively, were primarily a result of our evaluation of the future deployment of ourcurrent idle fleet under the current market conditions. Our evaluation determined that due to certain performancecharacteristics of the impaired equipment, such as excessive maintenance costs and the inability of the equipment to meetcurrent emission standards without retrofitting, this equipment was unlikely to be accepted by customers under currentmarket conditions. As a result of our evaluation during the years ended December 31, 2016 and 2015, we determined to retireand either sell or re-utilize the key components of 29 and 166 compression units, with a total of approximately 15,000 and58,000 horsepower, respectively, that had been previously used to provide compression services in our business. Goodwill impairment. There was no impairment of goodwill for the year ended December 31, 2016. During the yearended December 31, 2015, we recorded a $172.2 million impairment of goodwill due primarily to the decline in our unit55 Table of Contentsprice, the sustained decline in global commodity prices, expected reduction in the capital budgets of certain of our customersand the impact these factors have on our expected future cash flows. Interest expense, net. The $3.5 million increase in interest expense, net was primarily attributable to the impact of anapproximately $20.2 million increase in average outstanding borrowings under our revolving credit facility, in whichaverage borrowings were $743.5 million for the year ended December 31, 2016 compared to $723.3 million for the yearended December 31, 2015. Our revolving credit facility had an interest rate of 2.94% and 2.26% at December 31, 2016 and2015, respectively, and a weighted-average interest rate of 2.55% and 2.24% during the years ended December 31, 2016 and2015, respectively. Income tax expense. This line item represents the Texas Margin Tax. The decrease in income tax expense for the yearended December 31, 2016 compared to December 31, 2015 was primarily associated with the establishment of a deferred taxliability reflecting the book/tax basis difference in our property and equipment during the year ended December 31, 2015. Other 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) 2017 2016 2015 2017 2016 Gross operating margin $187,631 $177,760 $189,006 5.6% (6.0)%Gross operating margin percentage (2) 67.0% 66.8% 69.9% 0.3%(4.4)%Adjusted EBITDA $155,703 $146,648 $153,572 6.2%(4.5)%Adjusted EBITDA percentage (2) 55.6% 55.2% 56.8% 0.7%(2.8)%DCF (3) $118,330 $118,329 $120,850 0.0%(2.1)%DCF Coverage Ratio (3) 0.89x 1.00x 1.17 (11.0)%(14.5)%Cash Coverage Ratio (3) 1.02x 1.26x 2.58 (19.0)%(51.2)%(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)Definitions of DCF and DCF Coverage Ratio can be found under the caption “Non-GAAP Financial Measures” in Part II, Item 6. TheDCF and DCF Coverage Ratios presented here are based on a weighted average of units outstanding. For the years ended December 31,2016 and 2015, the DCF Coverage Ratio based on the actual units outstanding at the respective record dates was 0.98x and 1.15x,respectively, and the Cash Coverage Ratio based on actual units outstanding at the respective record dates for these same periods was1.23x and 2.48x, respectively. Adjusted EBITDA. The $9.1 million, or 6.2%, increase in Adjusted EBITDA during the year ended December 31, 2017was primarily attributable to a $9.9 million increase in gross operating margin offset by $0.9 million higher selling, generaland administrative expenses, excluding unit-based compensation expense, severance charges and transaction expenses,during the year ended December 31, 2017. The $6.9 million, or 4.5%, decrease in Adjusted EBITDA during the year ended December 31, 2016 was primarilyattributable to an $11.2 million decrease in gross operating margin offset by $4.4 million lower selling, general andadministrative expenses, excluding unit-based compensation expense, severance charges and transaction expenses, duringthe year ended December 31, 2016. Distributable Cash Flow. DCF during the year ended December 31, 2017 was materially consistent with DCF during theyear ended December 31, 2016 primarily due to $9.9 million increase in gross operating margin, offset by $4.8 million highermaintenance capital expenditures, $4.0 million higher cash interest expense, net and $0.9 million56 Table of Contentshigher selling, general and administrative expenses, excluding unit-based compensation expense, severance charges andtransaction expenses during the comparable period. The $2.5 million, or 2.1%, decrease in DCF during the year ended December 31, 2016 was primarily due to $11.2 milliondecrease in gross operating margin, $3.1 million higher cash interest expense, net and $1.1 million lower insurancerecoveries received, offset by $8.4 million lower maintenance capital expenditures, $4.4 million lower selling, general andadministrative expenses, excluding unit-based compensation expense, severance charges and transaction expenses duringthe comparable period. Coverage Ratios. The decrease in DCF Coverage Ratio is due to a greater number of common units outstanding as of therespective record dates during the year ended December 31, 2017. The disproportionate decrease in Cash Coverage Ratio (ascompared to DCF Coverage Ratio) is due to period-to-period decreases in DRIP participation. 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 our revolving credit facilityand issuances of debt and equity securities, including under the DRIP. We believe cash generated by operating activities and, where necessary, borrowings under our revolving credit facilitywill be sufficient to service our debt, fund working capital, fund our estimated expansion capital expenditures, fund ourmaintenance capital expenditures and pay distributions through 2018. Because we distribute all of our available cash, whichexcludes prudent operating reserves, we expect to fund any future expansion capital expenditures or acquisitions primarilywith capital from external financing sources, such as borrowings under our revolving credit facility and issuances of debt andequity securities, including under the DRIP. If the CDM Acquisition and other transactions described in Item 1 (“Business—Recent Developments”) areconsummated, our capital expenditure requirements may increase significantly. We expect to fund any increase in capitalexpenditures with cash generated by operating activities and borrowings under our revolving credit facility. 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, 2017, 2016 and 2015 (inthousands): Year Ended December 31, 2017 2016 2015Net cash provided by operating activities $124,644 $103,697 $117,401Net cash used in investing activities (105,231) (50,831) (278,158)Net cash provided by (used in) financing activities (19,431) (52,808) 160,758 Net cash provided by operating activities. The $20.9 million increase in net cash provided by operating activities for theyear ended December 31, 2017 was due primarily to $9.9 million higher gross operating margin, adjustments to non-cash andother items and changes in our working capital. The $13.7 million decrease in net cash provided by operating activities for the year ended December 31, 2016 was dueprimarily to $11.2 million lower gross operating margin, adjustments to non-cash and other items and changes in ourworking capital. 57 Table of ContentsNet cash used in investing activities. For the year ended December 31, 2017, net cash used in investing activitiesrelated primarily to purchases of new compression units, reconfiguration costs and related equipment. For the year ended December 31, 2016, net cash used in investing activities related primarily to purchases of newcompression units, reconfiguration costs and related equipment. We significantly reduced our purchases of new compressionunits during 2016 due to the reduced activity levels in the overall energy market. For the year ended December 31, 2015, net cash used in investing activities related primarily to purchases of newcompression units and related equipment in response to increased demand for our services and maintenance capitalexpenditures made to maintain or replace existing assets and operating capacity, partially offset by $1.7 million of proceedsfrom the disposition of equipment during 2015 and $1.2 million of proceeds from insurance recoveries on previouslyimpaired compression units during 2015. Net cash provided by financing activities. During 2017, we borrowed $97.5 million, on a net basis, on our revolvingcredit facility from which we borrow primarily to support our purchases of new compression units, reconfiguration costs andrelated equipment, as described above. Additionally, we made cash distributions to our unitholders of $114.1 million andpaid $2.8 million in cash related to the net settlement of unit-based awards. During 2016, we paid $43.8 million, on a net basis, on our revolving credit facility from which we borrow primarily tosupport our purchases of new compression units, reconfiguration costs and related equipment, as described above. DuringDecember 2016, we completed a public equity offering and utilized net proceeds of $80.9 million to reduce indebtednessoutstanding under our revolving credit facility. Additionally, we paid various loan fees and incurred costs of $2.0 millionrelated to an amendment to our revolving credit facility. During 2016, we made cash distributions to our unitholders of $87.7million. For the year ended December 31, 2015, we borrowed $134.3 million, on a net basis, primarily to support our purchases ofnew compression units and related equipment, as described above. During 2015, we completed a public equity offering and aprivate placement and utilized combined net proceeds of $75.1 million to reduce indebtedness outstanding under ourrevolving credit facility. Additionally, in January 2015, we paid various loan fees and incurred costs of $3.4 million relatedto an amendment to our revolving credit facility. During 2015, we made cash distributions to our unitholders of $45.1million. Equity Offerings On December 8, 2016, we closed a public offering of 5,175,000 common units at a price to the public of $16.25 percommon unit. We used the net proceeds of $80.9 million (net of underwriting discounts and commission and offeringexpenses) to reduce the indebtedness outstanding under our revolving credit facility. On September 15, 2015, we closed a public offering of 4,000,000 common units at a price to the public of $19.33 percommon unit. We used the net proceeds of $74.4 million (net of underwriting discounts and commission and offeringexpenses) to reduce the indebtedness outstanding under our revolving credit facility. On May 21, 2015, we issued 34,921 common units in a private placement for $0.7 million in a transaction that wasexempt from registration under Section 4(a)(2) of the Securities Act of 1933, as amended (the “Securities Act”). We used theproceeds from the private placement for general partnership purposes. 58 Table of ContentsCapital 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, 2017 and 2016 were $12.6million and $7.7 million, respectively. We currently plan to spend approximately $15 million in maintenance capitalexpenditures during 2018, 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 current or futureacquisitions, we currently have budgeted between $130 million and $140 million in expansion capital expenditures during2018. Our expansion capital expenditures for the years ended December 31, 2017 and 2016 were $116.9 million and $40.9million, respectively. Revolving Credit Facility As of December 31, 2017, we were in compliance with all of our covenants under our revolving credit facility. As ofDecember 31, 2017, we had outstanding borrowings under our revolving credit facility of $782.9 million, $272.1 million ofborrowing base availability and, subject to compliance with the applicable financial covenants, available borrowingcapacity of $101.6 million. The borrowing base consists of eligible accounts receivable, inventory and compression units.One of the financial covenants under our revolving credit facility permits a maximum leverage ratio of (A) 5.25 to 1.0 as ofthe end of the fiscal quarter ending December 31, 2017 and (B) 5.00 to 1.0 thereafter. As of February 8, 2018, we hadoutstanding borrowings of $815.0 million. We expect to remain in compliance with our covenants throughout 2018. If ourcurrent cash flow projections prove to be inaccurate, we expect to be able to remain in compliance with such financialcovenants by one or more of the following actions: issue debt and equity securities in conjunction with the acquisition ofanother business; issue equity in a public or private offering; request a modification of our covenants from our bank group;reduce distributions from our current distribution rate or obtain an equity infusion pursuant to the terms of our revolvingcredit facility. For a more detailed description of our revolving credit facility including the covenants and restrictions containedtherein, please refer to Note 7 to our consolidated financial statements. 59 Table of ContentsCommitment Letter In connection with the CDM Acquisition, on January 15, 2018, we entered into a commitment letter with JPMorganChase Bank, N.A. and Barclays Bank PLC, as modified by the joinder to commitment letter and bridge fee letter entered intoby the Partnership, JPMorgan Chase Bank, N.A. and Barclays Bank PLC with each of Regions Bank, Royal Bank of Canada,Wells Fargo Bank, N.A., MUFG Union Bank, N.A., a member of MUFG, a global financial group, The Bank of Nova Scotiaand SunTrust Bank and certain affiliates of such parties (the “Commitment Letter”). The Commitment Letter provides forsenior unsecured bridge loans in an aggregate amount up to $725 million (the “Bridge Loans”). The proceeds of such BridgeLoans may be used (a) to finance a portion of the purchase price of the CDM Acquisition and (b) to pay fees and expensesincurred in connection therewith. The availability of the borrowings is subject to the satisfaction of certain customaryconditions. Distribution Reinvestment Plan During the year ended December 31, 2017, distributions of $20.3 million were reinvested under the DRIP resulting in theissuance of 1.2 million common units. Such distributions are treated as non-cash transactions in the accompanyingConsolidated Statements of Cash Flows included under Part IV, Item 15 of this report. For a more detailed description of the DRIP, please refer to Note 8 to our consolidated financial statements. Total Contractual Cash Obligations The following table summarizes our total contractual cash obligations as of December 31, 2017: 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) $782,902 $— $782,902 $— $— Interest on long-term debt obligations (2) 54,622 27,088 27,534 — — Equipment/capital purchases (3) 122,156 119,656 2,500 — — Operating lease obligations (4) 2,946 1,517 1,357 72 — Total contractual cash obligations $962,626 $148,261 $814,293 $72 $ — (1)We assumed that the amount outstanding under our revolving credit facility at December 31, 2017 would be repaid in January 2020, thematurity date of the facility.(2)Represents future interest payments under our revolving credit facility based on the interest rate as of December 31, 2017 of 3.46%.(3)Represents commitments for new compression units that are being fabricated, and is a component of our overall projected expansioncapital expenditures during 2018 of $130 million to $140 million.(4)Represents commitments for future minimum lease payments on noncancelable leases. Effects of Inflation. Our revenues and results of operations have not been materially impacted by inflation and changingprices in the past three fiscal years. Off-Balance Sheet Arrangements We have no off-balance sheet financing activities. Please refer to Note 13 of 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 make60 Table of Contentscertain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of thefinancial statements and the reported amounts of revenue and expenses during the periods presented. We base our estimateson historical experience, available information and various other assumptions we believe to be reasonable under thecircumstances. On an ongoing basis, we evaluate our estimates; however, actual results may differ from these estimates underdifferent assumptions or conditions. The accounting policies that we believe require management’s most difficult, subjectiveor complex judgments and are the most critical to its reporting of results of operations and financial position are as follows: Revenue Recognition We recognize revenue using the following criteria: (i) persuasive evidence of an arrangement; (ii) delivery has occurredor services have been rendered; (iii) the customer’s price is fixed or determinable; and (iv) collectability is reasonablyassured. Revenue from compression services is recognized ratably under our fixed-fee contracts over the term of the contract ascompression services are provided to our customers. Compression services generally are billed monthly, one month inadvance of the commencement of the service month, except for certain customers who are billed at the beginning of theservice month. Amounts invoiced in advance are recorded as deferred revenue on the balance sheet until earned, at whichtime it is recognized as revenue. Revenue and the associated expense from installation services, which includes the installation of stations for ourcustomers, is recorded using the percentage-of-completion method measured using the efforts-expended method. In applyingthe percentage-of-completion method, we use the percentage of total workflows to date that have been completed relative toestimated total workflows to be completed in order to estimate the progress towards completion to determine the amount ofrevenue and profit to recognize for each contract. The percentage-of-completion method of revenue recognition requires us to make estimates of contract revenues andcosts to complete our projects. In making such estimates, management judgments are required to evaluate significantassumptions including the cost of materials and labor, expected labor productivity, the impact of potential variances inschedule completion, the amount of net contract revenues and the impact of any penalties, claims, change orders, orperformance incentives. 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. Goodwill—Impairment Assessments We evaluate goodwill for impairment annually on October 1 of the fiscal year and whenever events or changes indicatethat it is more likely than not that the fair value of our single business reporting unit could be less than its carrying value(including goodwill). The timing of the annual test may result in charges to our statement of operations in our fourth fiscalquarter that could 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.61 Table of Contents On October 1, 2017 and 2016, we performed our annual goodwill impairment test, wherein we compared the estimatedfair value of our single reporting unit to its carrying value. The estimated fair value of our reporting unit, measured based onmarket capitalization, as of October 1, 2017 and 2016 exceeded its carrying value in excess of 20% and we concluded thatour goodwill was not impaired. We recorded no goodwill impairment charges for the years ended December 31, 2017 and2016. We had approximately $35.9 million of goodwill recorded on the balance sheet as of December 31, 2017 and 2016. On October 1, 2015, we performed our annual goodwill impairment test and concluded that our goodwill was notimpaired. We updated our impairment test as of December 31, 2015 as certain potential impairment indicators were identifiedduring the fourth quarter, specifically (1) the decline in the market price of our common units, (2) the sustained decline inglobal commodity prices, and (3) the decline in performance of the Alerian MLP Index, which indicated the reporting unithad a fair value that was less than its carrying value as of December 31, 2015. We prepared a quantitative assessment as ofDecember 31, 2015 which indicated that the calculated fair value was less than the carrying value. We subsequentlyperformed “step two” impairment test for our reporting unit under which we treated our business as if it had been acquired ina business combination as of December 31, 2015 and assigned the fair value of the reporting unit to all of our assets andliabilities. The carrying value of the goodwill was compared to the new implied fair value of goodwill and an impairment wasrecognized for the amount of the carrying value that exceeded the implied fair value. Based on that step two impairment test,we recognized a non-cash impairment charge of $172.2 million. We had approximately $35.9 of goodwill remaining on thebalance sheet as of December 31, 2015 following this impairment. 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 remaining $35.9million 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. 62 Table of ContentsAllowances 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 We qualify as an emerging growth company under Section 109 of the Jumpstart Our Business Startups, (“JOBS”) Act. Anemerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of theSecurities Act for complying with new or revised accounting standards. In other words, an emerging growth company candelay the adoption of certain accounting standards until those standards would otherwise apply to private companies.However, we have chosen to “opt out” of such extended transition period, and as a result, are compliant with new or revisedaccounting standards on the relevant dates on which adoption of such standards is required for non-emerging growthcompanies. Section 108 of the JOBS Act provides that our decision to opt out of the extended transition period forcomplying with new or revised accounting standards is irrevocable. For more discussion on specific recent accounting pronouncements affecting us, please see Note 12 to our consolidatedfinancial statements. 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. Lower natural gas prices or crude oil prices 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, 2017 would have resulted in a decrease of approximately $2.7 millionand $1.8 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, 2017, we had approximately $782.9 million of variable-rate outstanding indebtedness at a weighted-average interest rate of 3.14%. A 1% increase or decrease in the effective interest rate on our variable-rate outstanding debt asof December 31, 2017 would result in an annual increase or decrease in our interest expense of approximately $7.8 million. 63 Table of ContentsFor further information regarding our exposure to interest rate fluctuations on our debt obligations, see Note 7 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 reports that we file or submit under the ExchangeAct is accumulated and communicated to our management, including our principal executive officer and principal financialofficer, as appropriate to allow timely decisions regarding required disclosures, and is recorded, processed, summarized andreported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principalexecutive officer and principal financial officer have concluded that our disclosure controls and procedures were effective asof December 31, 2017 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, 2017. 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, 2017, our internal control over financial reporting was effective. This report does not64 Table of Contentsinclude an attestation report of the company’s registered public accounting firm due to a transition period established byrules of the SEC for emerging growth companies. Changes in Internal Control over Financial Reporting There were no changes in our internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) 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 None.65 Table of Contents PART III ITEM 10.Directors, Executive Officers and Corporate Governance Board of Directors Our general partner, USA Compression GP, LLC, manages our operations and activities. Our general partner is notelected by our unitholders and is not subject to re-election on a regular basis in the future. Our general partner has a board ofdirectors that manages our business. The board of directors of our general partner is currently comprised of eight members, all of whom have been designatedby USA Compression Holdings and three of whom are independent as defined under the independence standards establishedby the NYSE. The NYSE does not require a listed limited partnership like us to have a majority of independent directors onthe board of directors of our general partner or to establish a compensation committee or a nominating committee. The non-management members of our general partner’s board of directors regularly meet in executive session withoutthe management members of our general partner’s board of directors. Mr. Long, our President and Chief Executive Officer, iscurrently the only management member of our general partner’s board of directors. Forrest E. Wylie presides at suchmeetings. Interested parties can communicate directly with non-management members of our general partners’ board ofdirectors by mail in care of the General Counsel and Secretary at USA Compression Partners, LP, 100 Congress Avenue, Suite450, Austin, Texas 78701. Such communications should specify the intended recipient or recipients. Commercialsolicitations or communications will not be forwarded. Independent Directors. The board of directors of our general partner has determined that Robert F. End, Jerry L. Peters,and Forrest E. Wylie are independent directors under the standards established by the NYSE and the Exchange Act. Theboard of directors of our general partner considered all relevant facts and circumstances and applied the independentguidelines of the NYSE and the Exchange Act in determining that none of these directors has any material relationship withus, our management, our general partner or its affiliates or our subsidiaries. Effective October 15, 2017, John D. Chandler resigned from the board of directors of our general partner for personalreasons as he accepted a position with another publicly traded company. Mr. Chandler’s resignation did not arise from anydisagreement with the general partner, its management or its Board of Directors on any matter relating to the generalpartner’s, or the Partnership’s, operations, policies or practices, the general direction of the general partner or the Partnership,or Mr. Chandler’s role on the Board of Directors. Effective October 16, 2017, the board of directors of our generalpartner appointed Jerry L. Peters to serve as a director on the board of directors of our general partner to fill the vacancycreated by Mr. Chandler’s resignation. As Mr. Chandler served as the chairman of the Audit Committee, Mr. Peters wasappointed by the board of directors of our general partner to the audit committee of the board of directors of our generalpartner and to serve as the chairman of the audit committee. In October 2014, Mr. Chandler was appointed to serve on the board of directors and the audit committee of one of ourcustomers. During the period of Mr. Chandler’s directorship for the year ended December 31, 2017, subsidiaries of thiscustomer made compression service payments to us of approximately $5.7 million. The board of directors of our generalpartner made a determination that the relationship with this customer did not preclude the independence of Mr. Chandler. Since September 2012, Mr. Peters has served on the board of directors and the audit committee of one of ourcustomers. During the period of Mr. Peters’ directorship for the year ended December 31, 2017, subsidiaries of this customermade compression service payments to us of approximately $0.3 million. The board of directors of our general partner made adetermination that the relationship with this customer did not preclude the independence of Mr. Peters. Audit Committee. The board of directors of our general partner has appointed an audit committee comprised solely ofdirectors who meet the independence and experience standards established by the NYSE and the Exchange Act. The66 Table of Contentsaudit committee consists of Robert F. End, Jerry L. Peters and Forrest E. Wylie. Mr. Peters serves as chairman of the auditcommittee. The board of directors of our general partner has determined that Mr. Peters is an “audit committee financialexpert” as defined in Item 407(d)(5)(ii) of SEC Regulation S-K, and that each of Messrs. End, Peters and Wylie is“independent” within the meaning of the applicable NYSE and Exchange Act rules regulating audit committeeindependence. The audit committee assists the board of directors of our general partner in its oversight of the integrity of ourfinancial statements and our compliance with legal and regulatory requirements and corporate policies and controls. Theaudit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve allauditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by ourindependent registered public accounting firm. The audit committee is also responsible for confirming the independence andobjectivity of our independent registered public accounting firm. Our independent registered public accounting firm will begiven unrestricted access to the audit committee. A copy of the charter of the audit committee is available under the InvestorRelations tab on our website at usacompression.com. We also will provide a copy of the charter of the audit committee to anyof our 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 of directors of our general partner has established a compensation committee to, among otherthings, oversee the compensation plans described below in Part III, Item 11 (“Executive Compensation”). The compensationcommittee consists of Robert F. End, William H. Shea, Jr. and Olivia C. Wassenaar. The compensation committee establishesand reviews general policies related to our compensation and benefits. The compensation committee has the responsibility todetermine and make recommendations to the board of directors of our general partner with respect to, the compensation andbenefits of the board of directors and executive officers of our general partner. A copy of the charter of the compensationcommittee is available under the Investor Relations tab on our website at usacompression.com. We also will provide a copyof the charter of the compensation committee to any of our unitholders without charge upon written request to InvestorRelations, 100 Congress Avenue, Suite 450, Austin, TX 78701. Conflicts Committee. As set forth in the limited liability company agreement of our general partner, our general partnermay, from time to time, establish a conflicts committee to which the board of directors of our general partner will appointindependent directors and which may be asked to review specific matters that the board of directors of our general partnerbelieves may involve conflicts of interest between us, our limited partners and USA Compression Holdings. The conflictscommittee will determine the resolution of the conflict of interest in any manner referred to it in good faith. The members ofthe conflicts committee may not be officers or employees of our general partner or directors, officers or employees of itsaffiliates, including USA Compression Holdings, and must meet the independence and experience standards established bythe NYSE and the Exchange Act to serve on an audit committee of a board of directors of our general partner, and certainother requirements. Any matters approved by the conflicts committee in good faith will be conclusively deemed to be fairand reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us orour unitholders. Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Exchange Act requires the board of directors and executive officers of our general partner, andpersons who own more than 10 percent of a registered class of our equity securities, to file with the SEC and any exchange orother system on which such securities are traded or quoted initial reports of ownership and reports of changes in ownership ofour common units and other equity securities. Officers, directors and greater than 10 percent unitholders are required by theSEC’s regulations to furnish to us and any exchange or other system on which such securities are traded or quoted withcopies of all Section 16(a) forms they filed with the SEC. To our knowledge, based solely on a review of the copies of suchreports furnished to us, we believe that all reporting obligations of the officers and directors of our general partner and greaterthan 10 percent unitholders under Section 16(a) were satisfied during the year ended December 31, 2017. 67 Table of ContentsCorporate Governance Guidelines and Code of Ethics The board of directors of our general partner has adopted Corporate Governance Guidelines that outline importantpolicies and practices regarding our governance and provide a framework for the function of the board of directors of ourgeneral partner and its committees. The board of directors of our general partner has also adopted a Code of BusinessConduct and Ethics (the “Code”) that applies to our general partner and its subsidiaries and affiliates, including us, and to allof its and their directors, employees and officers, including its principal executive officer, principal financial officer andprincipal accounting officer. Copies of the Corporate Governance Guidelines and the Code are available under the InvestorRelations tab on our website at usacompression.com. We also will provide copies of the Corporate Governance Guidelinesand the Code to any of our unitholders without charge upon written request to Investor Relations, 100 Congress Avenue,Suite 450, Austin, TX 78701. Reimbursement of Expenses of Our General Partner Our general partner will not receive any management fee or other compensation for its management of us. Our generalpartner and its affiliates will be reimbursed for all expenses incurred on our behalf, including the compensation of employeesof our general partner or its affiliates that perform services on our behalf. These expenses include all expenses necessary orappropriate to the conduct of our business and that are allocable to us. Our partnership agreement provides that our 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 our general partner or its affiliates for compensation or expenses incurred on our behalf. Directors and Executive Officers The following table shows information as of February 8, 2018 regarding the current directors and executive officers ofUSA Compression GP, LLC. Name Age Position with USA Compression GP, LLCEric D. Long 59 President and Chief Executive Officer and DirectorWilliam G. Manias 55 Vice President and Chief Operating OfficerMatthew C. Liuzzi 43 Vice President, Chief Financial Officer and TreasurerChristopher W. Porter 34 Vice President, General Counsel and SecretaryDavid A. Smith 55 Vice President and President, Northeast RegionSean T. Kimble 53 Vice President, Human ResourcesJerry L. Peters 60 DirectorJim H. Derryberry 73 DirectorRobert F. End 62 DirectorWilliam H. Shea, Jr. 63 DirectorOlivia C. Wassenaar 38 DirectorForrest E. Wylie 54 DirectorMichael A. Wichterich 50 Director The directors of our 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 of directors of our generalpartner. There are no family relationships among any of the directors or executive officers of our general partner. Eric D. Long has served as our President and Chief Executive Officer since September 2002 and has served as a directorof USA Compression GP, LLC since June 2011. Mr. Long co-founded USA Compression in 1998 and has over 35 years ofexperience in the oil and gas industry. From 1980 to 1987, Mr. Long served in a variety of technical and managerial roles forseveral major pipeline and oil and natural gas producing companies, including Bass Enterprises Production Co. and TexasOil & Gas. Mr. Long then served in a variety of senior officer level operating positions with affiliates of Hanover Energy, Inc.,a company primarily engaged in the business of gathering, compressing and transporting natural gas. In 1993, Mr. Long co-founded Global Compression Services, Inc., a compression services68 Table of Contentscompany. Mr. Long was formerly on the board of directors of the Wiser Oil Company, an NYSE listed company fromMay 2001 until it was sold to Forest Oil Corporation in May 2004. Mr. Long received his bachelor’s degree, with honors, inPetroleum Engineering from Texas A&M University. He is a registered Professional Engineer in the state of Texas. As a result of his professional background, Mr. Long brings to us executive level strategic, operational and 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 of directors of our generalpartner. William G. Manias has served as our Vice President and Chief Operating Officer since July 2013. He served as a directorof our general partner from February 2013 to July 2013. From October 2009 until January 2013, Mr. Manias served as SeniorVice President and Chief Financial Officer of Crestwood Midstream Partners LP and its affiliates, where his generalresponsibilities 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 Product 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 Product Partners L.P. Prior to GulfTerra Energy Partners, L.P., Mr. Manias held several executive managementpositions with El Paso Corporation. Prior to El Paso, he worked as an energy investment banker for J.P. Morgan 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. 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. 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 Andrews Kurth Kenyon 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 from Texas A&M University, a M.S. degree from Texas A&M University, and a J.D. degree fromThe George Washington University. David A. Smith has served as our President, Northeast Region since joining us in November 1998 and was appointedcorporate Vice President in June 2011. Mr. Smith has approximately 20 years of experience in the natural gas compressionindustry, primarily in operations and sales. From 1985 to 1989, Mr. Smith was a sales manager for McKenzie Corporation, acompression fabrication company. From 1989 to 1996, Mr. Smith held positions of General Manager and Regional Managerof Northeast Division with Compressor Systems Inc., a fabricator and supplier of compression services. Mr. Smith was theRegional Manager in the northeast for Global Compression Services, Inc., a compression services company, and served inthat capacity from 1996 to 1998. Mr. Smith received an associates degree in Automotive and Diesel Technology fromRosedale Technical Institute. Sean T. Kimble has served as our Vice President, Human Resources since June 2014. Mr. Kimble comes to us with overtwenty years of human resources leadership experience. Prior to joining the company, 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. from Sacramento State University and an M.B.A. fromSaint Mary’s College of California.69 Table of Contents Jerry L. Peters has served as a director of USA Compression GP, LLC since October 2017. Additionally, Mr. Petersserves as the chairman and financial expert of the Audit Committee of our general partner. Mr. Peters served as the ChiefFinancial Officer of Green Plains Inc., a publicly traded vertically-integrated ethanol producer, from June 2007 until hisretirement in September 2017. In 2015, Mr. Peters was appointed Chief Financial Officer and Director of the general partnerof Green Plains Partners LP, a publicly traded partnership engaged in fuel storage and transportation services. He retired fromhis role as Chief Financial Officer of the general partner of Green Plains Partners LP in September 2017, but remains on theboard of directors. Prior to joining Green Plains, Mr. Peters served as Senior Vice President—Chief Accounting Officer forONEOK Partners, L.P. from May 2006 to April 2007, as its Chief Financial Officer from July 1994 to May 2006, and invarious senior management roles prior to that. Prior to joining ONEOK Partners in 1985, he was employed by KPMG LLP as acertified public accountant. Beginning September 2012, Mr. Peters serves on the board of directors, and as chairman of theaudit committee, of the general partner of Summit Midstream Partners, LP, a publicly traded partnership focused onmidstream energy infrastructure assets. Mr. Peters received his Master of Business Administration from Creighton Universitywith a Finance emphasis and a Bachelor of Science degree in Business Administration from the University of Nebraska—Lincoln. Mr. Peters’ experience serving on the board of directors of publicly traded limited partnerships, including as chairman ofthe audit committee, and his financial expertise are key attributes, among others, that make him well qualified to serve on theboard of directors of our general partner. Jim H. Derryberry has served as a director of USA Compression GP, LLC since January 2013. From February 2005 toOctober 2006, Mr. Derryberry served on the board of directors of Magellan GP, LLC, the general partner of MagellanMidstream Partners, L.P. Mr. Derryberry served as chief operating officer and chief financial officer of Riverstone Holdings,LLC until 2006 and currently serves as a special advisor. Prior to joining Riverstone, Mr. Derryberry was a managing directorof J.P. Morgan, where he served as head of the Natural Resources and Power Group. Before joining J.P. Morgan,Mr. Derryberry was in the Goldman Sachs Global Energy and Power Group where he was responsible for mergers andacquisitions, capital markets financing and the management of relationships with major energy companies. He has alsoserved as an advisor to the Russian government for energy privatization. Mr. Derryberry has served as a member of the Boardof Overseers for the Hoover Institution at Stanford University and is a member of the Engineering Advisory Board at theUniversity of Texas at Austin. He received his B.S. and M.S. degrees in engineering from the University of Texas at Austinand earned an M.B.A. from Stanford University. Mr. Derryberry brings significant knowledge and expertise to the board of directors of our general partner from hisservice on other boards and his years of experience in our industry including his useful insight into investments and provenleadership skills as a managing director of Riverstone Holdings, LLC. As a result of his experience and skills, we believeMr. Derryberry is a valuable member of the board of directors of our general partner. Robert F. End has served as a director of USA Compression GP, LLC since November 2012. Mr. End served as a directorof Hertz Global Holdings, Inc. from December 2005 until August 2011. Mr. End was a Managing Director of TransportationResource Partners, a private equity firm from 2009 through 2011. Prior to joining TRP in 2009, Mr. End had been aManaging Director of Merrill Lynch Global Private Equity Division (“MLGPE”), the private equity arm of Merrill Lynch &Co., Inc., where he served as Co-Head of the North American Region, and a Managing Director of Merrill Lynch GlobalPrivate Equity, Inc., the Manager of ML Global Private Equity Fund, L.P., a proprietary private equity fund which he joinedin 2004. Previously, Mr. End was a founding Partner and Director of Stonington Partners Inc., a private equity firmestablished in 1994. Prior to leaving Merrill Lynch in 1994, Mr. End was a Managing Director of Merrill Lynch CapitalPartners, Merrill Lynch’s private equity group. Mr. End joined Merrill Lynch in 1986 and worked in the Investment BankingDivision before joining the private equity group in 1989. Mr. End received his A.B. from Dartmouth College and his M.B.A.from the Tuck School of Business Administration at Dartmouth College. Mr. End brings significant knowledge and expertise to the board of directors of our general partner from his service onother boards and his years of experience with private equity groups, including his useful insight into investments andbusiness development and proven leadership skills as Managing Director of MLGPE. As a result of this experience andresulting skills set, we believe Mr. End is a valuable member of the board of directors of our general partner. 70 Table of ContentsWilliam H. Shea, Jr. has served as a director of USA Compression GP, LLC since June 2011. Mr. Shea served as thechairman of the board of directors, President and Chief Executive Officer of Niska Gas Storage Partners LLC from May 2014to July 2016. Previously, Mr. Shea served as the President and Chief Operating Officer of Buckeye GP LLC and itspredecessor entities (“Buckeye”), from July 1998 to September 2000, as President and Chief Executive Officer of Buckeyefrom September 2000 to July 2007, and Chairman from May 2004 to July 2007. From August 2006 to July 2007, Mr. Sheaserved as Chairman of MainLine Management LLC, the general partner of Buckeye GP Holdings, L.P., and as President andChief Executive Officer of MainLine Management LLC from May 2004 to July 2007. Mr. Shea served as a director of PennVirginia Corp. from July 2007 to March 2010, and as President and Chief Executive Officer of the general partner of PennVirginia GP Holdings, L.P. from March 2010 to October 2013 and as Chief Executive Officer of the general partner of PVRPartners, L.P. (“PVR”), from March 2010 to October 2013. Mr. Shea has also served as a director of Kayne Anderson EnergyTotal Return Fund, Inc., and Kayne Anderson MLP Investment Company since March 2008 and Niska Gas Storage PartnersLLC from May 2010 to July 2016. Mr. Shea has an agreement with Riverstone, pursuant to which he has agreed to serve onthe boards of certain Riverstone portfolio companies. Mr. Shea received his B.A. from Boston College and his M.B.A. fromthe University of Virginia. Mr. Shea’s experiences as an executive with both PVR and Buckeye, energy companies that operate across a broadspectrum of sectors, including coal, natural gas gathering and processing and refined petroleum products transportation, havegiven him substantial knowledge about our industry. In addition, Mr. Shea has substantial experience overseeing the strategyand operations of publicly traded partnerships. As a result of this experience and resulting skill set, we believe Mr. Shea is avaluable member of the board of directors of our general partner. Olivia C. Wassenaar has served as a director of USA Compression GP, LLC since June 2011. Ms. Wassenaar was anAssociate with Goldman, Sachs & Co. in the Global Natural Resources investment banking group from July 2007 toAugust 2008, where she focused on mergers, equity and debt financings and leveraged buyouts for energy, power andrenewable energy companies. Ms. Wassenaar joined Riverstone in September 2008 as Vice President, and has served as aPrincipal from May 2010 to February 2014 and as a Managing Director since February 2014. In this capacity, she invests inand monitors investments in the midstream and exploration & production sectors of the energy industry. Ms. Wassenaar hasalso served on the board of directors of Northern Blizzard Resources Inc. from 2011 to 2017 and on the board of directors ofthe general partner of Niska Gas Storage Partners LLC from July 2014 to July 2016, as well as various private portfoliocompanies sponsored by Riverstone. Ms. Wassenaar received her A.B., magna cum laude, from Harvard College and earnedan M.B.A. from the Wharton School of the University of Pennsylvania. Ms. Wassenaar’s experience in evaluating financial and strategic options and the operations of companies in ourindustry and as an investment banker make her a valuable member of the board of directors of our general partner. Forrest E. Wylie has served as a director of USA Compression GP, LLC since March 2013. Mr. Wylie is also a SeniorOperating Partner at Stonepeak Infrastructure Partners and has served in such role since October 2013. Mr. Wylie served asthe Non-Executive Chairman of the board of directors of Buckeye GP LLC, the general partner of Buckeye Partners, L.P.,from February 2012 to August 2014. He served as Chairman of the Board, CEO and a director of Buckeye GP LLC fromJune 2007 to February 2012. Mr. Wylie also served as a director of the general partner of Buckeye GP Holdings L.P., theformer parent company of Buckeye (“BGH”) from June 2007 until the merger of BGH with Buckeye Partners, L.P. onNovember 2010. Prior to his appointment, he served as Vice Chairman of Pacific Energy Management LLC, an entityaffiliated with Pacific Energy Partners, L.P., a refined product and crude oil pipeline and terminal partnership, fromMarch 2005 until Pacific Energy Partners, L.P. merged with Plains All American, L.P. in November 2006. Mr. Wylie wasPresident and CFO of NuCoastal Corporation, a midstream energy company, from May 2002 until February 2005. FromNovember 2006 to June 2007, Mr. Wylie was a private investor. Mr. Wylie served on the board of directors and the auditcommittee of Coastal Energy Company, a publicly traded entity, until April 2011. Mr. Wylie also served on board ofdirectors and compensation and nominating and corporate governance committees of Eagle Bulk Shipping Inc. untilMay 2010. Mr. Wylie also currently serves as Executive Chairman of Ajax Resources LLC and a board member of ParadigmEnergy Partners. Mr. Wylie’s experience in the energy industry, through his prior position as the CEO of a publicly traded partnership andthe past employment described above, has given him both an understanding of the midstream sector of the energy71 Table of Contentsbusiness and of the unique issues related to operating publicly traded limited partnerships that make him a valuable memberof the board of directors of our general partner. Michael A. Wichterich has served as a director of USA Compression GP, LLC since October 2017. Mr. Wichterich hasbeen in the oil and gas business for 23 years and currently serves as President of Three Rivers Operating Company. Hefounded the first Three Rivers entity in 2010. Prior to starting Three Rivers, Mr. Wichterich served as Chief Financial Officerof Texas American Resources, which operated wells throughout Texas, Colorado and Wyoming. Mr. Wichterich has alsoserved as a director of Sabine Oil and Gas since July 2016, where he serves on the audit and compensation committees. Hepreviously served as Chief Financial Officer of Mariner Energy Inc. He spent seven years with Mariner gaining experience atboth offshore Gulf of Mexico and West Texas projects. Prior to that, Mr. Wichterich spent nine years with PWC in its energyauditing practices, leading engagements within the oil and gas industry. Mr. Wichterich is a Certified Public Accountant inthe State of Texas and is a graduate of the University of Texas. Mr. Wichterich’s experience in the energy industry, through his prior position as the CFO of multiple energy entities andthe past employment described above, has given him a unique understanding of the energy business that makes him avaluable member of the board of directors of our general partner. ITEM 11.Executive Compensation As is commonly the case for many publicly traded limited partnerships, we have no employees. Under the terms of ourpartnership agreement, we are ultimately managed by our general partner. All of our employees, including our executiveofficers, are employees of USAC Management, a wholly owned subsidiary of our general partner. Executive Compensation We are an “emerging growth company” as defined under the Jumpstart Our Business Startups (JOBS) Act. As such, we arepermitted to meet the disclosure requirements of Item 402 of Regulation S-K by providing the reduced disclosures requiredof a “smaller reporting company.” Executive Summary This Executive Compensation disclosure provides an overview of the executive compensation program for our namedexecutive officers identified below. Our general partner intends to provide our named executive officers with compensationthat is significantly performance based. For the year ended December 31, 2017, our named executive officers (“NEOs”) were: ·Eric D. Long, President and Chief Executive Officer; ·William G. Manias, Vice President and Chief Operating Officer; and ·Matthew C. Liuzzi, Vice President, Chief Financial Officer and Treasurer. 72 Table of ContentsSummary Compensation Table The following table sets forth certain information with respect to the compensation paid to our NEOs for the years endedDecember 31, 2017 and 2016. All Other Unit Awards Compensation Name and Principal Position Year Salary ($) Bonus ($) (1) ($) (2) ($) Total ($)Eric D. Long 2017 625,233 721,436 1,953,127 755,233(3) 4,055,029President and Chief Executive Officer 2016 607,019 773,419 1,892,893 742,412 4,015,743William G. Manias 2017 423,886 396,711 993,108 389,700(4) 2,203,405Vice President and Chief Operating Officer 2016 411,538 416,353 1,069,430 380,616 2,277,937Matthew C. Liuzzi 2017 375,538 329,496 782,050 313,209(5) 1,800,293Vice President, Chief Financial Officer andTreasurer 2016 362,885 381,399 852,693 306,589 1,903,566(1)Represents the awards earned under annual cash incentive bonus program for the years ended December 31, 2017 and 2016, asapplicable. For a discussion of the determination of the 2017 bonus amounts, see “—Annual Incentive Compensation for 2017” below. (2)On February 13, 2017 and February 11, 2016, each of our NEOs received an award of time-based and performance-based phantom unitsunder our long-term incentive plan (“LTIP”). Each phantom unit is the economic equivalent of one common unit, although theperformance-based awards could be settled at 200% of target levels in the event that the performance goals are satisfied at such levels. Thephantom unit values reflect the grant date fair value of the awards calculated in accordance with the Financial Accounting StandardsBoard’s (“FASB”) Accounting Standard Codification (“ASC”) Topic 718, disregarding the estimate of forfeitures. For a discussion ofthe assumptions utilized in determining the fair value of these awards, please see Note 9 to our consolidated financial statements. Withrespect to the performance-based awards, the value of the awards has been reflected at the probable outcome of performance conditions asof the grant date for accounting purposes. If the awards were to be reflected at maximum amounts, the year 2017 amounts reflected in thetable above would be increased by the following amounts: Mr. Long, $450,907; Mr. Manias, $229,278; and Mr. Liuzzi, $180,540. Theyear 2016 amounts reflected in the table above would be increased by the following amounts: Mr. Long, $434,412; Mr. Manias,$245,430; and Mr. Liuzzi, $195,693. (3)Includes $710,538 of distribution equivalent rights (“DERs”), $18,000 of automobile allowance, $8,100 of employer contributions underthe 401(k) plan, $3,843 of parking, $3,574 of club membership dues, $9,178 of personal administrative assistant support and $2,000 ofpersonal tax support. Please see a description of the DERs under “—Discretionary Long-Term Equity Incentive Awards” below. (4)Includes $381,568 of DERs, $7,330 of employer contributions under the 401(k) plan and $801 of parking. (5)Includes $304,308 in DERs, $8,100 of employer contributions under the 401(k) plan and $801 of parking. 73 Table of ContentsNarrative Disclosure to Summary Compensation Table Elements of the Compensation Program Compensation for our NEOs consists primarily of the elements, and their corresponding objectives, identified in thefollowing table. 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. Discretionary 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 our partnership. Severance benefits To encourage the continued attention and dedication of keyindividuals and to focus the attention of such keyindividuals when considering strategic alternatives. Retirement savings (401(k)) plan To provide an opportunity for tax-efficient savings. Other elements of compensation and perquisites To attract and retain talented executives in a cost-efficientmanner by providing benefits with high perceived values atrelatively low cost. Base Compensation For 2017 and 2018 Base salaries for our 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 executive officers and market conditions, each as assessed by the board of directors of our general partneror the chief executive officer (for non-chief executive officer compensation) in conjunction with the compensationcommittee. For 2017 and 2018, in connection with determining base salaries for each of our NEOs, the board of directors ofour general partner, compensation committee and chief executive officer worked with a compensation consultant todetermine comparable salaries for our peer group, which we identified based on a review of companies in our industry withsimilar characteristics. Based upon discussions with the compensation consultant with respect to a review of base salary information ofcompanies within our peer group, the board of directors of our general partner has determined to target base salaries directlyin-line with our peer group. For 2017 and 2018, the board of directors of our general partner determined that base salaryshould be set at approximately the 50 percentile of the peer group. The 2017 and current 2018 base salaries for our NEOs,including for our Chief Executive Officer, are set forth in the following table: 2017 Base Salary Current 2018Base SalaryName and Principal Position ($) ($)Eric D. Long, President and Chief Executive Officer 625,931 644,709William G. Manias, Vice President and Chief Operating Officer 424,361 437,092Matthew C. Liuzzi, Vice President, Chief Financial Officer and Treasurer 375,960 387,239 74 thTable of ContentsAnnual Incentive Compensation For 2017 The board of directors of our general partner has approved the adoption of an Annual Cash Incentive Plan (the “CashPlan”). Each of our NEOs is entitled to participate in the Cash Plan and their potential bonus is governed both by the CashPlan and their employment agreement. The compensation committee acts as the administrator of the Cash Plan under thesupervision of the full board of directors of our general partner, and has the discretion to amend, modify or terminate the CashPlan at any time upon approval by the board of directors of our general partner. Although the Cash Plan uses both companyand individual performance goals to determine bonus amounts, the Cash Plan is ultimately a discretionary annual bonus planand awards are therefore reported in the “Bonus” column within the Summary Compensation Table above. The board of directors of our general partner sets a target bonus amount (the “Target Bonus”) for each NEO prior to orduring the first quarter of the calendar year. For the year ended December 31, 2017, the Target Bonus for each NEO was$625,934 for Mr. Long, $339,489 for Mr. Manias and $281,970 for Mr. Liuzzi. The Target Bonus is generally subject to thesatisfaction of both a partnership performance goal and an individual performance goal. For the year ended December 31,2017 seventy-five percent (75%) of the Target Bonus was subject to our achievement of our budgeted distributable cash flowlevel (“DCF”) for the year, as determined by our board of directors of our general partner. Payouts with respect to the portionof the bonus subject to DCF (the “DCF Bonus”) generally do not occur unless we have satisfied the threshold set for DCF. For2017, the board of directors of our general partner set the budget for DCF at $115.7 million. The threshold, target andmaximum requirements for the DCF target for the year ended December 31, 2017, as well as the portion of the DCF Bonusthat could become payable if performance was satisfied for the year, are set forth below: DCF as a Percentage of Percentage of DCF Levels of Budgeted DCF Bonus that would DCF Bonus for 2017 be Paid Threshold 80% 50% Target 100% 100% Maximum 110% 200% If DCF performance falls in between threshold and target, or between target and maximum, the amounts payable areadjusted ratably using straight line interpolation. If DCF is satisfied above maximum levels, the potential payment of theDCF Bonus is capped at the maximum level of 200%. For the year ended December 31, 2017, the remaining twenty-five percent (25%) of the Target Bonus was subject toindividual objectives specific to each eligible individual’s role at USAC Management (the “Individual Bonus”). Theindividual objectives are agreed upon in advance between the NEO and his immediate supervisor (or, with respect to thechief executive officer, between the board of directors of our general partner and the chief executive officer) and suchobjectives address the key priorities for that NEO’s position. They may include key operating objectives as well as personaldevelopment criteria. The Individual Bonus is subject to a maximum payout of 100% of the targeted Individual Bonusamount, although the board of directors of our general partner has discretion to pay out smaller amounts ranging from 0% to100%, at their sole discretion, after analyzing the individual’s personal performance for the year. In connection with theIndividual Bonus for the year ended December 31, 2017, each of the NEOs met with their immediate supervisor (or, withrespect to the chief executive officer, the board of directors of our general partner) to set individual objectives that reflectedthe responsibilities and priorities of their position. For the year ended December 31, 2017, in the aggregate, the maximum amount payable with respect to a Target Bonusunder the Plan is 175%, as the DCF Bonus is capped at 200% of target and the Individual Bonus is capped at 100% of target.Target Bonuses, if any, are paid within one week following delivery by our independent auditor of the audit of our financialstatements for the year in which the Target Bonus relates, but in no case later than March 15 of the year following the year inwhich the Target Bonus relates. For the year ended December 31, 2017, DCF exceeded the target threshold by 2.2%, whichresulted in the DCF portion of the Cash Plan (comprising seventy-five percent of the overall Bonus) being paid to each NEOat the rate of 122% for the DCF Bonus. With respect to the Individual Bonus75 Table of Contentsportion of the overall Bonus, each NEO was determined by his immediate supervisor (which in the case of the chief executiveofficer is the board of directors of our general partner) to have satisfied his individual objectives and therefore was entitled toreceive 100% of the Individual Bonus. The awards made pursuant to the Cash Plan with respect to the 2017 year were: Eric D. Long $721,436 William G. Manias $396,711 Matthew C. Liuzzi $329,496 Benefit Plans and Perquisites We provide our executive officers, including our NEOs, with certain personal benefits and perquisites, which we do notconsider to be a significant component of executive compensation but which we recognize are an important factor inattracting and retaining talented executives. Executive officers are eligible under the same plans as all other employees withrespect to our medical, dental, vision, disability and life insurance plans and a defined contribution plan that is tax-qualifiedunder Section 401(k) of the Internal Revenue Code and that we refer to as the 401(k) Plan. We also provide certain executiveofficers with an annual automobile allowance. We provide these supplemental benefits to our executive officers due to therelatively low cost of such benefits and the value they provide in assisting us in attracting and retaining talented executives.The value of personal benefits and perquisites we provide to each of our NEOs is set forth above in our “—SummaryCompensation Table.” Discretionary Long-Term Equity Incentive Awards The board of directors of our general partner has adopted an LTIP. The LTIP was designed to promote our interests, aswell as the interests of our unitholders, by rewarding the officers, employees and directors of us, our subsidiaries and ourgeneral partner for delivering desired performance results, as well as by strengthening our and our general partner’s ability toattract, retain and motivate qualified individuals to serve as officers, employees and directors. The LTIP provides for thegrant, from time to time at the discretion of the board of directors of our general partner, of unit awards, restricted units,phantom units, unit options, unit appreciation rights, DERs and other unit-based awards, although in 2017, as well as in2016, the board of directors of our general partner only granted phantom unit awards pursuant to the LTIP. The outstandingLTIP awards held by our NEOs are reflected in the table below. During 2017 the board of directors of our general partner granted phantom unit awards to certain key employees,including our NEOs. With respect to our 2017 and 2016 awards, twenty percent (20%) of the phantom unit award to eachindividual is subject to a performance-based vesting formula and the remaining eighty percent (80%) of the phantom unitaward is subject to time-based vesting restrictions. With respect to the time-based phantom unit awards, the awards will vestin three equal annual installments, with the first installment vesting on the first anniversary of the date of grant. With respectto the performance-based phantom unit awards, the awards will vest based upon our level of total unitholder return (“TUR”)relative to a group of peer companies over the period beginning December 31, 2016 and ending December 31, 2019 for the2017 award, and beginning December 31, 2015 and ending December 31, 2018 for the 2016 award. The peer groupcompanies are the constituent companies in the Alerian Natural Gas MLP Index, as reported in the Alerian CapitalManagement or other relevant reporter. The performance-based phantom unit awards are granted at a “target” level, but willbe eligible to vest from 0%-200% of the target level. Threshold levels (50% of target) are set at the 35 percentile of theconstituent companies, target levels (100% of target) are set at the 50 percentile of the constituent companies, andmaximum levels (200%) are set at the 90 percentile of the constituent companies. The awards will be adjusted ratably usingstraight line interpolation for TUR results between threshold and target and between target and maximum. Each phantom unit granted to an employee, including the NEOs, is granted in tandem with a corresponding DER, whichis paid quarterly on the distribution date from the grant date until the earlier of the vesting or the forfeiture of the relatedphantom units. With respect to the performance-based phantom units, the DERs will only be granted with respect to thetarget level number, and will not be adjusted up or down depending on the actual TUR results. The DERs entitle the recipientof the award to a payment equivalent to the amount of the per common unit distribution payable to common unitholdersfollowing the grant date of such DERs for each phantom unit granted in tandem with such rights.76 thththTable of Contents Mr. Long was also granted Class B Units of USA Compression Holdings at the time we were acquired by USACompression Holdings in 2010. Mr. Manias and Mr. Liuzzi were granted Class B Units of USA Compression Holdings at thetime of their employment. The grants the NEOs received had time-based vesting requirements (which, for Mr. Long, weresatisfied in full as of December 31, 2013 and, for Mr. Manias and Mr. Liuzzi, were satisfied in full as of December 31, 2017)and are designed not only to compensate but also to motivate and retain the recipients by providing an opportunity forequity ownership by our NEOs. The grants to our NEOs also provide our NEOs with meaningful incentives to increaseunitholder value over time. The Class B Units are profits interests that allow our NEOs to participate in the increase in valueof USA Compression Holdings over and above an annual and cumulative preferred return hurdle. Available cash will bedistributed to the USA Compression Holdings members at such times as determined by its board of managers, at which timethe holders of Class B Units could receive distributions if the cash distributed reaches the required distribution hurdles.Distributions to the Class B Unitholders could also occur in connection with a sale or liquidation event of USA CompressionHoldings. To date, our NEOs have not received distributions with respect to these awards. Outstanding Equity Awards as of December 31, 2017 The following table provides information regarding the Class B Units in USA Compression Holdings held by the NEOsas of December 31, 2017. None of our NEOs held any option awards that were outstanding as of December 31, 2016 and2017. Also reflected within the table are the outstanding phantom units that were granted to our NEOs from the LTIP duringthe years ended December 31, 2015, 2016 and 2017, respectively. Unit Awards Equity Incentive Plan Awards Number of Number of Market Number ofUnearned Market ValueOf Class B Units Outstanding Value of Units That Have Unearned UnitsThat That HaveVested but PhantomUnits Outstanding Not Vested Have Not Vested Are StillOutstanding (Time-Based) PhantomUnits (Performance-Based) (Performance-Based)Name (#)(1) (#) ($) (5) (#) ($) (5)Eric D. Long 481,250 2015 Grant 25,176(2)416,411 2016 Grant 134,484(3)2,224,365 100,862(6)1,668,2572017 Grant 81,598(4)1,349,631 40,800(7)674,832William G. Manias 125,000 2015 Grant 12,168(2)201,259 2016 Grant 75,979(3)1,256,693 56,984(6)942,5152017 Grant 41,490(4)686,245 20,746(7)343,139Matthew C. Liuzzi 62,500 2015 Grant 9,843(2)162,803 2016 Grant 60,580(3)1,001,993 45,436(6)751,5112017 Grant 32,673(4)540,411 16,336(7)270,197(1)Represents the number of Class B Units in USA Compression Holdings that became vested but had not been settled as of December 31,2017. These Class B Units vested 25% on the one-year anniversary of the date of grant and 1/36 monthly thereafter; provided that withrespect to Mr. Long 50% of the then-unvested portion of Class B Units vested at the time of our initial public offering, which occurred onJanuary 18, 2013. (2)Represents the number of phantom units issued on February 19, 2015 pursuant to the LTIP that had not vested as of December 31, 2017.Each phantom unit is the economic equivalent of one common unit. The phantom units are scheduled to vest in three equal annualinstallments on each subsequent February 15 with the first installment vesting on February 15, 2016. In the event of cessation of theNEO’s service for any reason, all phantom units that have not vested prior to or in connection with such cessation of service shallautomatically be forfeited. (3)Represents the number of time-based phantom units issued on February 11, 2016 pursuant to the LTIP that had not vested as ofDecember 31, 2017. Each phantom unit is the economic equivalent of one common unit. The phantom units are scheduled to vest in threeequal annual installments on each subsequent February 15 with the first installment vesting on February 15, 2017. In the77 ththTable of Contentsevent of cessation of the NEO’s service for any reason, all phantom units that have not vested prior to or in connection with suchcessation of service shall automatically be forfeited. (4)Represents the number of time-based phantom units issued on February 13, 2017 pursuant to the LTIP that had not vested as ofDecember 31, 2017. Each phantom unit is the economic equivalent of one common unit. The phantom units are scheduled to vest in threeequal annual installments on each subsequent February 15 with the first installment vesting on February 15, 2018. In the event ofcessation of the NEO’s service for any reason, all phantom units that have not vested prior to or in connection with such cessation ofservice shall automatically be forfeited. (5)Market value is calculated using the value of $16.54, which was the closing price of our common units on December 29, 2017 (asDecember 31, 2017 was not a trading day). (6)Represents the number of performance-based phantom units granted on February 11, 2016 pursuant to the LTIP that had not vested as ofDecember 31, 2017. The number of performance-based phantom units was determined by calculating the level of TUR performance thatwould have been achieved as of December 31, 2017 with respect to our constituent companies, and reflecting the next highest level ofachievement within the table above, which was the maximum level. The performance period for these awards will end on December 31,2018 and will vest, if at all, based upon the level of TUR performance achieved at that time. Events that could result in accelerated vestingare described below under the heading “Severance and Change in Control Arrangements.” (7)Represents the number of performance-based phantom units granted on February 13, 2017 pursuant to the LTIP that had not vested as ofDecember 31, 2017. The number of performance-based phantom units was determined by calculating the level of TUR performance thatwould have been achieved as of December 31, 2017 with respect to our constituent companies, and reflecting the next highest level ofachievement within the table above, which was the maximum level. The performance period for these awards will end on December 31,2019 and will vest, if at all, based upon the level of TUR performance achieved at that time. Events that could result in accelerated vestingare described below under the heading “Severance and Change in Control Arrangements.” Severance and Change in Control Arrangements Our NEOs are entitled to severance payments and benefits upon certain terminations of employment and, in certaincases, in connection with a change in control (as defined below) of USA Compression Holdings. Each NEO currently has an employment agreement with USAC Management that provides for severance benefits upon atermination of employment. On January 1, 2013, we entered into the services agreement with USAC Management, pursuantto which USAC Management provides to us and our general partner management, administrative and operating services andpersonnel to manage and operate our business. Pursuant to the services agreement, we will reimburse USAC Management forthe allocable expenses for the services performed, including the salary, bonus, cash incentive compensation and otheramounts paid to our NEOs. See Part III, Item 13 (“Certain Relationships and Related Transactions, and DirectorIndependence”). Severance Arrangements Each NEO’s employment agreement had an initial term that has been extended on a year-to-year basis and will beextended automatically for successive twelve-month periods thereafter unless either party delivers written notice to the otherwithin ninety days prior to the expiration of the then-current employment term. Upon termination of an NEO’s employmentfor any reason, all earned, unpaid annual base salary and vacation time (and, with respect to the chief executive officer,accrued, unused sick time off) shall be paid to the NEO within thirty (30) days of the date of the NEO’s termination ofemployment. Upon termination of an NEO’s employment either by us for convenience or due to the NEO’s resignation forgood reason, subject to the timely execution of a general release of claims, the NEO is entitled to receive (i) an amount equalto one times his annual base salary (plus, in the case of Mr. Long, an amount equal to one times his target annual bonus),payable in equal semi-monthly installments over one year following termination (the “Severance Period”) (or, if suchtermination occurs within two years following a change in control, in a lump sum within thirty days following thetermination of employment), subject to acceleration upon the NEO’s death during the Severance Period, and (ii) continuedcoverage for twenty-four (24) months (or, with respect to Mr. Long, thirty (30) months) under our group medical plan inwhich the executive and any of his dependents were participating immediately prior to his termination. Continued coverageunder our group medical plan is subsidized for the first twelve (12) months78 thTable of Contentsfollowing termination, after which time continued coverage shall be provided at the NEO’s sole expense (except with respectto Mr. Long, who is entitled to reimbursement by us to the extent the cost of such coverage exceeds $1,200 per month) forthe remainder of the applicable period. Additionally, upon a termination of an NEO’s employment by us for convenience, bythe NEO for good reason, or due to the NEO’s death or disability, the NEO is entitled to receive (i) an amount equal to onetimes his annual bonus (up to his target annual bonus) for the immediately preceding year and (ii) a pro-rata portion of anyearned annual bonus for the year in which termination occurs. During employment and for two years following termination,each NEO’s employment agreement prohibits him from competing with our business. As used in the NEOs’ employment agreements, a termination for “convenience” means an involuntary termination forany reason, including a failure to renew the employment agreement at the end of an initial term or any renewal term, otherthan a termination for “cause.” “Cause” is defined in the NEOs’ employment agreements to mean (i) any material breach ofthe employment agreement or the Holdings Operating Agreement, by the executive, (ii) the executive’s breach of anyapplicable duties of loyalty to us or any of our affiliates, gross negligence or misconduct, or a significant act or acts ofpersonal dishonesty or deceit, taken by the executive, in the performance of the duties and services required of the executivethat has a material adverse effect on us or any of our affiliates, (iii) conviction or indictment of the executive of, or a plea ofnolo contendere by the executive to, a felony, (iv) the executive’s willful and continued failure or refusal to performsubstantially the executive’s material obligations pursuant to the employment agreement or the Holdings OperatingAgreement or follow any lawful and reasonable directive from the board of managers of USA Compression Holdings(regarding Mr. Long) or the board of directors of our general partner (regarding Mr. Manias and Mr. Liuzzi) or, as applicable,the chief executive officer, other than as a result of the executive’s incapacity, or (v) a pattern of illegal conduct by theexecutive that is materially injurious to us or any of our affiliates or our or their reputation. “Good reason” is defined in the NEOs’ employment agreements to mean (i) a material breach by us of the employmentagreement, the Holdings Operating Agreement, or any other material agreement with the executive, (ii) any failure by us topay to the executive the amounts or benefits to which he is entitled, other than an isolated and inadvertent failure notcommitted in bad faith, (iii) a material reduction in the executive’s duties, reporting relationships or responsibilities, (iv) amaterial reduction by us in the facilities or perquisites available to the executive or in the executive’s base salary, other thana reduction that is generally applicable to all similarly situated employees, or (v) the relocation of the geographic location ofthe executive’s current principal place of employment by more than fifty miles from the location of the executive’s principalplace of employment. With respect to Mr. Long’s employment agreement, “good reason” also means the failure to appointand maintain Mr. Long in the office of President and Chief Executive Officer. In the event of cessation of the NEO’s service for any reason, all phantom units that have not vested prior to or inconnection with such cessation of service shall automatically be forfeited. With respect to the time-based awards for Mr.Manias and Mr. Liuzzi, the awards will receive accelerated vesting in the event that that the holder is terminated withoutcause or for good reason (as each term is defined above with respect to the employment agreements) in connection with achange in control event. With respect to the time-based awards for Mr. Long, the award will receive accelerated vesting inconnection with a change in control event regardless of whether Mr. Long’s service is terminated in connection with suchchange in control. All performance-based phantom unit awards will receive accelerated vesting at target levels in connectionwith a change in control event (subject to the discretion of the compensation committee to vest a greater portion). Each of the Class B Units held by the NEOs would be forfeited for no consideration if the NEO was terminated for cause.A termination for “Cause” under the USA Compression Holdings limited liability company agreement is definedsubstantially the same as the term used within the employment agreements described above. In the event that the NEO’semployment is terminated for any reason, however, USA Compression Holdings (or its nominee) shall have the right, but notthe obligation, to repurchase any vested Class B Units held by the terminated NEO for then-current fair market value or otheragreed value. Change in Control Benefits We generally have double-trigger change in control benefits for our outstanding LTIP awards, although in 2017 and2016 we granted performance-based phantom unit awards that could become vested upon a change in control. If a79 Table of Contentschange in control occurs, and our NEOs are also terminated without cause or for good reason (each term as defined in theNEO’s employment agreement) in connection with that change in control event, the current time-based LTIP phantom unitswould become fully vested. One exception to this practice is with respect to our CEO, who would receive immediate vestingof any outstanding time-based phantom units upon the change in control event. The performance-based phantom unitsgranted during 2017 and 2016 will become eligible to vest at target levels in the event of a change in control. In addition, aportion (subject to the discretion of the compensation committee) of each LTIP award granted to our NEOs during the yearending December 31, 2017 will immediately vest immediately prior to the change in control event. For example, the numberof phantom units that would vest upon change in control as a result of the CDM Acquisition would be 192,471 for Mr. Long,38,865 for Mr. Manias and 30,886 for Mr. Liuzzi. A “Change in Control” is generally defined within the LTIP as the occurrence of one of the following events: (i) anyperson or group, other than our general partner, Riverstone Holdings LLC or an affiliate of our general partner or RiverstoneHoldings LLC, shall become the beneficial owner, by way of merger, consolidation, recapitalization, reorganization orotherwise, of 50% or more of the combined voting power of our equity interests or the equity interests of our general partner;(ii) our shareholders approve, in one or a series of transactions, a plan of complete liquidation; (iii) the sale or otherdisposition by either us or our general partner of all or substantially all of its assets in one or more transactions to any personother than to us, our general partner, Riverstone Holdings LLC or an affiliate of us, our general partner or RiverstoneHoldings LLC; (iv) a transaction resulting in a person other than our general partner, Riverstone Holdings LLC or an affiliateof our general partner or Riverstone Holdings LLC being our sole general partner. However, if an LTIP award is subject tosection 409A of the Internal Revenue Code, a “Change in Control” will be defined in accordance with section 409A of theInternal Revenue Code and the regulations promulgated thereunder. Director Compensation For the year ended December 31, 2017, Mr. Long, our only NEO who also served as a director, did not receive additionalcompensation for his service as a director. Mr. Long’s compensation as an executive is reflected in the SummaryCompensation Table above. Only the independent members of the board of directors of our general partner receivecompensation for their service as directors. The following table shows the total compensation earned by each independent director during 2017. Fees Earned or All Other Paid in Cash Unit Awards Compensation TotalName ($) ($) (1) ($) (2) ($)John D. Chandler 85,500 —(3)23,861 109,361Robert F. End 136,000 75,000 23,861 234,861Forrest E. Wylie 117,000(4)75,000 47,725 239,725Jerry L. Peters 46,500 — — 46,500(1)Represents the grant date fair value of our phantom units, calculated in accordance with ASC 718. For a detailed discussion of theassumptions utilized in coming to these values, please see Note 9 to our consolidated financial statements. As of December 31, 2017, theindependent members of the board of directors of our general partner held the following number of outstanding equity awards under theLTIP: Mr. End, 4,073 phantom units; and Mr. Wylie, 8,147 phantom units.(2)Amounts in this column reflect the value of DERs, received by the directors with respect to their outstanding phantom unit awards.(3)Mr. Chandler’s outstanding equity awards were forfeited upon his resignation during 2017.(4)Mr. Wylie elected to receive his annual cash retainer of $75,000 in phantom units that will vest in full on February 15, 2018. Officers, employees or paid consultants or advisors of us or our general partner or its affiliates who also serve as directorsdo not receive additional compensation for their service as directors. Our directors who are not officers, employees or paidconsultants or advisors of us or our general partner or its affiliates receive cash and equity based80 Table of Contentscompensation for their services as directors. Our director compensation program consists of the following and will be subjectto revision by the board of directors of our general partner from time to time: ·an annual cash retainer of $75,000, ·an additional annual retainer of $15,000 for service as the chair of any standing committee, ·meeting attendance fees of $2,000 per meeting attended, and ·an annual equity based award in the form of phantom units that will be granted under the LTIP, having a value as ofthe grant date of $75,000. Phantom unit awards are expected to be subject to vesting conditions (which, for the 2017phantom unit grants was a one year vesting period). DERs will be paid either on a current or deferred basis, in eachcase as will be determined at the time of grant of the awards; the 2017 phantom unit awards provided for deferredDERs. Directors will also receive reimbursement for out-of-pocket expenses associated with attending such board or committeemeetings and director and officer liability insurance coverage. Each director will be fully indemnified by us for actionsassociated with being a director to the fullest extent permitted under Delaware law. ITEM 12.Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters Security Ownership of Certain Beneficial Owners and Management The following table sets forth the beneficial ownership of our units as of February 8, 2018 held by: ·each person who beneficially owns 5% or more of our outstanding units; ·all of the directors of USA Compression GP, LLC; ·each named executive officer of USA Compression GP, LLC; and ·all directors and executive officers of USA Compression GP, LLC as a group. 81 Table of ContentsExcept as indicated by footnote, the persons named in the table below have sole voting and investment power withrespect to all units shown as beneficially owned by them and their address is 100 Congress Avenue, Suite 450, Austin, Texas78701. Percentage of Common Units Common Units Name of Beneficial Owner BeneficiallyOwned Beneficially Owned USA Compression Holdings (1) 25,092,196 40.3% Argonaut (2) 7,715,948 12.4% Oppenheimer Funds, Inc. (3) 6,529,518 10.5% Eric D. Long (4) 359,579 * William G. Manias (5) 161,620 * Matthew C. Liuzzi (6) 111,764 * Jerry L. Peters — — Jim H. Derryberry — — William H. Shea, Jr. — — Robert F. End (7) 33,717 * Olivia C. Wassenaar — — Forrest E. Wylie (8) 54,116 * All directors and executive officers as a group (12 persons) (9) 856,973 1.4% *Less than 1%. (1)Eric D. Long, Matthew C. Liuzzi, William G. Manias, and David A. Smith, each of whom are executive officers of our general partner,Aladdin Partners, L.P., a limited partnership affiliated with Mr. Long, and R/C IV USACP Holdings, L.P. (“R/C Holdings”), own equityinterests in USA Compression Holdings. USA Compression Holdings is managed by a three person board of managers consisting ofMr. Long, Mr. Derryberry and Ms. Wassenaar. The board of managers exercises investment discretion and control over the units held byUSA Compression Holdings. R/C Holdings is the record holder of approximately 97.6% of the limited liability company interests of USA Compression Holdings andis entitled to elect a majority of the members of the board of managers of USA Compression Holdings. R/C Holdings is an investmentpartnership affiliated with Riverstone/Carlyle Global Energy and Power Fund IV, L.P. (“R/C IV”). Management and control of R/CHoldings is vested in its general partner, which is in turn managed and controlled by its general partner, R/C Energy GP IV, LLC. Theprincipal business address of R/C Energy GP IV, LLC is 712 Fifth Avenue, 51st Floor, New York, New York 10019. Mr. Long, Mr. Derryberry and Ms. Wassenaar, each of whom is a member of the board of managers of USA Compression Holdings anda member of the board of directors of our general partner, each disclaims beneficial ownership of the units owned by USA CompressionHoldings. (2)Argonaut has sole voting and dispositive power of 7,715,948 common units. The principal business address of Argonaut is 6733 SouthYale Avenue, Tulsa, Oklahoma 74136. (3)Oppenheimer Funds, Inc. has the shared power to vote or to direct the vote, and the shared power to dispose or to direct the dispositionof, 6,529,518 common units based on Amendment No. 8 to Schedule 13G filed on February 6, 2018 with the SEC. The principalbusiness address of Oppenheimer Funds, Inc. is Two World Financial Center, 225 Liberty Street, New York, New York 10281. (4)Includes 184,947 common units held directly by Mr. Long, 7,592 common units held by Aladdin Partners, L.P., a limited partnershipaffiliated with Mr. Long, 45,248 common units held by certain trusts of which Mr. Long is the trustee, 2,174 common units held byMr. Long’s spouse and 119,618 common units that Mr. Long has the right to acquire within 60 days upon the vesting and/or settlementof his phantom units, subject to compensation committee discretion. Mr. Long disclaims any beneficial ownership of the units held byMr. Long’s spouse, except to the extent of his pecuniary interest therein. Mr. Long also has the right to acquire an additional 192,471common units upon vesting and/or settlement of his phantom units upon the closing of the CDM Acquisition, which could occur within60 days from February 8, 2018. (5)Includes 63,988 common units that Mr. Manias has the right to acquire within 60 days upon the vesting and/or settlement of his phantomunits, subject to compensation committee discretion. Mr. Manias also has the right to acquire an additional 38,86582 Table of Contentscommon units upon vesting and/or settlement of his phantom units upon the closing of the CDM Acquisition, which could occur within60 days from February 8, 2018. (6)Includes 51,024 common units that Mr. Liuzzi has the right to acquire within 60 days upon the vesting and/or settlement of his phantomunits, subject to compensation committee discretion. Mr. Liuzzi also has the right to acquire an additional 30,886 common units uponvesting and/or settlement of his phantom units upon the closing of the CDM Acquisition, which could occur within 60 days fromFebruary 8, 2018. (7)Includes 4,073 common units that Mr. End has the right to acquire within 60 days upon the vesting and/or settlement of his phantomunits. (8)Includes 8,147 common units that Mr. Wylie has the right to acquire within 60 days upon the vesting and/or settlement of his phantomunits. (9)Includes 309,891 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. Certain of our directors and executive officershave the right to acquire an additional 300,568 common units upon vesting and/or settlement of phantom units held by such directors andexecutive officers upon the closing of the CDM Acquisition, which could occur within 60 days from February 8, 2018. Securities Authorized for Issuance Under Equity Compensation Plans In connection with the consummation of our initial public offering on January 18, 2013, the board of directors of ourgeneral partner adopted the LTIP. The following table provides certain information with respect to this plan as ofDecember 31, 2017: 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 1,086,858 N/A —(1)(1)As of December 31, 2017, the number of common units that may be delivered pursuant to awards under the LTIP was 755,804 commonunits before giving effect to any outstanding awards. Awards that are forfeited, cancelled, paid or otherwise terminate or expire withoutthe actual delivery of units will be available for delivery pursuant to other awards. Currently, only phantom unit awards are outstandingunder the LTIP. Pursuant to the terms of the LTIP, each phantom unit award is the economic equivalent of one common unit and may besettled in cash or common units at the discretion of the board of directors of our general partner or a committee thereof. Any phantom unitsettled in cash will not result in the actual delivery of a common unit. For more information about our LTIP, please see Note 9 to our consolidated financial statements. ITEM 13.Certain Relationships and Related Transactions, and Director Independence Certain Relationships And Related Party Transactions Services Agreement In connection with our formation and initial public offering, we and other parties have entered into the followingagreements. These agreements were not the result of arm’s length negotiations, and they, or any of the transactions that theyprovide for, may not be effected on terms as favorable to the parties to these agreements as could have been obtained fromunaffiliated third parties.83 Table of Contents We entered into a services agreement with USAC Management, effective on January 1, 2013, pursuant to which USACManagement provides to us and our general partner management, administrative and operating services and personnel tomanage and operate our business. We or one of our subsidiaries pays USAC Management for the allocable expenses it incursin its performance under the services agreement. These expenses include, among other things, salary, bonus, cash incentivecompensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocatedby USAC Management to us. USAC Management has substantial discretion to determine in good faith which expenses toincur on our behalf and what portion to allocate to us. On November 3, 2017, the term of the services agreement was extended to December 31, 2022 pursuant to an amendmentto that certain services agreement. The services agreement may be terminated at any time by (i) the board of directors of ourgeneral partner upon 120 days’ written notice for any reason in its sole discretion or (ii) USAC Management upon 120 days’written notice if: (a) we or our general partner experience a change of control; (b) we or our general partner breach the termsof the services agreement in any material respect following 30 days’ written notice detailing the breach (which breachremains uncured after such period); (c) a receiver is appointed for all or substantially all of our or our general partner’sproperty or an order is made to wind up our or our general partner’s business; (d) a final judgment, order or decree thatmaterially and adversely affects the ability of us or our general partner to perform under the services agreement is obtained orentered against us or our general partner, and such judgment, order or decree is not vacated, discharged or stayed; or(e) certain events of bankruptcy, insolvency or reorganization of us or our general partner occur. USAC Management will notbe liable to us for their performance of, or failure to perform, services under the services agreement unless its acts or omissionsconstitute gross negligence or willful misconduct. Other Related Party Transactions We provide compression services to entities affiliated with Riverstone/Carlyle Global Energy and Power Fund IV, L.P.(“Riverstone”), which owns a majority of the membership interests in USA Compression Holdings. As of December 31, 2017,USA Compression Holdings owned and controlled our general partner and owned approximately 40% of our limited partnerinterests. We recognized $0.7 million and $0.4 million in revenue from compression services from such affiliated entities forthe years ended December 31, 2017 and 2016, respectively. We may provide compression services to entities affiliated withRiverstone in the future, and any significant transactions will be disclosed. Procedures for Review, Approval and Ratification of Related Person Transactions The board of directors of our general partner adopted a code of business conduct and ethics in connection with theclosing of our initial public offering that provides that the board of directors of our general partner or its authorizedcommittee will periodically review all related person transactions that are required to be disclosed under SEC rules and, whenappropriate, initially authorize or ratify all such transactions. If the board of directors of our general partner or its authorizedcommittee considers ratification of a related person transaction and determines not to so ratify, the code of business conductand ethics provides that our management will make all reasonable efforts to cancel or annul the transaction. The code of business conduct and ethics provides that, in determining whether or not to recommend the initial approvalor ratification of a related person transaction, the board of directors of our general partner or its authorized committee shouldconsider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there isan appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction;(iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on adirector’s independence (in the event the related person is a director, an immediate family member of a director or an entity inwhich a director or an immediate family member of a director is a partner, shareholder, member or executive officer); (v) theavailability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing,related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conductand ethics. The code of business conduct and ethics described above was adopted in connection with the closing of our initialpublic offering, and as a result the transaction described above was not reviewed under such policy. The transaction84 Table of Contentsdescribed above was not approved by an independent committee of our board of directors of our general partner and theterms were determined by negotiation among the parties. Conflicts of Interest Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and itsaffiliates, including USA Compression Holdings, on the one hand, and our partnership and our limited partners, on the otherhand. The directors and officers of our general partner have fiduciary duties to manage our general partner in a mannerbeneficial to its owners. At the same time, our general partner has a fiduciary duty to manage our partnership in a mannerbeneficial to us and our unitholders. Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners,on the other hand, our general partner will resolve that conflict. Our partnership agreement contains provisions that modifyand limit our general partner’s fiduciary duties to our unitholders. Our partnership agreement also restricts the remediesavailable to our unitholders for actions taken by our general partner that, without those limitations, might constitute breachesof its fiduciary duty. Our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us orour unitholders if the resolution of the conflict is: ·approved by the conflicts committee of our general partner, although our general partner is not obligated to seeksuch approval; ·approved by the vote of a majority of the outstanding common units, excluding any common units owned by ourgeneral partner or any of its affiliates; ·on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or ·fair and reasonable to us, taking into account the totality of the relationships among the parties involved, includingother transactions that may be particularly favorable or advantageous to us. Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of itsboard of directors. In connection with a situation involving a conflict of interest, any determination by our general partnerinvolving the resolution of the conflict of interest must be made in good faith, provided that, if our general partner does notseek approval from the conflicts committee and its board of directors determines that the resolution or course of action takenwith respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, thenit will conclusively be deemed that, in making its decision, the board of directors acted in good faith. Unless the resolution ofa conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee mayconsider any factors that it determines in good faith to be appropriate when resolving a conflict. When our partnershipagreement provides that someone act in good faith, it requires that person to reasonably believe he is acting in the bestinterests of the partnership. Director Independence Please see Part III, Item 10 (“Directors, Executive Officers and Corporate Governance—Board of Directors”) for adiscussion of director independence matters. 85 Table of Contents ITEM 14.Principal Accountant Fees and Services The following table presents fees for professional services rendered by our independent registered public accountingfirm, KPMG LLP during the years ended December 31, 2017 and 2016: Year Ended December31, 2017 2016 (in millions)Audit Fees (1) $0.6 $0.6Audit-Related Fees — —Tax Fees — —All Other Fees — —Total $0.6 $0.6(1)Expenditures classified as “Audit Fees” above were billed to USA Compression Partners, LP and include the audits of our annualfinancial statements, work related to the registration statements, reviews of our quarterly financial statements, and fees associated withcomfort letters and consents related to equity offerings and registration statements. Our audit committee has adopted an audit committee charter, which is available on our website and which requires theaudit 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. 86 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: ExhibitNumber 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 First 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 January 18, 2013) 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) 10.2 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 (File No.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 thereto andJPMorgan 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) 87 Table of Contents10.4 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† 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) 10.7† 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) 10.8† 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) 10.9† 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) 10.10 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) 10.11 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) 10.12† 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) 10.13† 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-Kfor the year ended December 31, 2013 (File No. 001-35779) filed on February 20, 2014) 10.14† 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) 10.15† 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) 10.16† 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) 88 Table of Contents10.17 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) 21.1* List of subsidiaries of USA Compression Partners, LP 23.1* Consent of KPMG LLP 31.1* Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act 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 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.89 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 12, 2018 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 12, 2018. 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/ Jerry L. Peters Jerry L. Peters Director /s/ Jim H. Derryberry Jim H. Derryberry Director /s/ Robert F. End Robert F. End Director /s/ William H. Shea, Jr. William H. Shea, Jr. Director /s/ Olivia C. Wassenaar Olivia C. Wassenaar Director /s/ Forrest E. Wylie Forrest E. Wylie Director /s/ Michael A. Wichterich Michael A. Wichterich Director 90 Table of ContentsINDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report of Independent Registered Public Accounting Firm F-2Consolidated Balance Sheets as of December 31, 2017 and 2016 F-3Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015 F-4Consolidated Statements of Changes in Partners’ Capital for the years ended December 31, 2017, 2016 and 2015 F-5Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015 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 The PartnersUSA Compression Partners, LP: Opinion on the Consolidated Financial StatementsWe have audited the accompanying consolidated balance sheets of USA Compression Partners, LP and subsidiaries (the“Partnership”) as of December 31, 2017 and 2016, the related consolidated statements of operations, changes in partners’capital, and cash flows for each of the years in the three‑year period ended December 31, 2017, and the related notes(collectively, the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, inall material respects, the financial position of the Partnership as of December 31, 2017 and 2016, and the results of itsoperations and its cash flows for each of the years in the three‑year period ended December 31, 2017, in conformity withU.S. generally accepted accounting principles.Basis for OpinionThese consolidated financial statements are the responsibility of the Partnership’s management. Our responsibility is toexpress an opinion on these consolidated financial statements based on our audits. We are a public accounting firmregistered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to beindependent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules andregulations 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 consolidated financial statements are free of materialmisstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an auditof its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internalcontrol over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership’sinternal control over financial reporting. Accordingly, we express no such opinion.Our audits included performing procedures to assess the risks of material misstatement of the consolidated financialstatements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures includedexamining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Ouraudits also included evaluating the accounting principles used and significant estimates made by management, as well asevaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonablebasis for our opinion. /s/ KPMG LLP We have served as the Partnership’s auditor since 2002.Dallas, TexasFebruary 12, 2018 F-2 Table of ContentsUSA COMPRESSION PARTNERS, LPConsolidated Balance Sheets(in thousands) December 31, 2017 2016 Assets Current assets: Cash and cash equivalents $47 $65 Accounts receivable, net: Trade, net 32,063 32,237 Other 8,500 9,028 Inventory, net 33,444 29,556 Prepaid expenses 2,835 2,083 Total current assets 76,889 72,969 Property and equipment, net 1,292,476 1,267,574 Installment receivable 10,635 14,079 Identifiable intangible assets, net 71,680 75,189 Goodwill 35,866 35,866 Other assets 4,541 6,735 Total assets $1,492,087 $1,472,412 Liabilities and Partners’ Capital Current liabilities: Accounts payable $20,020 $13,148 Accrued liabilities 26,263 26,572 Deferred revenue 27,488 16,691 Total current liabilities 73,771 56,411 Long-term debt 782,902 685,371 Other liabilities 1,561 1,113 Partners’ capital: Limited partner interest: Common units, 62,194 and 60,689 units issued and outstanding, respectively 626,922 721,080 General partner interest 6,931 8,437 Total partners’ capital 633,853 729,517 Total liabilities and partners’ capital $1,492,087 $1,472,412 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, 2017 2016 2015 Revenues: Contract operations $264,315 $246,950 $263,816 Parts and service 15,907 18,971 6,729 Total revenues 280,222 265,921 270,545 Costs and expenses: Cost of operations, exclusive of depreciation and amortization 92,591 88,161 81,539 Selling, general and administrative 47,483 44,483 40,950 Depreciation and amortization 98,603 92,337 85,238 Loss (gain) on disposition of assets (507) 772 (1,040) Impairment of compression equipment 4,972 5,760 27,274 Impairment of goodwill — — 172,189 Total costs and expenses 243,142 231,513 406,150 Operating income (loss) 37,080 34,408 (135,605) Other income (expense): Interest expense, net (25,129) (21,087) (17,605) Other 27 35 22 Total other expense (25,102) (21,052) (17,583) Net income (loss) before income tax expense 11,978 13,356 (153,188) Income tax expense 538 421 1,085 Net income (loss) $11,440 $12,935 $(154,273) Net income (loss) allocated to: General partner’s interest in net income (loss) $1,493 $1,364 $(1,477) Limited partners’ interest in net income (loss): Common units $9,947 $14,282 $(107,513) Subordinated units $(2,711) $(45,283) Weighted average common units outstanding: Basic 61,555 53,043 34,110 Diluted 61,835 53,344 34,110 Basic and diluted weighted average subordinated units outstanding 1,766 14,049 Basic and diluted net income (loss) per common unit $0.16 $0.27 $(3.15) Basic and diluted net income (loss) per subordinated unit $(1.54) $(3.22) Distributions declared per limited partner unit $2.10 $2.10 $2.09 See accompanying notes to consolidated financial statements. F-4 Table of ContentsUSA COMPRESSION PARTNERS, LPConsolidated Statements of Changes in Partners’ Capital(in thousands) Partners’ Capital Total Common Units Subordinated Units General PartnerInterest Partners’ Units Amount Units Amount Amount Capital Partners’ capital, December 31, 2014 31,307 $600,401 14,049 $225,221 $13,898 $839,520 Vesting of phantom units 101 1,844 — — — 1,844 Distributions and DERs — (69,480) — (29,151) (2,503) (101,134) Issuance of common units under the DRIP 3,113 56,895 — — — 56,895 Issuance of common units 4,035 75,111 — — — 75,111 Unit-based compensation of equity classified awards — 325 — — — 325 Net loss — (107,513) — (45,283) (1,477) (154,273) Partners’ capital, December 31, 2015 38,556 $557,583 14,049 $150,787 $9,918 $718,288 Vesting of phantom units 201 1,619 — — — 1,619 Distributions and DERs — (106,570) — (7,376) (2,845) (116,791) Issuance of common units under the DRIP 2,708 31,812 — — — 31,812 Issuance of common units 5,175 80,892 — — — 80,892 Unit-based compensation of equity classified awards — 762 — — — 762 Net income (loss) — 14,282 — (2,711) 1,364 12,935 Conversion of subordinated units to common units 14,049 140,700 (14,049) (140,700) — — Partners’ capital, December 31, 2016 60,689 $721,080 — $ — $8,437 $729,517 Vesting of phantom units 272 4,267 — — — 4,267 Distributions and DERs — (128,930) — — (2,999) (131,929) Issuance of common units under the DRIP 1,233 20,324 — — — 20,324 Unit-based compensation of equity classified awards — 234 — — — 234 Net income — 9,947 — — 1,493 11,440 Partners’ capital, December 31, 2017 62,194 $626,922 — $ — $6,931 $633,853 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, 2017 2016 2015 Cash flows from operating activities: Net income (loss) $11,440 $12,935 $(154,273) Adjustments to reconcile net income (loss) to net cash provided by operatingactivities: Depreciation and amortization 98,603 92,337 85,238 Amortization of debt issue costs 2,186 2,108 1,702 Unit-based compensation expense 11,708 10,373 3,863 Loss (gain) on disposition of assets (507) 772 (1,040) Impairment of compression equipment 4,972 5,760 27,274 Impairment of goodwill — — 172,189 Changes in assets and liabilities: Accounts receivable, net 4,146 (6,580) (439) Inventory, net (13,747) (16,448) (14,340) Prepaid expenses (751) 517 (1,580) Other noncurrent assets 8 16 (3) Accounts payable (1,841) (1,981) (3,310) Accrued liabilities and deferred revenue 8,427 3,888 2,120 Net cash provided by operating activities 124,644 103,697 117,401 Cash flows from investing activities: Capital expenditures, net (105,888) (51,240) (281,050) Proceeds from sale of property and equipment 657 336 1,735 Proceeds from insurance recovery — 73 1,157 Net cash used in investing activities (105,231) (50,831) (278,158) Cash flows from financing activities: Proceeds from long-term debt 397,806 300,593 480,004 Payments on long-term debt (300,275) (344,410) (345,681) Net proceeds from issuance of common units — 80,892 75,111 Cash paid related to net settlement of unit-based awards (2,844) (139) (210) Cash distributions (114,118) (87,731) (45,078) Financing costs — (2,013) (3,388) Net cash provided by (used in) financing activities (19,431) (52,808) 160,758 Increase (decrease) in cash and cash equivalents (18) 58 1 Cash and cash equivalents, beginning of year 65 7 6 Cash and cash equivalents, end of year $47 $65 $ 7 Supplemental cash flow information: Cash paid for interest $24,133 $20,489 $17,110 Cash paid for income taxes $160 $230 $282 Supplemental non-cash transactions: Non-cash distributions to certain limited partners (DRIP) $20,324 $31,812 $56,895 Transfers from inventory to property and equipment $9,860 $7,771 $4,004 Transfer from long term installment receivable to short term $(3,444) $(3,196) $(2,966) Change in capital expenditures included in accounts payable and accruedliabilities $(9,371) $11,753 $19,256 See accompanying notes to consolidated financial statements. F-6 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statements (1) Description and Nature of Business Unless otherwise indicated, the terms “our”, “we”, “us”, “the Partnership” and similar language refer to USACompression Partners, LP, collectively with its operating subsidiaries. We are a Delaware limited partnership. USACompression GP, LLC, a Delaware limited liability company, serves as our general partner and is referred to herein as the“General Partner”. Through our operating subsidiaries, we provide compression services under term contracts with customersin the natural gas and crude oil industries, using natural gas compression packages that we design, engineer, own, operateand maintain. We provide compression services in a number of shale plays throughout the United States, including the Utica,Marcellus, Permian Basin, Delaware Basin, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, Haynesville,Niobrara and Fayetteville shales. Certain of our operating subsidiaries are borrowers under a revolving credit facility and the Partnership is a guarantor ofthat revolving credit facility (see Note 7). The accompanying consolidated financial statements include the accounts of thePartnership and its operating subsidiaries, all of which are wholly owned by us. Net income (loss) is allocated to our general and limited partners using the two-class income allocation method. Allintercompany balances and transactions have been eliminated in consolidation. Our limited partner units trade on the NewYork Stock Exchange under the ticker symbol “USAC”. USA Compression Management Services, LLC (“USAC Management”), a wholly owned subsidiary of our 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, 2017, USAC Management had 426 full time employees. None of our employees are subject to collectivebargaining agreements. (2) Summary of Significant Accounting Policies (a)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. (b)Trade Accounts Receivable Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtfulaccounts, which was $0.4 million and $0.7 million as of December 31, 2017 and 2016, respectively, is our best estimate ofthe amount of probable credit losses included in our existing accounts receivable. We determine the allowance based uponhistorical write-off experience and specific customer circumstances. The determination of the allowance for doubtfulaccounts requires us to make estimates and judgments regarding our customers’ ability to pay amounts due. On an ongoingbasis, we conduct an evaluation of the financial strength of our customers based on payment history, the overall businessclimate in which our customers operate and specific identification of customer bad debt and make adjustments to theallowance 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. During the years ended December 31,2017 and 2016, we reduced our allowance for doubtful accounts by $0.3 million and $1.1 million, respectively, due mostlyto collections on accounts that had previously been reserved. Additionally during the year ended December 31, 2016, wewrote-off $0.3 million of accounts that had been previously reserved. Due to the decrease in the allowance for doubtfulaccounts during 2017 and 2016, we recognized a reduction of bad debt expense of $0.3 million and $1.1 million for theyears ended December 31, 2017 and 2016, respectively. Bad debt expense for the year ended December 31, 2015 was $1.8million. F-7 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statements (c)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. Components of inventory were as follows (in thousands): December 31, 2017 2016Serialized parts $16,413 $17,943Non-serialized parts 17,181 11,927Total Inventory, gross 33,594 29,870Less: obsolete and slow moving reserve (150) (314)Total Inventory, net $33,444 $29,556 (d)Property 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. Depreciation is calculated using the straight-line method overthe estimated useful lives of the assets as follows: Compression equipment, acquired new 25 yearsCompression equipment, acquired used 9 - 25 yearsFurniture and fixtures 7 yearsVehicles and computer equipment 3 - 7 yearsLeasehold improvements 5 years 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. Depreciation expense for the years ended December 31, 2017, 2016 and 2015 was $95.1 million, $88.8 million and$81.7 million, respectively. (e)Impairments of Long-Lived Assets Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-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 theundiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceedsthe sum of the undiscounted cash flows associated with the operating fleet, an impairment loss equal to the amount of thecarrying value exceeding the fair value of the asset is recognized. The fair value of the asset is measured using quoted marketprices or, in the absence of quoted market prices, based on an estimate of discounted cash flows, the expected net saleproceeds compared to the other similarly configured fleet units we recently sold or a review of other units recently offered forsale by third parties, or the estimated component value of the equipment we plan to use. F-8 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statements Refer to Note 3 for more detailed information about impairment charges during the years ended December 31, 2017,2016 and 2015. (f)Revenue Recognition Revenue from contract operations is recognized ratably as compression services are provided to customers under ourfixed-fee contracts over the term of the contract, which generally ranges from six months to five years. Parts and servicerevenue is recorded as parts are delivered or services are performed for the customer. Revenue and the associated expense from installation services, which includes the installation of stations for ourcustomers, is recorded using the percentage-of-completion method measured by the efforts-expended method. Revenue frominstallation services is included within the Parts and service revenue caption on our Consolidated Statements of Operations. (g)Income Taxes We have elected to be treated under SubChapter K of the Internal Revenue Code. Under SubChapter K, a partnershipreturn is filed annually reflecting each partner’s allocable share of our income or loss. Therefore, no provision has been madefor federal income tax in our accounts. For tax purposes, our net income (loss) is allocated to the partners in proportion totheir respective interest in us. As a partnership, all income, gains, losses, expenses, deductions and tax credits generated by us generally flow throughto our unitholders. However, Texas imposes an entity-level income tax on partnerships. Refer to Note 6 for more detailedinformation about the Revised Texas Franchise Tax for the years ended December 31, 2017, 2016 and 2015. (h)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 nonrecurring 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 part of the impairment analysis of goodwill as of December 31, 2015, the fair value of our goodwill was re-measuredusing Level 3 inputs. Refer to the Goodwill section below of this Note 2 for more information about this valuation as ofDecember 31, 2015. As of December 31, 2017 and 2016, our financial instruments consisted primarily of cash and cash equivalents, tradeaccounts receivable, trade accounts payable and long-term debt. The book values of cash and cash equivalents, tradeaccounts receivable, and trade accounts payable are representative of fair value due to their short-term maturities. Thecarrying amount of long-term debt approximates fair value due to the floating interest rates associated with the debt. (i)Pass Through Taxes Sales taxes incurred on behalf of, and passed through to, customers are accounted for on a net basis. F-9 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statements (j)Use of Estimates The preparation of our consolidated financial statements in conformity with accounting principles generally accepted inthe United States of America (“GAAP”) requires us to make estimates and assumptions that affect the amounts reported inthese consolidated financial statements and the accompanying results. Although these estimates are based on management’savailable knowledge of current and expected future events, actual results could differ from these estimates. (k)Identifiable Intangible Assets Identifiable intangible assets, net consisted of the following (in thousands): Customer Relationships Trade Names Non-compete TotalGross Balance at December 31, 2015 $78,700 $15,600 $900 $95,200Accumulated amortization (15,517) (3,744) (750) (20,011)Net Balance at December 31, 2016 $63,183 $11,856 $150 $75,189 Gross Balance at December 31, 2016 $78,700 $15,600 $900 $95,200Accumulated amortization (18,252) (4,368) (900) (23,520)Net Balance at December 31, 2017 $60,448 $11,232 $ — $71,680 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 20 to 30 years. Amortization expense for the year ended December 31, 2017 was$3.5 million and for each of the years ended December 31, 2016 and 2015 was $3.6 million. The expected amortization ofthe identifiable intangible assets for each of the five succeeding years is as follows (in thousands): Year Ending December 31, Total2018 $3,3592019 3,3592020 3,3592021 3,3592022 3,359 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, 2017, 2016 or 2015. (l)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 ofOctober 1, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not berecovered. As of October 1, 2017 and 2016, a quantitative assessment was performed to determine whether the fair value of oursingle reporting unit was greater than its carrying value. As of October 1, 2017 and 2016, the fair value was determined to bein excess of the carrying value. Due to the identification of certain impairment indicators during the fourth quarter of 2015, specifically (1) the declinein the market price of our common units, (2) the sustained decline in global commodity prices, and (3) the decline inperformance of the Alerian MLP Index, we prepared a quantitative assessment of our goodwill as of December 31, 2015. Thisassessment indicated that the calculated fair value was less than the carrying value. As such,F-10 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statements we prepared a Step 2 impairment test which measured the amount of the impairment loss and involved a hypotheticalallocation of the estimated fair value among the reporting unit’s assets and liabilities. The carrying value of goodwillexceeded the implied value of goodwill and an impairment charge was recorded for $172.2 million during the year endedDecember 31, 2015. The fair value of our single reporting unit was calculated using the Discounted Cash Flow Method, anincome approach. This method utilizes Level 3 inputs from the fair value hierarchy. The impairment of goodwill wasprimarily the result of the sustained decline in the market price of our common units. The continued decline in commodityprices adversely impacted many of our customers and resulted in a significant decline in their future capital expansion plans.This in turn reduced our expected future capital expansion plans and in turn, our estimated future cash flows as of December31, 2015. We had approximately $35.9 million of goodwill remaining on the balance sheet as of December 31, 2017 and 2016. Noimpairment of goodwill was recorded for the years ended December 31, 2017 and 2016. (m)Capitalized Interest For the years ended December 31, 2017, 2016 and 2015, we capitalized $0.3 million, $0.2 million and $0.3 million,respectively, of interest expense for interest costs incurred during the period related to upfront payments required inacquiring certain compression units. (n)Operating Segment We operate in a single business segment, the compression services business. (3) Property and Equipment Property and equipment consisted of the following (in thousands): December 31, 2017 2016Compression equipment $1,662,506 $1,551,157Furniture and fixtures 593 625Automobiles and vehicles 19,407 18,979Computer equipment 25,870 23,394Leasehold improvements 1,586 1,392Total Property and equipment, gross 1,709,962 1,595,547Less: accumulated depreciation and amortization (417,486) (327,973)Total Property and equipment, net $1,292,476 $1,267,574 As of December 31, 2017 and 2016, there was $10.8 million and $1.4 million, respectively, of property and equipmentpurchases in accounts payable and accrued liabilities. During the year ended December 31, 2017, we had a gain on disposition of compression equipment of $0.5 million.During the year ended December 31, 2016, we abandoned certain assets and incurred a $1.0 million loss. During the yearended December 31, 2015, insurance recoveries of $1.2 million were received on previously impaired compressionequipment. Each of these is reported within the Loss (gain) on disposition of assets caption in the Consolidated Statements ofOperations. During the years ended December 31, 2017, 2016 and 2015, we evaluated the future deployment of our idle fleet underthen-current market conditions and determined to retire, sell or re-utilize key components of 40 compressor units, orapproximately 11,000 horsepower, 29 compressor units, or approximately 15,000 horsepower, and 166 compressor units, orapproximately 58,000 horsepower, respectively, that were previously used to provide services in our business. The primarycauses for these impairments were due to: (i) units were not considered marketable in the foreseeable future, (ii) units weresubject to excessive maintenance costs or (iii) units were unlikely to be accepted by customers due to certain performancecharacteristics of the unit, such as the inability to meet then-current emissionF-11 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statements standards without excessive retrofitting costs. These compression units were written down to their respective estimatedsalvage values, if any. As a result of our decision to retire, sell or re-utilize these compressor units, management performed animpairment review and recorded $5.0 million, $5.8 million and $27.3 million in impairment of compression equipment forthe years ended December 31, 2017, 2016 and 2015, respectively. (4) Installment Receivable On June 30, 2014, we entered into a FMV Bargain Purchase Option Grant Agreement (the “BPO Capital LeaseTransaction”) with a customer, pursuant to which we granted a bargain purchase option to the customer with respect tocertain compressor packages leased to the customer. The bargain purchase option provides the customer with an option toacquire the equipment at a value significantly less than the fair market value at the end of the lease term, which is 7 years. On November 1, 2016, we entered into a Formula Price Purchase Agreement (the “FPP Capital Lease Transaction”) with acustomer with respect to certain assets leased to the customer that the customer will purchase at the end of the lease term. Thecustomer has the option to purchase these assets in April and October of each year with the final option occurring in April2021. Both capital leases were accounted for as sales type leases resulting in a current installment receivable included in otheraccounts receivable of $8.5 million and $8.9 million as of December 31, 2017 and 2016, respectively, and a long-terminstallment receivable of $10.6 million and $14.1 million as of such period ends, respectively. Additionally, we recorded a$0.3 million gross profit margin related to the FPP Capital Lease Transaction for the year ended December 31, 2016. Revenue and interest income related to both capital leases is recognized over the respective lease terms. We recognizemaintenance revenue within Contract operations revenue and interest income within Interest expense, net on theConsolidated Statements of Operations. For each of the years ended December 31, 2017, 2016 and 2015, maintenancerevenue related to the BPO Capital Lease Transaction was $1.3 million. There is no maintenance revenue component to theFPP Capital Lease Transaction. Interest income related to both capital leases was $1.6 million, $1.5 million and $1.6 millionfor the years ended December 31, 2017, 2016 and 2015, respectively. (5) Accrued Liabilities Accrued liabilities include unit-based compensation liability, accrued payroll and benefits and accrued property taxes.We recognized $8.9 million and $7.0 million of unit-based compensation liability as of December 31, 2017 and 2016,respectively. We recognized $6.4 million and $6.9 million of accrued payroll and benefits as of December 31, 2017 and2016, respectively. We recognized $2.3 million and $6.6 million of accrued property taxes as of December 31, 2017 and2016, respectively. (6) Income Tax Expense We are subject to the Revised Texas Franchise Tax (“Texas Margin Tax”). We do not conduct business in any other statewhere a similar tax is applied. This margin tax requires certain forms of legal entities, including limited partnerships, to pay atax of 0.75% on its “margin,” as defined in the law, based on annual results. The margin tax base to which the tax rate isapplied is the least of (1) 70% of total revenues for federal income tax purposes, (2) total revenue less cost of goods sold or(3) total revenue less compensation for federal income tax purposes. For the years ended December 31, 2017, 2016 and 2015,we recorded expense related to the Texas margin tax of $0.5 million, $0.4 million and $1.1 million, respectively. F-12 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statements Components of our income tax expense related to the Texas Margin Tax are as follows (in thousands): Year Ended December 31, 2017 2016 2015Current tax expense $260 $182 $211Deferred tax expense 278 239 874Total income tax expense $538 $421 $1,085 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 are as follows (in thousands): December 31, 2017 2016Net deferred tax liabilities $1,391 $1,113 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, 2017, 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 taxes (including anyapplicable penalties and interest) directly to the Internal Revenue Service or, if we are eligible, issue a revised informationstatement to each unitholder and former unitholder with respect to an audited and adjusted return. The Bipartisan Budget Actof 2015 allows a partnership to elect to apply these provisions to any return of the partnership filed for partnership taxableyears beginning after the date of the enactment, November 2, 2015. We do not intend to elect to apply these provisions forany tax return filed for partnership taxable years beginning before January 1, 2018. (7) Long-Term Debt Our first lien long-term debt consisted of the following (in thousands): December 31, 2017 2016Revolving Credit Facility $782,902 $685,371 Our revolving credit facility has an aggregate commitment of $1.1 billion (subject to availability under our borrowingbase), with a further potential increase of $200 million and has a maturity date of January 6, 2020. The revolving credit facility permits us to make distributions of available cash to unitholders so long as (a) no defaultunder the facility has occurred, is continuing or would result from the distribution, (b) immediately prior to and after givingeffect to such distribution, we are in compliance with the facility’s financial covenants and (c) immediately after giving effectto such distribution, we have availability under the revolving credit facility of at least $20 million. In addition, the revolvingcredit facility contains various covenants that may limit, among other things, our ability to (subject to exceptions): ·grant liens; F-13 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statements ·make certain loans or investments; ·incur additional indebtedness or guarantee other indebtedness; ·enter into transactions with affiliates; ·merge or consolidate; ·sell our assets; or ·make certain acquisitions. The 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) 5.25 to 1.0 as of the end of the fiscal quarter ending December 31, 2017 and (b) 5.00 to1.0 thereafter, in each case subject to a provision for increases to such thresholds by 0.5 in connection with certainfuture acquisitions for the six consecutive month period following the period in which any such acquisition occurs. If a default exists under the revolving credit facility, the lenders will be able to accelerate the maturity on the amountthen outstanding and exercise other rights and remedies. We paid various loan fees and incurred costs in respect of the revolving credit facility in the amount of $2.0 million and$3.4 million in 2016 and 2015, respectively, which were capitalized to loan costs that will be amortized through January2020. We did not incur or pay any of these various loan fees during 2017. As of December 31, 2017 and 2016, we were in compliance with all of our covenants under the revolving credit facility. As of December 31, 2017, we had outstanding borrowings under our revolving credit facility of $782.9 million, $272.1million of borrowing base availability and, subject to compliance with the applicable financial covenants, availableborrowing capacity of $101.6 million. The borrowing base consists of eligible accounts receivable, inventory andcompression units. The largest component, representing 95% and 94% of the borrowing base as of December 31, 2017 and2016, respectively, was eligible compression units. Eligible compression units consist of compressor packages that areleased, rented or under service contracts to customers and carried in the financial statements as fixed assets. Our interest ratein effect for all borrowings under our revolving credit facility as of December 31, 2017 and 2016 was 3.46% and 2.94%,respectively, with a weighted-average interest rate of 3.14%, 2.55%, and 2.24% during 2017, 2016 and 2015, respectively.There were no letters of credit issued as of December 31, 2017 and 2016. The revolving credit facility matures in January 2020 and we expect to maintain this facility for the term. The facility isa “revolving credit facility” that includes a “springing” lock box arrangement, whereby remittances from customers areforwarded to a bank account controlled by us. We are not required to use such remittances to reduce borrowings under thefacility, unless there is a default or excess availability under the facility is reduced below $20 million. As the remittances donot automatically reduce the debt outstanding absent the occurrence of a default or a reduction in excess availability below$20 million, the debt has been classified as long-term as of December 31, 2017 and 2016. F-14 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statements Maturities of long-term debt are as follows (in thousands): Year Ending December 31, 2018 $ — 2019 — 2020 782,902 2021 — 2022 — Total Debt $782,902 In the event that any of our operating subsidiaries guarantees any series of the debt securities as described in ourregistration statements filed on Form S-3, such guarantees will be full and unconditional and made on a joint and severalbasis for the benefit of each holder and the Trustee. However, such guarantees will be subject to release, subject to certainlimitations, as follows (i) upon the sale, exchange or transfer, whether by way of a merger or otherwise, to any Person that isnot our affiliate, of all our direct or indirect limited partnership or other equity interest in such Subsidiary Guarantor; or(ii) upon our or USA Compression Finance Corp.’s (together, the “Issuers”) delivery of a written notice to the Trustee of therelease or discharge of all guarantees by such Subsidiary Guarantor of any Debt of the Issuers other than obligations arisingunder the indenture governing such debt and any debt securities issued under such indenture, except a discharge or releaseby or as a result of payment under such guarantees. Capitalized terms used but not defined in this paragraph are defined inthe Form of Indenture filed as exhibit 4.1 to such registration statements. (8) Partner’s Capital As of February 8, 2018, USA Compression Holdings, LLC (“USA Compression Holdings”) held 25,092,196 commonunits and owned and controlled our General Partner which held an approximate 1.2% general partner interest (the “GeneralPartner’s Interest”) and the incentive distribution rights (“IDRs”). See the Consolidated Statement of Changes in Partners’Capital. The limited partners holding our common units have the following rights, among others: ·Right to receive distributions of our available cash (as defined in the Partnership Agreement) within 45 days afterthe end of each quarter; ·Right to transfer limited partner unit ownership to substitute limited partners; ·Right to approve certain amendments of our 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. Subordinated Units All of our outstanding subordinated units, which were held by USA Compression Holdings, converted to common unitson a one-for-one basis on February 16, 2016 upon payment of our quarterly distribution on February 12, 2016. Incentive Distribution Rights Our General Partner holds all of the IDRs. The IDRs represent the right to receive an increasing percentage of quarterlydistributions of available cash from operating surplus after the minimum quarterly distribution and the target distributionlevels have been achieved.F-15 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statements The following table illustrates the percentage allocations of Available Cash from Operating Surplus between ourunitholders and our General Partner based on the specified target distribution levels. The amounts set forth under “MarginalPercentage Interest in Distributions” are the percentage interests of our General Partner and our unitholders in any AvailableCash from Operating Surplus we distribute up to and including the corresponding amount in the column “Total QuarterlyDistribution per Unit.” The percentage interests shown for our unitholders and our General Partner for the minimum quarterlydistribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. Thepercentage interests set forth below for our General Partner include its General Partner’s Interest, and assume our GeneralPartner has contributed any additional capital necessary to maintain its General Partner’s Interest, our General Partner has nottransferred the IDRs and there are no arrearages on common units. Marginal Percentage Interest in Total Quarterly Distributions Distributions per Unit Unitholders General Partner Minimum Quarterly Distribution $0.425 98.8% 1.2%First Target Distribution up to $0.4888 98.8% 1.2%Second Target Distribution above $0.4888 up to $0.5313 85.8% 14.2%Third Target Distribution above $0.5313 up to $0.6375 75.8% 24.2%Thereafter above $0.6375 50.8% 49.2% Cash Distributions We have declared quarterly distributions per unit to our limited partner unitholders of record, including holders of ourcommon, subordinated and phantom units and distributions paid to our General Partner, including our General Partner’sInterest and IDRs, as follows (dollars in millions, except distribution per unit): Distribution per Amount Paid to Amount Paid to Amount Paid to Amount Paid to Limited Partner Common Subordinated General Phantom Total Payment Date Unit Unitholders Unitholder Partner Unitholders Distribution February 13, 2015 $0.510 $16.0 $7.2 $0.5 $0.1 $23.8 May 15, 2015 0.515 16.6 7.2 0.6 0.2 24.6 August 14, 2015 0.525 17.2 7.4 0.7 0.2 25.5 November 13, 2015 0.525 19.7 7.4 0.7 0.2 28.0 2015 Total Distributions $2.075 $69.5 $29.2 $2.5 $0.7 $101.9 February 12, 2016 $0.525 $20.2 $7.4 $0.7 $0.8 $29.1 May 13, 2016 0.525 28.4 — 0.7 0.7 29.8 August 12, 2016 0.525 28.8 — 0.7 0.7 30.2 November 14, 2016 0.525 29.1 — 0.7 0.6 30.4 2016 Total Distributions $2.100 $106.5 $7.4 $2.8 $2.8 $119.5 February 14, 2017 $0.525 $31.9 $ — $0.7 $0.8 $33.4 May 12, 2017 0.525 32.1 — 0.7 0.6 33.4 August 11, 2017 0.525 32.3 — 0.8 0.6 33.7 November 10, 2017 0.525 32.6 — 0.8 0.5 33.9 2017 Total Distributions $2.100 $128.9 $ — $3.0 $2.5 $134.4 Announced Quarterly Distribution On January 18, 2018, we announced a cash distribution of $0.525 per unit on our common units. The distribution will bepaid on February 14, 2018 to unitholders of record as of the close of business on February 2, 2018. F-16 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statements Distribution Reinvestment Plan For the years ended December 31, 2017, 2016 and 2015, distributions of $20.3 million, $31.8 million and $56.9 million,respectively, were reinvested under the Distribution Reinvestment Plan (the “DRIP”) resulting in the issuance of 1.2 million,2.7 million and 3.1 million common units, respectively. Such distributions are treated as non-cash transactions in theaccompanying Consolidated Statements of Cash Flows. Equity Offerings On December 8, 2016, we closed a public offering of 5,175,000 common units at a price to the public of $16.25 percommon unit. We used the net proceeds of $80.9 million (net of underwriting discounts and commissions and offeringexpenses) to reduce the indebtedness outstanding under our revolving credit facility. On September 15, 2015, we closed a public offering of 4,000,000 common units at a price to the public of $19.33 percommon unit. We used the net proceeds of $74.4 million (net of underwriting discounts and commissions and offeringexpenses) to reduce the indebtedness outstanding under our revolving credit facility. On May 21, 2015, we issued 34,921 common units in a private placement for $0.7 million in a transaction that wasexempt from registration under Section 4(a)(2) of the Securities Act. We used the proceeds from the private placement forgeneral partnership purposes. There were no other unregistered sales of securities during the years ended December 31, 2017,2016 or 2015. Earnings Per Common and Subordinated Unit The computations of earnings per common unit and subordinated unit are based on the weighted average number ofcommon units and subordinated units, respectively, outstanding during the applicable period. The subordinated units andour General Partner’s Interest (including its IDRs) meet the definition of participating securities as defined by the FASB’sASC Topic 260 Earnings Per Share; therefore, we apply the two-class method of income allocation in computing earningsper unit. Basic earnings per common and subordinated unit are determined by dividing net income (loss) allocated to thecommon and subordinated units, respectively, after deducting the net income (loss) amount allocated to our General Partner(including distributions to our General Partner on our General Partner’s Interest and its IDRs), by the weighted averagenumber of outstanding common and subordinated units, respectively, during the period. Net income (loss) is allocated to thecommon units, subordinated units and our General Partner’s Interest (including its IDRs) based on their respective shares ofthe distributed and undistributed earnings for the period. To the extent cash distributions exceed net income (loss) for theperiod, the excess distributions are allocated to all participating interests outstanding based on their respective ownershippercentages. Diluted earnings per unit are computed using the treasury stock method, which considers the potential issuanceof limited partner units associated with our LTIP. Unvested phantom units are not included in basic earnings per unit, as theyare liability classified and as such are not considered to be participating securities, but are included in the calculation ofdiluted earnings per unit. Incremental unvested phantom units outstanding represent the only difference between our basicand diluted weighted average common units outstanding during the years ended December 31, 2017, 2016 and 2015. For theyear ended December 31, 2015, approximately 121,000 incremental phantom units were excluded from the calculation ofdiluted units because the impact was anti-dilutive. (9) Unit-Based Compensation Class B Units During 2011 and 2013, USA Compression Holdings issued to certain employees and members of its management, whoprovide services to us, Class B non-voting units. These Class B units are liability-classified profits interest awards whichhave a service condition. The holders of Class B units in USA Compression Holdings are entitled to a cash payment of 10% of net proceedsprimarily from a monetization event, as defined under the provisions of the Amended and Restated Limited LiabilityF-17 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statements Company Agreement of USA Compression Holdings, or the Holdings Operating Agreement, related to these Class B unitawards, in excess of USA Compression Holdings’ Class A unitholder’s capital contributions and a return on each Class Aunitholder’s capital account, compounded annually (both of which are due upon a monetization event), to the extent ofvested units over total units of the respective class. Each holder of Class B units is then allocated their pro-rata share of therespective class of unit’s entitlement based on the number of units held over the total number of units in that class of units.The Class B units vest 25% on the first anniversary date of the grant date and then monthly for the next three years (at therate of 1/36 per month) subject to certain continued employment. The units have no expiry date provided the employeeremains employed with USA Compression Holdings or one of its subsidiaries. The Class B units vesting schedule consisted of the following as of December 31: Class B Interest Units Vested UnvestedBalance of awards as of December 31, 2014 1,125,000 125,000Vesting 54,687 (54,687)Forfeitures (125,000) —Balance of awards as of December 31, 2015 1,054,687 70,313Vesting 46,875 (46,875)Balance of awards as of December 31, 2016 1,101,562 23,438Vesting 23,438 (23,438)Balance of awards as of December 31, 2017 1,125,000 — Fair value of the Class B units is based on enterprise value calculated by a predetermined formula. We recognized nounit-based compensation expense related to these Class B units during any of the periods presented above. Long-Term Incentive Plan In connection with our initial public offering, the board of directors of our General Partner (the “Board”) adopted theLTIP for employees, consultants and directors of our General Partner and any of its affiliates who perform services for us. TheLTIP consists of unit options, unit appreciation rights, restricted units, phantom units, distribution equivalent rights(“DERs”), unit awards, profits interest units and other unit-based awards. The LTIP initially limits the number of commonunits that may be delivered pursuant to awards under the plan to 1,410,000 common units. Awards that are forfeited,cancelled, paid or otherwise terminate or expire without the actual delivery of units will be available for delivery pursuant toother awards. The LTIP is administered by the Board or a committee thereof. In February 2014, the Board approved a modification to all of the phantom unit awards that were granted to employeespursuant to the LTIP during the 2013 fiscal year. The modification provided all employees with phantom unit awards grantedduring 2013 with an option of settling a portion of their award in cash and a portion in units. The amount that can be settledin cash is in excess of the employee’s minimum statutory tax-withholding rate. ASC Topic 718 Compensation-StockCompensation, requires the entire amount of an award with such features to be accounted for as a liability. Under the liabilitymethod of accounting for unit-based compensation, we re-measure the fair value of the award at each financial statement dateuntil the award vests or is cancelled. The fair value is re-measured at the end of each reporting period using the market priceof the common units. During the requisite service period (the vesting period of the awards), compensation cost is recognizedusing the proportionate amount of the award’s fair value that has been earned through service to date. During the years ended December 31, 2017 and 2016, an aggregate of 382,231 and 1,084,003, respectively, phantomunits (including the corresponding DERs) were granted under the LTIP to our General Partner’s executive officers andemployees and independent directors. The phantom units granted in 2017 and 2016 provide the employees with an option ofsettling a portion of their award in cash and a portion in units. The phantom units (including the corresponding DERs)awarded are subject to restrictions on transferability, customary forfeiture provisions and time vesting provisions generally. F-18 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statements The phantom units granted to employees during 2017 and 2016 are subject to time-based and market-based criteria. Werefer to the component of the grants subject to the time-based criteria as “Standard Units” and we refer to the component ofthe grants subject to the market-based criteria as “Performance Units”. Standard Units vest over a three year service period,consistent with historical phantom units granted. Performance Units vest at the end of a three year service period, subject to amarket condition. The market condition metric is our total shareholder return over the three year service period, relative tothe total shareholder returns of a defined peer group of companies over the same three year period. Our ranking determinesthe rate at which the Performance Units convert into our common shares, which can range from zero to 200 percent of thePerformance Unit grant. The phantom units will generally vest in full in the event of a change in control and a termination of employment.Grants of phantom units to the independent directors of our General Partner generally vest in full on the one year anniversaryof the grant date. Award recipients do not have all the rights of a unitholder in the Partnership with respect to the phantomunits until the units have vested. Phantom units granted to employees during the years ended December 31, 2017 and 2016 are accounted for as a liabilityand are re-measured to fair value at the end of each reporting period using the market price of the common units for StandardUnits. Fair value for the Performance Units was determined using a Monte Carlo simulation model, which incorporated anumber of factors in its valuation including the vesting periods of our awards, the expected volatility of our units, expecteddividends and the risk free interest rate. As of December 31, 2017 and 2016, our total unit-based compensation liability was$8.9 million and $7.0 million, respectively. Phantom units granted to independent directors do not have a cash settlementoption and as such we account for these awards as equity. During the requisite service period, compensation cost isrecognized using the proportionate amount of the award’s fair value that has been earned through service to date. Our General Partner’s executive officers, employees and independent directors were granted these awards to incentivizethem to help drive our future success and to share in the economic benefits of that success. The compensation costsassociated with these awards were recorded in selling, general and administrative expense. During the years ended December31, 2017, 2016 and 2015, we recognized $11.7 million, $10.4 million and $3.9 million, respectively, of compensationexpense associated with these awards. During the years ended December 31, 2017, 2016 and 2015, amounts we paid relatedto the cash settlement of vested awards under the LTIP were $2.8 million, $0.1 million and $0.2 million, respectively. Thetotal fair value and intrinsic value of the phantom units vested under the LTIP was $7.8 million, $1.9 million and $2.2million during the years ended December 31, 2017, 2016 and 2015, respectively. F-19 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statements The following table summarizes information regarding phantom unit awards for the periods presented: Weighted-Average Grant Date Fair Number of Units Value per Unit (1) Phantom units outstanding at December 31, 2014 269,102 $23.65 Granted 320,636 19.04 Vested 111,991 22.96 Forfeited 20,666 21.77 Phantom units outstanding at December 31, 2015 457,081 $22.10 Granted 1,084,003 7.27 Vested 212,896 21.25 Forfeited 158,275 9.83 Phantom units outstanding at December 31, 2016 1,169,913 $9.81 Granted 382,231 19.05 Vested 429,539 11.09 Forfeited 35,747 8.73 Phantom units outstanding at December 31, 2017 1,086,858 $12.40 (1)Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. The unrecognized compensation cost associated with phantom unit awards was an aggregate $10.6 million as ofDecember 31, 2017. We expect to recognize the unrecognized compensation cost for these awards on a weighted-averagebasis over a period of 1.4 years. Each phantom unit granted to an independent director is granted in tandem with a corresponding DER, which remainsoutstanding and unpaid from the grant date until the earlier of the payment or forfeiture of the related phantom units. Eachvested DER shall entitle the participant to receive payments in the amount equal to any distributions we make following thegrant date in respect of the common unit underlying the phantom unit to which such DER relates. Accumulated but unpaidDERs are never paid if the underlying phantom unit award is forfeited by the independent director. Each phantom unit granted to an executive officer or an employee is granted in tandem with a corresponding DER,which is paid quarterly on the distribution date from the grant date until the earlier of the settlement or the forfeiture of therelated phantom units. For the Performance Units granted during 2016 and 2017, DERs are paid on 100% of the granted unitsregardless of whether the ultimate number of units that vest fall within the range from zero to 200%. (10) Employee Benefit Plans A 401(k) plan is available to all of our employees. The plan permits employees to make contributions up to 20% of theirsalary, up to statutory limits, which was $18,000 in 2017. The plan provides for discretionary matching contributions by uson an annual basis. Aggregate matching contributions made by us were $0.8 million for each of the years ended December31, 2017, 2016 and 2015, respectively. (11) Transactions with Related Parties John Chandler, who served as a director of our General Partner from October 2013 to October 2017, has served as adirector of one of our customers since October 2014. During the period of Mr. Chandler’s appointment as a director of ourGeneral Partner during the year ended December 31, 2017, and for the years ended December 31, 2016 and 2015, werecognized $5.7 million, $8.5 million and $8.8 million, respectively, in revenue on compression services and $1.1 million inaccounts receivable from this customer on the Consolidated Balance Sheets as of both December 31, 2017 and 2016.F-20 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statements Jerry Peters, who has served as a director of our General Partner since October 2017, has served as a director of one of ourcustomers since September 2012. During the period of Mr. Peters’ appointment as a director of our General Partner during theyear ended December 31, 2017, we recognized $0.3 million in revenue on compression services and $0 in accountsreceivable from this customer on the Consolidated Balance Sheets as of December 31, 2017. We provide compression services to entities affiliated with Riverstone/Carlyle Global Energy and Power Fund IV, L.P.(“Riverstone”), which owns a majority of the membership interests in USA Compression Holdings. As of December 31, 2017,USA Compression Holdings owned and controlled our General Partner and owned approximately 40% of our limited partnerinterests. We recognized $0.7 million and $0.4 million in revenue from compression services from such affiliated entities forthe years ended December 31, 2017 and 2016, respectively. We may provide compression services to additional entitiesaffiliated with Riverstone in the future, and any significant transactions will be disclosed. (12) Recent Accounting Pronouncements In May 2014, the FASB issued Accounting Standards Update (“ASU”) 2014-09 ASC Topic 606 Revenue from Contractswith Customers (“ASC Topic 606”). ASC Topic 606 supersedes the revenue recognition requirements in ASC Topic 605Revenue Recognition, and requires an entity to recognize revenue when it transfers promised goods or services to customersin an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.ASC Topic 606 also requires disclosures enabling users of financial statements to understand the nature, amount, timing anduncertainty of revenue and cash flows arising from contracts with customers. As currently issued and amended, this ASCTopic 606 is effective for annual and interim reporting periods beginning after December 15, 2017. We will elect the modified retrospective transition method for adoption to annual and interim periods beginning January1, 2018 on contracts which are not completed on the transition date. Upon adoption, we will recognize the cumulative effectof adoption as an adjustment to the opening balance of our partners’ capital. Our performance obligations within our contract operations revenue stream represent promises to perform a series ofdistinct services that are satisfied over time and that are substantially the same to the customer. In our compression serviceagreements, services are performed over time and, accordingly, we expect to recognize revenue based upon a time elapsedmeasure of progress. Our performance obligations within our parts and service revenue stream are to deliver a part or serviceat a point in time and control is transferred at the point in time that our customers have the ability to use the part or access thebenefits provided by the service. ASC Topic 606 provides guidance on contract costs that should be recognized as assets and amortized over the periodthat the related goods or services transfer to the customer. Certain costs such as freight charges to transport compressionequipment, currently expensed as incurred, will be deferred and amortized. Our implementation approach included performing a review of contracts comprising our revenue streams and comparinghistorical accounting policies and practices to the new standard. At this time we do not expect the adoption of ASC Topic606 to result in a material difference in timing or measurement of revenue recognition from our current practice. The impacts noted are not all-inclusive, but reflect our current expectations. We anticipate significant changes to ourdisclosures based on the requirements prescribed by ASC Topic 606. We are finalizing changes to our internal controlstructure to address risks associated with recognizing revenue under ASC Topic 606. We will continue to evaluate ourbusiness processes, systems and controls to ensure the accuracy and timeliness of the recognition and disclosure requirementsunder ASC Topic 606. In February 2016, the FASB issued ASU 2016-02 ASC Topic 842 Leases (“ASC Topic 842”). ASC Topic 842 is a newleasing standard that increases transparency and comparability among organizations by, among other things, requiringlessees to recognize most lease assets and lease liabilities on the balance sheet and requiring both lessees andF-21 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statements lessors to disclose expanded qualitative and quantitative information about leasing arrangements. This new leasing standardrequires modified retrospective adoption for all leases existing at, or entered into after, the date of the initial application, withan option to use certain elective transition reliefs. ASC Topic 842 becomes effective for public business entities for annualand interim periods in fiscal years beginning after December 15, 2018. Early adoption of this standard is permitted. Weexpect to adopt this new standard on January 1, 2019. We are in the preliminary stages of the assessment phase and are in theprocess of identifying potential contracts and transactions subject to the provisions of the standard so that we may assess thefinancial impact of adopting this standard on our consolidated financial statements and related disclosures. Further, we are inthe preliminary stages of assessing the changes in controls, processes and accounting policies that are necessary toimplement this standard. (13) Commitments and Contingencies (a)Operating Leases Rent expense for office space, warehouse facilities and certain corporate equipment for the years ended December 31,2017, 2016 and 2015 was $3.0 million, $3.0 million and $2.9 million, respectively. Commitments for future minimum leasepayments for non-cancelable leases are as follows (in thousands): 2018 $1,517 2019 1,196 2020 161 2021 72 2022 — Thereafter — Total $2,946 (b)Major Customers We did not have revenue from any single customer representing 10% or more of total revenue for the years endedDecember 31, 2017, 2016 or 2015. (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, 2017 were $122.2 million, of which $119.7 million areexpected to be settled 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. Certain taxingauthorities have claimed that specific operational processes, which we and others in our industry regularly conduct, result intransactions that are subject to state sales taxes. We, and other entities in our industry, have disputed these claims based onexisting tax statutes which provide for manufacturing exemptions on the transactions in question. We continue to work withthe state taxing authority in providing them the documentation available to us to support the position we have taken withregard to the disputed transactions. We have recognized a liability of $0.1 million related to this issue; however, we believeit is reasonably possible that we could incur additional losses for this matter depending on whether the taxing authorityaccepts our documentation as sufficient to support our position that the disputed transactions are not taxable and the impactof any potential resulting litigation. Management estimates that the range ofF-22 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statements losses we could incur related to this matter is from $0.1 million to approximately $3.5 million. The upper end of this rangeassumes that we will be unable to apply the manufacturing exemption to any of the transactions in question, whichmanagement believes is extremely remote. (14) Subsequent Events Acquisition of Compression Business from Energy Transfer Partners On January 15, 2018, we entered into a Contribution Agreement (the “Contribution Agreement”) with Energy TransferPartners, L.P. (“ETP”), Energy Transfer Partners GP, L.P., the general partner of ETP (“ETP GP”), ETC Compression, LLC(“ETC” and, together with ETP and ETP GP, the “Contributors”) and, solely for certain purposes therein, Energy TransferEquity, L.P. (“ETE”), pursuant to which, among other things, ETP will contribute to us, and we will acquire from ETP, all ofthe issued and outstanding membership interests of CDM Resource Management LLC (“CDM Management”) and CDMEnvironmental & Technical Services LLC (“CDM E&T” and, together with CDM Management, “CDM”) for aggregateconsideration of approximately $1.7 billion consisting of units representing limited partner interests in the Partnership andan amount in cash equal to $1.225 billion, subject to certain adjustments (the “CDM Acquisition”). The CDM Acquisition is expected to close in the first half of 2018, subject to customary closing conditions, including(i) the concurrent closing of the GP Purchase (as defined below), and (ii) the transactions contemplated by the EquityRestructuring Agreement (as defined below), including the Restructuring (as defined below), shall be able to beconsummated immediately following the Closing (as defined below), and as otherwise described in the ContributionAgreement (the “Closing”). On January 15, 2018, and in connection with the execution of the Contribution Agreement, ETE entered into a PurchaseAgreement (the “GP Purchase Agreement”) with Energy Transfer Partners, L.L.C. (together with ETE, the “GP Purchasers”),USA Compression Holdings, and, solely for certain purposes therein, R/C IV USACP Holdings, L.P. and ETP, pursuant towhich the GP Purchasers will acquire from USA Compression Holdings (i) all of the outstanding limited liability companyinterests in our General Partner, and (ii) 12,466,912 common units (the “GP Purchase”). On January 15, 2018, and in connection with the execution of the Contribution Agreement, we entered into an EquityRestructuring Agreement (the “Equity Restructuring Agreement”) with our General Partner and ETE, pursuant to which,among other things, we, our General Partner and ETE have agreed to cancel our IDRs (the “Cancellation”) and convert ourGeneral Partner Interest (as defined in the Equity Restructuring Agreement) into a non-economic general partner interest (the“Conversion” and, together with the Cancellation, the “Restructuring”), in exchange for our issuance of 8,000,000 commonunits to our General Partner, effective at the Closing. On January 15, 2018, we entered into a Series A Preferred Unit and Warrant Purchase Agreement (the “Series A PurchaseAgreement”) with certain investment funds managed or sub-advised by EIG Global Energy Partners (“EIG”) and otherinvestment vehicles unaffiliated with EIG (collectively, the “Purchasers”) to issue and sell in a private placement (the“Private Placement”) $500 million in the aggregate of (i) newly authorized and established Series A Perpetual Preferred Unitsrepresenting limited partner interests in the Partnership (the “Preferred Units”) and (ii) warrants to purchase common units(the “Warrants”). We will issue 500,000 Preferred Units to the Purchasers at a price of $1,000 per Preferred Unit (the“Preferred Unit Purchase Price”), less a 1.0% structuring and origination fee, for total net proceeds, before expenses, of $495million. In addition, we will pay a 1.0% commitment fee to the Purchasers at the closing, as well as reimburse the Purchasersfor up to $400,000 of certain expenses incurred in connection with the transaction. We will also issue two tranches ofWarrants to the Purchasers, which will include Warrants to purchase 5,000,000 common units with a strike price of $17.03per unit and Warrants to purchase 10,000,000 common units with a strike price of $19.59 per unit. The Warrants may beexercised by the holders thereof at any time beginning on the one year anniversary of the closing date and before the tenthanniversary of the closing date. Upon exercise of the Warrants, we may, at our option, elect to settle the Warrants in commonunits on a net basis. The Series A Purchase Agreement contains customary representations, warranties and covenants of thePartnership and the Purchasers. The closing of the Private Placement is subject to customary closing conditions. F-23 Table of ContentsUSA COMPRESSION PARTNERS, LPNotes to Consolidated Financial Statements In connection with the CDM Acquisition, on January 15, 2018, we entered into a commitment letter (the “BridgeCommitment”) with JPMorgan Chase Bank, N.A. and Barclays Bank PLC, as modified by the joinder to commitment letterand bridge fee letter entered into by the Partnership, JPMorgan Chase Bank, N.A. and Barclays Bank PLC with eachof Regions Bank, Royal Bank of Canada, Wells Fargo Bank, N.A., MUFG Union Bank, N.A., a member of MUFG, a globalfinancial group, The Bank of Nova Scotia and SunTrust Bank and certain affiliates of such parties (the “CommitmentLetter”). The Commitment Letter provides for senior unsecured bridge loans in an aggregate amount up to $725 million (the“Bridge Loans”). The proceeds of such Bridge Loans may be used (a) to finance a portion of the purchase price of the CDMAcquisition and (b) to pay fees and expenses incurred in connection therewith. The availability of the borrowings is subjectto the satisfaction of certain customary conditions. The Bridge Commitment will expire upon the earliest to occur of (1) theOutside Date as defined in the Contribution Agreement (as the same may be extended thereunder), (2) the consummation ofthe CDM Acquisition without use of the Bridge Loans, (3) the termination of the Contribution Agreement in accordance withits terms, or (4) September 30, 2018. The Bridge Loans are available to backstop a portion of the CDM Acquisition purchaseprice that we expect to fund with the net proceeds of other debt financing. Revolving Credit Facility On January 29, 2018, we amended our revolving credit facility to, among other things, (i) permit us to consummate theCDM Acquisition as described above, (ii) incur up to $800 million in aggregate amount of indebtedness with respect to theBridge Loans described above or other long-term indebtedness, (iii) increase from $20 million to $100 million the minimumavailability under the revolving credit facility as a condition to making distributions of available cash to unitholders, and(iv) amend certain other provisions of the revolving credit facility, all as more fully set forth in the amendment documents. F-24 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, 2017 2017 2017 2017 Revenue $66,032 $66,014 $72,791 $75,385 Gross profit (1) $43,510 $44,431 $49,350 $50,340 Net income $1,552 $553 $4,789 $4,546 Net income per common unit - basic and diluted $0.02 $0.003 $0.07 $0.07 March 31, June 30, September30, December 31, 2016 2016 2016 2016 Revenue $66,367 $63,511 $61,130 $74,913 Gross profit $45,538 $44,857 $42,245 $45,120 Net income (loss) $8,538 $3,274 $(2,146) $3,269 Net income (loss) per common unit - basic and diluted $0.24 $0.05 $(0.04) $0.05 Net loss per subordinated unit - basic and diluted $(0.38) $ — $ — $ — (1)Gross profit is defined as revenue less cost of operations, exclusive of depreciation and amortization expense. S-1(1)Exhibit 21.1 List of Subsidiaries USA Compression Finance Corp., a Delaware corporation USA Compression Partners, LLC, a Delaware limited liability company USAC Leasing, LLC, a Delaware limited liability company USAC OpCo 2, LLC, a Texas limited liability company USAC Leasing 2, LLC, a Texas limited liability company Exhibit 23.1 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM The PartnersUSA Compression Partners, LP: We consent to the incorporation by reference in the registration statements on Form S-3 (No. 333-217391 and 333-211167)and Form S-8 (No. 333-187166) of USA Compression Partners, LP of our report dated February 12, 2018, with respect to theconsolidated balance sheets of USA Compression Partners, LP as of December 31, 2017 and 2016, and the relatedconsolidated statements of operations, changes in partners’ capital, and cash flows for each of the years in the three-yearperiod ended December 31, 2017, and the related notes (collectively, the “consolidated financial statements”), which reportappears in the December 31, 2017 annual report on Form 10-K of USA Compression Partners, LP. /s/ KPMG LLP Dallas, TexasFebruary 12, 2018 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 12, 2018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 12, 2018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, 2017 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 12, 2018 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, 2017 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 12, 2018 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. 

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