10-K 1 usac-20181231x10k.htm 10-K

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2018

or

☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 001-35779

USA Compression Partners, LP

(Exact Name of Registrant as Specified in its Charter)

Delaware |  | 75-2771546
(State or Other Jurisdiction of Incorporation or Organization) |  | (I.R.S. Employer Identification No.)

100 Congress Avenue, Suite 450 Austin, 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 registered
Common 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 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 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 of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment 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 emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” or an “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☒ |  | Accelerated filer ☐
Non-accelerated filer ☐ |  | Smaller reporting company ☐
Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

The aggregate market value of common units held by non-affiliates of the registrant as of June 29, 2018, the last business day of the registrant’s most recently completed second fiscal quarter was $831,898,973. This calculation does not reflect a determination that such persons are affiliates for any other purpose.

As of February 14, 2019, there were 90,000,504 common units and 6,397,965 Class B Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: NONE

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PART I | 1
| Item 1. | Business | 1
| Item 1A. | Risk Factors | 16
| Item 1B. | Unresolved Staff Comments | 39
| Item 2. | Properties | 39
| Item 3. | Legal Proceedings | 39
| Item 4. | Mine Safety Disclosures | 39
PART II | 40
| Item 5. | Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 40
| Item 6. | Selected Financial Data | 41
| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 47
| Item 7A. | Quantitative and Qualitative Disclosures About Market Risk | 64
| Item 8. | Financial Statements and Supplementary Data | 64
| Item 9. | Changes in and Disagreements With Accountants on Accounting and Financial Disclosure | 64
| Item 9A. | Controls and Procedures | 64
| Item 9B. | Other Information | 67
PART III | 68
| Item 10. | Directors, Executive Officers and Corporate Governance | 68
| Item 11. | Executive Compensation | 75
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters | 100
| Item 13. | Certain Relationships and Related Transactions, and Director Independence | 103
| Item 14. | Principal Accountant Fees and Services | 105
PART IV | 107
| Item 15. | Exhibits and Financial Statement Schedules | 107

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PART I

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

This report contains “forward-looking statements.” All statements other than statements of historical fact contained in this report are forward-looking statements, including, without limitation, statements regarding our plans, strategies, prospects and expectations concerning our business, results of operations and financial condition. You can identify many of these statements by looking for words such as “believe,” “expect,” “intend,” “project,” “anticipate,” “estimate,” “continue,” “if,” “outlook,” “will,” “could,” “should,” or similar words or the negatives thereof.

Known material factors that could cause our actual results to differ from those in these forward-looking statements are described below, in Part I, Item 1A (“Risk Factors”) and in Part II, Item 7 (“Management’s Discussion and Analysis of Financial Condition and Results of Operations”). Important factors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things:

| · |  | changes in general economic conditions and changes in economic conditions of the crude oil and natural gas industries 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 existing fleet, including the CDM Acquisition (as defined below);

| · |  | actions taken by our customers, competitors and third-party operators;

| · |  | the deterioration of the financial condition of our customers;

| · |  | changes in the availability and cost of capital;

| · |  | operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

| · |  | the effects of existing and future laws and governmental regulations; and

| · |  | the effects of future litigation.

All forward-looking statements included in this report are based on information available to us on the date of this report and speak only as of the date of this report. Except as required by law, we undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the foregoing cautionary statements.

ITEM 1.Business

Following the transactions described in further detail below, CDM Resource Management LLC and CDM Environmental & Technical Services LLC, which together represent the CDM Compression Business (the “USA Compression Predecessor”), has been determined to be the historical predecessor of USA Compression Partners, LP (the “Partnership”) for financial reporting purposes. The USA Compression Predecessor is considered the predecessor of the Partnership because Energy Transfer Equity, L.P. (“ETE”), through its wholly owned subsidiary Energy Transfer Partners, L.L.C., controlled the USA Compression Predecessor prior to the transactions described below and obtained control of the Partnership through its acquisition of USA Compression GP, LLC, the general partner of the Partnership (the “General Partner”).

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The closing of the Transactions occurred on April 2, 2018 (the “Transactions Date”) and has been reflected in the consolidated financial statements of the Partnership.

In October 2018, ETE and Energy Transfer Partners, L.P. (“ETP”) completed the merger of ETP with a wholly owned subsidiary of ETE in a unit-for-unit exchange (the “ETE Merger”). Following the closing of the ETE Merger, ETE changed its name to “Energy Transfer LP” and ETP changed its name to “Energy Transfer Operating, L.P.” (“ETO”). Upon the closing of the ETE Merger, ETE contributed to ETP 100% of the limited liability company interests in the General Partner. References herein to “ETP” refer to Energy Transfer Partners, L.P. for periods prior to the ETE Merger and ETO following the ETE Merger, and references to “ETE” refer to Energy Transfer Equity, L.P. for periods prior to the ETE Merger and Energy Transfer LP following the ETE Merger.

All references in this report to the USA Compression Predecessor, as well as the terms “our,” “we,” “us” and “its” refer to the USA Compression Predecessor when used in a historical context or in reference to the periods prior to the Transactions Date, unless the context otherwise requires or where otherwise indicated. All references in this section to the Partnership, as well as the terms “our,” “we,” “us” and “its” refer to USA Compression Partners, LP, together with its consolidated subsidiaries, including the USA Compression Predecessor, when used in the present or future tense and for periods subsequent to the Transactions Date, unless the context otherwise requires or where otherwise indicated.

Overview

We are a growth-oriented Delaware limited partnership, and we believe that we are one of the largest independent providers of compression services in the United States (“U.S.”) in terms of total compression fleet horsepower. USA Compression Partners, LP has been providing compression services since 1998 and completed its initial public offering in January 2013. The USA Compression Predecessor has been providing compression services since 1997 and was a wholly owned indirect subsidiary of ETP prior to the Transactions Date. As of December 31, 2018, we had 3,597,097 horsepower in our fleet and 131,750 horsepower on order for expected delivery during 2019. We provide compression services to our customers primarily in connection with infrastructure applications, including both allowing for the processing and transportation of natural gas through the domestic pipeline system and enhancing crude oil 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 and Fayetteville shales. 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 found in 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 to the comparatively attractive economic returns versus returns achieved in many conventional basins. Furthermore, the changes in production volumes and pressures of shale plays over time require a wider range of compression services than in conventional basins. We believe we are well-positioned to meet these changing operating conditions due to the flexibility of our 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 compression units, typically in shale plays, we also provide compression services in more mature conventional basins, including gas lift applications on crude oil wells targeted by horizontal drilling techniques. Gas lift, a process by which natural gas is injected into the production tubing of an existing producing well, in order to reduce the hydrostatic pressure and allow the oil to flow at a higher rate, and other artificial lift technologies are critical to the enhancement of oil production from horizontal wells operating in tight shale plays.

We operate a modern fleet of compression units, with an average age of approximately five years. We acquire our compression units from third-party fabricators who build the units to our specifications, utilizing specific components from original equipment manufacturers and assembling the units in a manner that provides us the ability to meet certain operating condition thresholds. Our standard new-build compression units are generally configured for multiple compression stages allowing us to operate our units across a broad range of operating conditions. The design flexibility of our units, particularly in midstream applications, allows us to enter into longer-term contracts and reduces the

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redeployment risk of our horsepower in the field. Our modern and standardized fleet, decentralized field level operating structure and technical proficiency in predictive and preventive maintenance and overhaul operations have enabled us to achieve average service run times consistently at or above the levels required by our customers and maintain high overall utilization rates for our fleet.

As part of our services, we engineer, design, operate, service and repair our compression units and maintain related support inventory and equipment. The compression units in our modern fleet are designed to be easily adaptable to fit our customers’ changing compression requirements. Focusing on the needs of our customers and providing them with reliable and flexible compression services in geographic areas of attractive growth helps us to generate stable cash flows for our unitholders.

We provide compression services to our customers under fixed-fee contracts with initial contract terms typically between six months and five years, depending on the application and location of the compression unit. We typically continue to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. We primarily enter into take-or-pay contracts whereby our customers are required to pay our monthly fee even during periods of limited or disrupted throughput, which enhances the stability and predictability of our cash flows. We are not directly exposed to commodity price risk because we do not take title to the natural gas or crude oil involved in our services and because the natural gas used as fuel by our compression units is supplied by our customers without cost to us.

We provide compression services to major oil companies and independent producers, processors, gatherers and transporters of natural gas and crude oil. Regardless of the application for which our services are provided, our customers rely upon the availability of the equipment used to provide compression services and our expertise to maximize the throughput of product, reduce fuel costs and minimize emissions. While we significantly expanded our geographic footprint with our acquisition of the USA Compression Predecessor from ETP (the “CDM Acquisition”), our customers may have compression demands in areas of the U.S. in conjunction with their field development projects where we are not currently operating. We continually consider further expansion of our geographic areas of operation in the U.S. based upon the level of customer demand. Our modern, flexible fleet of compression units, which have been designed to be rapidly deployed and redeployed throughout the country, provides us with opportunities to expand into other areas with both new and existing customers.

We also own and operate a fleet of equipment used to provide natural gas treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling and dehydration, to natural gas producers and midstream companies.

Our assets and operations are organized into a single reportable segment and are all located and conducted in the U.S. See our consolidated financial statements, and the notes thereto, included elsewhere in this report for financial information on our operations and assets; such information is incorporated herein by reference.

Recent Developments

Senior Notes Issuance

On March 23, 2018, USA Compression Partners, LP and its wholly-owned subsidiary, USA Compression Finance Corp., a Delaware corporation (“Finance Corp.” and, together with USA Compression Partners, LP, the “Issuers”) co-issued $725 million in aggregate principal amount of 6.875% senior notes due 2026 (the “Senior Notes”) and entered into an Indenture (the “Indenture”), among the Issuers, the Guarantors (as defined below) and Wells Fargo Bank, National Association, as trustee. The Senior Notes are guaranteed (the “Guarantees”), jointly and severally, on a senior unsecured basis by all of the Partnership’s existing subsidiaries (other than Finance Corp.) and will be guaranteed by each of its future restricted subsidiaries that either borrows under, or guarantees, the Credit Agreement (as defined below) or guarantees certain of the Partnership’s other indebtedness (collectively, the “Guarantors”). The Senior Notes accrue interest at the rate of 6.875% per year, and interest on the Senior Notes is payable semi-annually in arrears on April 1 and October 1, with the first such payment having occurred on October 1, 2018.

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On January 14, 2019, the Partnership completed an exchange offer whereby holders of the Senior Notes exchanged all of the Senior Notes for an equivalent amount of senior notes registered under the Securities Act of 1933 (the “Exchange Notes”). The Exchange Notes are substantially identical to the Senior Notes, except that the Exchange Notes have been registered with the Securities and Exchange Commission (“SEC”) and do not contain the transfer restrictions, restrictive legends, registration rights or additional interest provisions of the Senior Notes.

The Indenture contains customary terms, events of default and covenants relating to, among other things, the incurrence of debt, the payment of distributions or similar restricted payments, undertaking transactions with affiliates and limitations on asset sales.

CDM Acquisition and Issuance of Class B Units

On the Transactions Date, we completed the CDM Acquisition for aggregate consideration to ETP of approximately $1.7 billion, consisting of (i) 19,191,351 common units, (ii) 6,397,965 Class B units representing limited partner interests in us (the “Class B Units”) and (iii) $1.2 billion in cash (including customary closing adjustments). The Class B Units are a class of partnership interests in the Partnership that have substantially all of the rights and obligations of our common units, except that the Class B Units do not receive any quarterly distributions paid on our common units until the Class B Units automatically convert into common units following the record date attributable to the quarter ending June 30, 2019.

General Partner Purchase Agreement

On the Transactions Date and in connection with the closing of the CDM Acquisition, pursuant to that certain Purchase Agreement, dated as of January 15, 2018, by and among ETE, Energy Transfer Partners, L.L.C. (together with ETE, the “GP Purchasers”), USA Compression Holdings, LLC (“USAC Holdings”) and, solely for certain purposes therein, R/C IV USACP Holdings, L.P. and ETP, the GP Purchasers acquired from USAC Holdings (i) all of the outstanding limited liability company interests in the General Partner and (ii) 12,466,912 common units of the Partnership for cash consideration equal to $250 million. Upon the closing of the ETE Merger, ETE contributed all of the outstanding limited liability company interests in the General Partner and the 12,466,912 common units to ETP.

Equity Restructuring Agreement

On the Transactions Date and in connection with the closing of the CDM Acquisition, we consummated the transactions contemplated by the Equity Restructuring Agreement dated January 15, 2018, by and among us, the General Partner and ETE, including, among other things, the cancellation of the Incentive Distribution Rights (as defined in the Second Amended and Restated Agreement of Limited Partnership of the Partnership (the “Partnership Agreement”)) in the Partnership and conversion of the General Partner’s General Partner Interest (as defined in the Partnership Agreement) into a non-economic general partner interest, in exchange for our issuance of 8,000,000 common units to the General Partner. In addition, at any time after one year following the Transactions Date, ETE has the right to contribute (or cause any of its subsidiaries to contribute) to us all of the outstanding equity interests in any of its subsidiaries that owns the general partner interest in us in exchange for $10 million (the “GP Contribution”); provided that the GP Contribution will occur automatically if at any time following the Transactions Date (i) ETE or one of its subsidiaries (including ETP) owns, directly or indirectly, the general partner interest in us and (ii) ETE and its subsidiaries (including ETP) collectively own less than 12,500,000 of our common units.

Series A Preferred Unit and Warrant Private Placement

On the Transactions Date, we also consummated the transactions contemplated by the Series A Preferred Unit and Warrant Purchase Agreement (the “Purchase Agreement”), dated January 15, 2018, between the Partnership and certain investment funds managed or sub-advised by EIG Global Energy Partners (“EIG”) and FS Energy and Power Fund (collectively, the “Purchasers”), whereby the Partnership issued and sold in a private placement $500 million in the aggregate of (i) newly authorized and established Series A Preferred Units representing limited partner interests in us (the “Preferred Units”) and (ii) two tranches of warrants to purchase our common units (collectively, the “Warrants”). Pursuant to the terms of the Purchase Agreement, on the Transactions Date, we issued (i) 500,000 Preferred Units to the

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Purchasers at a price of $1,000 per Preferred Unit, (ii) Warrants to purchase 5,000,000 common units with a strike price of $17.03 per unit and (iii) Warrants to purchase 10,000,000 common units with a strike price of $19.59 per unit. The Warrants may be exercised by the holders thereof at any time beginning on the one year anniversary of the Transactions Date and before the tenth anniversary of the Transactions Date. Upon exercise of the Warrants, we may, at our option, elect to settle the Warrants in common units on a net basis.

Credit Agreement Amendment and Restatement

On the Transactions Date, we entered into the Sixth Amended and Restated Credit Agreement (the “Credit Agreement”) by and among the Partnership, as borrower, USAC OpCo 2, LLC, USAC Leasing 2, LLC, USA Compression Partners, LLC, USAC Leasing, LLC, CDM Resource Management LLC, CDM Environmental & Technical Services LLC and Finance Corp., the lenders party thereto from time to time, JPMorgan Chase Bank, N.A., as agent and an LC issuer, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Regions Capital Markets, a division of Regions Bank, RBC Capital Markets and Wells Fargo Bank, N.A., as joint lead arrangers and joint book runners, Barclays Bank PLC, Regions Bank, RBC Capital Markets and Wells Fargo Bank, N.A., as syndication agents, and MUFG Union Bank, N.A., SunTrust Bank and The Bank of Nova Scotia, as senior managing agents. The Credit Agreement amended and restated that certain Fifth Amended and Restated Credit Agreement, dated as of December 13, 2013, as amended (the “Fifth A&R Credit Agreement”).

The Credit Agreement amended the Fifth A&R Credit Agreement to, among other things, (i) increase the borrowing capacity under the Credit Agreement from $1.1 billion to $1.6 billion (subject to availability under a borrowing base), (ii) extend the termination date (and the maturity date of the obligations thereunder) from January 6, 2020 to April 2, 2023, (iii) subject to the terms of the Credit Agreement, permit up to $400 million of future increases in borrowing capacity, (iv) modify the leverage ratio covenant to be 5.75 to 1.0 through the end of the fiscal quarter ending March 31, 2019, 5.5 to 1.0 through the end of the fiscal quarter ending December 31, 2019, and 5.0 to 1.0 thereafter and (v) increase the applicable margin for eurodollar borrowings to range from 2.00% to 2.75%, depending on our leverage ratio, all as more fully set forth in the Credit Agreement. Amounts borrowed and repaid under the Credit Agreement may be re-borrowed. Please read Part II, Item 7 (“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Description of Revolving Credit Facility.”)

Business Strategies

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

| · |  | Capitalize on the increased need for natural gas compression in conventional and unconventional plays. We expect additional demand for compression services to result from the continuing shift of natural gas production to domestic shale plays as well as the declining production pressures of aging conventional basins. The EIA continues to expect overall natural gas production and transportation volumes, and in particular volumes from domestic shale plays, to increase over the long term. Furthermore, the changes in production volumes and pressures of shale plays over time require a wider range and increased level of compression services than in conventional basins. Our fleet of modern, flexible compression units is capable of being rapidly deployed and redeployed and is designed to operate in multiple compression stages, which will enable us to capitalize on these opportunities in both emerging shale plays and conventional basins.

| · |  | Continue to execute on attractive organic growth opportunities. Prior to the CDM Acquisition, the Partnership grew the horsepower in its fleet of compression units and its compression revenues each at a compound annual growth rate of 15%, which the Partnership executed primarily through organic growth. We believe organic growth opportunities will be a source of near-term growth, which we seek to achieve by (i) increasing our business with existing customers, (ii) obtaining new customers in our existing areas of operations and (iii) expanding our operations into new geographic areas.

| · |  | Partner with customers who have significant compression needs. We actively seek to identify customers with meaningful acreage positions or significant infrastructure development in active and growing areas. We work

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with these customers to jointly develop long-term and adaptable solutions designed to optimize their lifecycle compression costs. We believe this is important in determining the overall economics of producing, gathering and transporting natural gas and crude oil. Our proactive and collaborative approach positions us to serve as our customers’ 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 conjunction with providing compression services to them. We consider opportunities that (i) are in our existing geographic areas of operations or new, high-growth regions, (ii) meet internally established economic thresholds and (iii) may be financed on reasonable terms.

| · |  | Focus on asset utilization. We seek to actively manage our business in a manner that allows us to continue to achieve high utilization rates at attractive service rates while providing us with the most financial flexibility possible. From time to time, we expect the crude oil and natural gas industry to be impacted by the cyclicality of commodity prices. During downturns in commodity prices, producers and midstream operators may reduce their capital spending, which in turn can hinder the demand for compression services. We have the ability, in response to industry conditions, to drastically and rapidly reduce our capital spending, which allows us to avoid financing organic growth with outside capital and aligns our capital spending with the demand for compression services. By reducing organic growth and avoiding new unit deliveries during downturns, we are able to conserve capital and instead focus on the deployment and re-deployment of our existing asset base. With higher utilization, we are better positioned to continue to generate attractive rates of return on our already-deployed capital.

| · |  | Maintain financial flexibility. We intend to maintain financial flexibility to enable us to take advantage of growth opportunities. Historically, we have utilized our cash flow from operations, borrowings under the Credit Agreement 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 maintaining debt levels that we believe are manageable for our business. We believe the appropriate management of our financial position, and the resulting access to capital, positions us to take advantage of future growth opportunities as they arise.

Our Operations

Compression Services

We provide compression services for a monthly service fee. As part of our services, we engineer, design, operate, service and repair our fleet of compression units and maintain related support inventory and equipment. In certain instances, we also engineer, design, install, operate, service and repair certain ancillary equipment used in conjunction with our compression services. We have consistently provided average service run times at or above the levels required by our customers. In general, our team of field service technicians services only our compression fleet and ancillary equipment. In limited circumstances and for established customers, we will agree to service third-party owned equipment. We do not own any compression fabrication facilities.

Our Compression Fleet

The fleet of compression units that we own and use to provide compression services consists of specially engineered compression units that utilize standardized components, principally engines manufactured by Caterpillar, Inc. and compressor frames and cylinders manufactured by Ariel Corporation. Our units can be rapidly and cost effectively modified for specific customer applications. As of December 31, 2018, the average age of our compression units was approximately five years. Our modern, standardized compression unit fleet is powered primarily by the Caterpillar 3400, 3500 and 3600 engine classes, which range from 401 to 5,000 horsepower per unit. These larger horsepower units, which we define as 400 horsepower per unit or greater, represented 85.8% of our total fleet horsepower (including compression units on order) as of December 31, 2018. In addition, a portion of our fleet consists of smaller horsepower units ranging from 40 horsepower to 399 horsepower that are primarily used in gas lift applications. We believe the young age and

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overall composition of our compressor fleet result in fewer mechanical failures, lower fuel usage, and reduced environmental emissions.

The following table provides a summary of our compression units by horsepower as of December 31, 2018:

Unit Horsepower |  | Fleet Horsepower |  | Number of Units |  | Horsepower on Order (1) |  | Number of Units on Order |  | Total Horsepower |  | Number of Units |  | Percent of Total Horsepower |  |  | Percent of Total Units |
Small horsepower |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
<400 |  | 528,084 |  | 3,101 |  | 900 |  | 4 |  | 528,984 |  | 3,105 |  | 14.2 | % |  | 56.0 | %
Large horsepower |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
>400 and <1,000 |  | 429,203 |  | 735 |  | — |  | — |  | 429,203 |  | 735 |  | 11.5 | % |  | 13.3 | %
>1,000 |  | 2,639,810 |  | 1,650 |  | 130,850 |  | 55 |  | 2,770,660 |  | 1,705 |  | 74.3 | % |  | 30.7 | %
Total |  | 3,597,097 |  | 5,486 |  | 131,750 |  | 59 |  | 3,728,847 |  | 5,545 |  | 100.0 | % |  | 100.0 | %

| (1) |  | As of December 31, 2018, we had 131,750 horsepower on order for delivery during 2019.

The following table sets forth certain information regarding our compression fleet as of the dates and for the periods indicated and excludes certain gas treating assets for which horsepower is not a relevant metric:

|  | Year Ended |  | Percent |
|  | December 31, |  | Change |
Operating Data: |  | 2018 |  | 2017 (8) |  | 2016 (8) |  | 2018 |  | 2017 |
Fleet horsepower (at period end) (1) |  | 3,597,097 |  | 1,730,820 |  | 1,600,842 |  | 107.8 | % | 8.1 | %
Total available horsepower (at period end) (2) |  | 3,675,447 |  | 1,780,893 |  | 1,606,424 |  | 106.4 | % | 10.9 | %
Revenue generating horsepower (at period end) (3) |  | 3,262,470 |  | 1,395,328 |  | 1,227,899 |  | 133.8 | % | 13.6 | %
Average revenue generating horsepower (4) |  | 2,760,029 |  | 1,293,864 |  | 1,203,487 |  | 113.3 | % | 7.5 | %
Revenue generating compression units (at period end) |  | 4,753 |  | 2,076 |  | 1,789 |  | 128.9 | % | 16.0 | %
Average horsepower per revenue generating compression unit (5) |  | 674 |  | 681 |  | 668 |  | (1.0) | % | 1.9 | %
Horsepower utilization (6): |  |  |  |  |  |  |  |  |  |  |
At period end |  | 94.0 | % | 87.5 | % | 77.7 | % | 7.4 | % | 12.6 | %
Average for the period (7) |  | 91.9 | % | 82.4 | % | 77.0 | % | 11.5 | % | 7.0 | %

| (1) |  | Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order). As of December 31, 2018, we had 131,750 horsepower on order for delivery during 2019.

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

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

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

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

| (6) |  | Horsepower utilization is calculated as (i) the sum of (a) revenue generating horsepower, (b) horsepower in our fleet that is under contract, but is not yet generating revenue and (c) horsepower not yet in our fleet that is under contract, not yet generating revenue and that is subject to a purchase order, divided by (ii) total available horsepower less idle horsepower that is under repair. Horsepower utilization based on revenue generating horsepower and fleet horsepower was 90.7%, 80.6% and 76.7% at December 31, 2018, 2017 and 2016, respectively.

| (7) |  | Calculated as the average utilization for the months in the period based on utilization at the end of each month in the period. Average horsepower utilization based on revenue generating horsepower and fleet horsepower was 88.0%, 76.9% and 75.9% for the years ended December 31, 2018, 2017 and 2016, respectively.

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| (8) |  | Certain historical metrics attributable to the USA Compression Predecessor have been conformed to the Partnership’s calculation methodology.

A growing number of our compression units contain electronic control systems that enable us to monitor the units remotely by satellite or other means to supplement our technicians’ on-site monitoring visits. We intend to continue to selectively add remote monitoring systems to our fleet during 2019 where beneficial from an operational and financial standpoint. 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 allow our customers, subject to a defined protocol, to start, stop, accelerate and slow down compression units in response to field conditions.

We adhere to routine, preventive and scheduled maintenance cycles. Each of our compression units is subjected to rigorous sizing and diagnostic analyses, including lubricating oil analysis and engine exhaust emission analysis. We have proprietary field service automation capabilities that allow our service technicians to electronically record and track operating, technical, environmental and commercial information at the discrete unit level. These capabilities allow our field technicians to identify potential problems and 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 major overhaul involves the periodic rebuilding of the unit to materially extend its economic useful life or to enhance the unit’s ability to fulfill broader or more diversified compression applications. Because our compression fleet is comprised of units of varying horsepower that have been placed into service with staggered initial on-line dates, we are able to schedule overhauls in a way that avoids excessive annual maintenance capital expenditures and minimizes the revenue impact of down-time.

We believe that our customers, by outsourcing their compression requirements, can achieve higher compression run-times, which translates into increased volumes of either natural gas or crude oil production and, therefore, increased revenues. Utilizing our compression services also allows our customers to reduce their operating, maintenance and equipment costs by allowing us to efficiently manage their changing compression needs. In many of our service contracts, we guarantee our customers 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. We generally 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 on the application and location of the compression unit. After the expiration of the initial term, the contract continues on a month-to-month or longer basis until terminated by us or our customer upon notice as provided for in the applicable contract. As of December 31, 2018, approximately 47% of our compression services on a revenue basis were provided on a month-to-month basis to customers who continue to utilize our services following expiration of the primary term of their contracts with us.

Availability. Our contracts often provide a guarantee of specified availability. We define availability as the percentage of time in a given period that our compression services are being provided or are capable of being provided. Availability is reduced by instances of “down-time” that are attributable to anything other than events of force majeure or acts or failures to act by the customer. Down-time under our contracts usually begins when our services stop being provided or when we receive notice from the customer of the problem. Down-time due to scheduled maintenance is excluded from our availability 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 our fleet as well as promptly respond to a problem to meet our contractual commitments and ensure our customers the compression availability on which their business and our service relationship are based. For service contracts that do not have a stated availability guarantee, we work with those customers to ensure that our compression services meet their operational needs.

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Fees and expenses. Our customers pay a fixed monthly fee for our services. Compression services generally are billed monthly 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 our customers generally are required to pay our monthly fee even during periods of limited or disrupted throughput. We are generally responsible for the costs and expenses associated with operation and maintenance of our compression equipment, although certain fees and expenses are the responsibility of our customers under the terms of their contracts. For example, all fuel gas is provided by our customers without cost to us, and in many cases customers are required to provide all water and electricity. At the customer’s option, we can provide fluids necessary to run the unit to the customer for an additional fee. We provide such fluids for a substantial majority of the compression units deployed in gas lift applications. We are also reimbursed by our customers for certain ancillary expenses such as trucking and crane operation, depending on the terms agreed to in the applicable contract, resulting in little to no impact to gross operating margin.

Service standards and specifications. We commit to provide compression services under service contracts that typically provide that we will supply all compression equipment, tools, parts, field service support and engineering in order to meet our customers’ requirements. Our contracts do not specify the specific compression equipment we will use; instead, in consultation with the customer, we determine what equipment is necessary to perform our contractual commitments.

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

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

Marketing and Sales

Our marketing and client service functions are performed on a coordinated basis by our sales team and field technicians. Salespeople, applications engineers and field technicians qualify, analyze and scope new compression applications as well as regularly visit our customers to ensure customer satisfaction, determine a customer’s needs related to existing services being provided and determine the customer’s future compression service requirements. This ongoing communication allows us to quickly identify and respond to our customers’ compression requirements.

Customers

Our customers consist of more than 400 companies in the energy industry, including major integrated oil companies, public and private independent exploration and production companies and midstream companies. Our ten largest customers accounted for approximately 33% and 43% of our revenue for the year ended December 31, 2018 and 2017, respectively.

Suppliers and Service Providers

The principal manufacturers of components for our natural gas compression equipment include Caterpillar, Inc., Cummins Inc., and Arrow Engine Company for engines, Air-X-Changers and Alfa Laval (US) for coolers, and Ariel Corporation, GE Oil & Gas Gemini products and Arrow Engine Company for compressor frames and cylinders. We also rely primarily on four vendors, A G Equipment Company, Alegacy Equipment, LLC, Standard Equipment Corp. and Genis Holdings LLC, to package and assemble our compression units. Although we rely primarily on these suppliers, we believe alternative sources for natural gas compression equipment are generally available if needed. However, relying on alternative sources may increase our costs and change the standardized nature of our fleet. We have not experienced any material supply problems to date. Although lead-times for new Caterpillar engines and new Ariel compressor frames have in the past been in excess of one year due to increased demand and supply allocations imposed on equipment packagers and end-users, currently lead-times for such engines and frames are approximately one year or shorter. Please

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read Part I, Item 1A (“Risk Factors—Risks Related to Our Business—We depend on a limited number of suppliers and are vulnerable to product shortages and price increases, which could have a negative impact on our results of operations”).

Competition

The compression services business is highly competitive. Some of our competitors have a broader geographic scope and greater financial and other resources than we do. On a regional basis, we experience competition from numerous smaller companies that may be able to more quickly adapt to changes within our industry and changes in economic conditions as a whole, more readily take advantage of available opportunities and adopt more aggressive pricing policies. Additionally, the historical availability of attractive financing terms from financial institutions and equipment manufacturers has made the purchase of individual compression units affordable to our customers. We believe that we compete effectively on the basis of price, equipment availability, customer service, flexibility in meeting customer needs, quality and reliability of our compressors and related services. Please read Part I, Item 1A (“Risk Factors—Risks Related to Our Business—We face significant competition that may cause us to lose market share and reduce our cash available for distribution”).

Seasonality

Our results of operations have not historically been materially affected by seasonality, and we do not currently have reason to believe that seasonal fluctuations will have a material impact in the foreseeable future.

Insurance

We believe that our insurance coverage is customary for the industry and adequate for our business. As is customary in the 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 can be hazardous, involving unforeseen circumstances such as uncontrollable flows of gas or well fluids, fires and explosions or environmental damage. To address the hazards inherent in our business, we maintain insurance coverage that, subject to significant 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 subject to significant limitations. Under the terms of our standard compression services contract, we are responsible for maintaining insurance 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 of materials into the environment or otherwise relating to protection of human health, safety and the environment. These regulations include compliance obligations for air emissions, water quality, wastewater discharges and solid and hazardous waste disposal, as well as regulations designed for the protection of human health and safety and threatened or endangered species. Compliance with these environmental laws and regulations may expose us to significant costs and liabilities and cause us to incur significant capital expenditures in our operations. We are often obligated to assist customers in obtaining permits or approvals in our operations from various federal, state and local authorities. Permits and approvals can be denied or delayed, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue. Moreover, failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of remedial obligations and the issuance of injunctions delaying or prohibiting operations. Private parties may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. While we believe that our operations are in substantial compliance with applicable environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, we cannot predict whether our cost of compliance will materially increase in the future. Any changes in, or more stringent enforcement of, existing environmental laws and regulations, or passage of additional

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environmental laws and regulations that result in more stringent and costly pollution control equipment, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial position.

We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. We cannot assure you, however, that future events such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations, or the development or discovery of new facts or conditions or unforeseen incidents will not cause us to incur significant costs. The following is a discussion of material environmental and safety laws that relate to our operations. We believe that we are in substantial compliance with all of these environmental laws and regulations. Please read Part I, Item 1A (“Risk Factors—Risks Related to Our Business—We are subject to substantial environmental regulation, and changes in these regulations could increase our costs or liabilities”).

Air emissions. The Clean Air Act (“CAA”) and comparable state laws regulate emissions of air pollutants from various industrial sources, including natural gas compressors, and impose certain monitoring and reporting requirements. Such emissions are regulated by air emissions permits, which are applied for and obtained through various state or federal regulatory agencies. Our standard natural gas compression contract provides that the customer is responsible for obtaining air emissions permits and assuming the environmental risks related to site operations. In some instances, our customers may be required to aggregate emissions from a number of different sources on the theory that the different sources should be considered a single source. Any such determinations could have the effect of making projects more costly than our customers expected and could require the installation of more costly emissions controls, which may lead some of our customers not to pursue certain projects.

Increased obligations of operators to reduce air emissions of nitrogen oxides and other pollutants from internal combustion engines in transmission service have been enacted by governmental authorities. For example, in 2010, the U.S. Environmental Protection Agency (“EPA”) published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines, also known as Quad Z regulations. The rule requires us to undertake certain expenditures and activities, including purchasing and installing emissions control equipment on certain compressor engines and generators.

In recent years, the EPA has lowered the National Ambient Air Quality Standards (“NAAQS”) for several air pollutants. For example, in 2015, the EPA finalized a rule strengthening the primary and secondary standards for ground level ozone, both of which are 8-hour concentration standards of 70 parts per billion. After the EPA revises a NAAQS standard, the states are expected to establish revised attainment/non-attainment regions. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our customers’ ability to obtain such permits, and result in increased expenditures for 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 emissions controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package included New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emissions standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules established specific new requirements regarding emissions from compressors and controllers at natural gas processing plants, dehydrators, storage tanks and other production equipment as well as the first federal air standards for natural gas wells that are hydraulically fractured. In June 2016, the EPA took steps to expand on these regulations when it published New Source Performance Standards, known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce methane gas and VOC emissions. These Subpart OOOOa standards would 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 and repair requirements for natural gas compressor and booster stations. However, the EPA announced in April 2017 that it intended to reconsider certain aspects of the 2016 New Source Performance Standards, and in May 2017, the EPA issued an administrative stay of key provisions of the rule, but was promptly ordered by the D.C. Circuit to implement the rule. The EPA also proposed 60-day and two-year stays of certain provisions in June 2017 and published a Notice of Data Availability in November 2017 seeking comment and providing clarification regarding

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the agency’s legal authority to stay the rule. In March 2018, EPA finalized narrow amendments to the rule, and in October 2018, EPA proposed further reconsideration amendments to the rule. Among other things, these amendments would alter fugitive emissions requirements, monitoring frequencies, and well site pneumatic pump standards.

Depending upon whether EPA finalizes these further amendments, Subpart OOOOa and any additional regulation of air emissions from the oil and gas sector could result in increased expenditures for pollution control equipment, which could impact our customers’ operations and negatively impact our business.

We are also subject to air regulation at the state level. For example, the Texas Commission on Environmental Quality (“TCEQ”) has finalized revisions to certain air permit programs that significantly increase the air permitting requirements for new and certain existing oil and gas production and gathering sites for 15 counties in the Barnett Shale production area. The final rule establishes new emissions standards for engines, which could impact the operation of specific categories of engines by requiring the use of alternative engines, compressor packages or the installation of aftermarket emissions control equipment. The rule became effective for the Barnett Shale production area in April 2011, with the lower emissions standards becoming applicable between 2015 and 2030 depending on the type of engine and the permitting requirements. The cost to comply with the revised air permit programs is not expected to be material at this time. However, the TCEQ has stated it will consider expanding application of the new air permit program statewide. At this point, we cannot predict the cost to comply with such requirements if the geographic scope is expanded.

There can be no assurance that future requirements compelling the installation of more sophisticated emissions control equipment would not have a material adverse impact on our business, financial condition, results of operations and cash available for distribution.

Climate change. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases (“GHGs”). In recent years, the U.S. Congress has considered legislation to reduce GHG emissions. It presently appears unlikely that comprehensive climate legislation will be passed in the near future, although energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues. For example, such initiatives could include a carbon tax or cap and trade program. Further, although Congress has not passed such legislation, almost half of the states have begun to address GHG emissions, primarily through the planned development of emissions inventories or regional GHG cap and trade programs. Depending on the particular program, we could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations.

Independent of Congress, the EPA undertook to adopt regulations controlling GHG emissions under its existing CAA authority. For example, in 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs endanger human health and the environment, allowing the agency to proceed with the adoption of regulations that restrict emissions of GHG under existing provisions of the CAA. In 2009 and 2010, the EPA adopted rules regarding regulation of GHG emissions from motor vehicles and requiring the reporting of GHG emissions in the U.S. from specified large GHG emissions sources, including petroleum and natural gas facilities such as natural gas transmission compression facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year.

In 2015, the EPA published standards of performance for GHG emissions from new power plants. The final rule establishes a performance standard for integrated gasification combined cycled units and utility boilers based on the use of the best system of emissions reduction that the EPA has determined has been adequately demonstrated for each type of unit. The rule also sets limits for stationary natural gas combustion turbines based on the use of natural gas combined cycle technology.

The EPA also promulgated the Clean Power Plan rule (“CPP”), which is intended to reduce carbon emissions from existing power plants by 32 percent from 2005 levels by 2030. In February 2016, the U.S. Supreme Court granted a stay of the implementation of the CPP, which will remain in effect throughout the pendency of the appeals process, including at the U.S. Court of Appeals for the D.C. Circuit and the Supreme Court through any certiorari petition that may be granted. The stay suspends the rule, including the requirement that states must start submitting implementation plans. It is not yet clear how the courts will ultimately rule on the legality of the CPP. Additionally, in October 2017, the EPA proposed to repeal the CPP, and in August 2018, the EPA proposed the Affordable Clean Energy rule (“ACE”) to

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replace the CPP. If the effort to replace the CPP with the ACE rule is unsuccessful and rules similar to the CPP are upheld to control GHG emissions from electric utility generating units, demand for the oil and natural gas our customers produce may decrease. In addition, the costs of electricity for our operations may also increase, thereby adversely impacting our business.

In addition to the EPA, the Bureau of Land Management (“BLM”) has also promulgated rules to regulate hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the rock formation to stimulate gas production. In 2015, the BLM promulgated new requirements relating to well construction, water management, and chemical disclosure for companies drilling on federal and tribal land, but subsequently finalized a rule in December 2017 rescinding the 2015 rule. This rescission has been challenged and that litigation is ongoing. If this rescission is not upheld, it could increase the costs of operation for our customers who operate on BLM land, and negatively impact our business. Additionally, on November 15, 2016, the BLM also finalized a rule to reduce the flaring, venting and leaking of methane from oil and gas operations on federal and Indian lands (the “Venting Rule”). The Venting Rule requires operators to use certain technologies and equipment to reduce flaring and to periodically inspect their operations for leaks. The Venting Rule also specifies when operators owe the government royalties for flared gas. In December 2017, BLM finalized a decision to delay implementation of key requirements in the Venting Rule for one year. The agency subsequently finalized a rule in September 2018 to revise the 2016 Venting rule (the “Revised Venting Rule”) by rescinding certain requirements, such as the requirement to use certain technologies and equipment, as well as the leak detection and repair requirement. The Revised Venting Rule also specifies that BLM will defer to the appropriate State or tribal authorities in determining whether royalties are owed for flared gas. Challenges to the Venting Rule and the Revised Venting Rule are pending in court. If the Revised Venting Rule is not upheld, and the Venting Rule is fully implemented, it could increase the costs of operations for our customers who operate on BLM land, and negatively impact our business.

At the international level, nearly 200 nations entered into an international climate agreement at the 2015 United Nations Framework Convention on Climate Change in Paris, under which participating countries did not assume any binding obligation to reduce future emissions of GHGs but instead pledged to voluntarily limit or reduce future emissions. Although the U.S. became a party to the Paris Agreement in April 2016, the Trump administration announced in June 2017 its intention to either withdraw from the Paris Agreement or renegotiate more favorable terms. However, the Paris Agreement stipulates that 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 the Paris Agreement.

Although it is not currently possible to predict with specificity how any proposed or future GHG legislation, regulation, agreements or initiatives will impact our business, any legislation or regulation of GHG emissions that may be imposed in areas in which we conduct business or on the assets we operate could result in increased compliance or operating costs or additional operating restrictions or reduced demand for our services, and could have a material adverse effect on our business, financial condition and results of operations. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that oil and gas will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades. However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in Earth’s atmosphere may produce climate changes that have significant weather-related effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any of those effects were to occur, they could have an adverse effect on our assets and operations.

Water discharge. The Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. The CWA also requires the development and implementation of spill prevention, control and countermeasures, including the construction and maintenance of containment berms and similar structures, if

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required, to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak at such facilities. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Our compression operations do not generate process wastewaters that are discharged to waters of the United States. In any event, our customers assume responsibility under the majority of our standard natural gas compression contracts for obtaining any permits that may be required under the CWA, whether for discharges or developing property by filling wetlands. Considerable legal uncertainty exists surrounding the standard for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the CWA. A 2015 rulemaking by the EPA that would significantly expand the scope of jurisdictional waters has been enjoined in a significant number of states by various district courts. As a result, while the 2015 rule is currently implemented in some states, in other states, the EPA continues to implement the pre-2015 definition of waters of the United States as determined by the preexisting regulatory definition, the Supreme Court’s holding in Rapanos v. United States, and the agency’s post-Rapanos guidance. In 2018, the Supreme Court held that challenges to the rule must be heard in district courts before appeals to the circuit courts can be made; litigation is ongoing regarding substantive challenges to the rule. EPA has also proposed two separate rulemakings to repeal and replace the 2015 Rule, both of which are likely to be challenged if finalized. Should the 2015 rule take effect nationwide, or should a different rule expand the jurisdictional reach of the CWA, our customers could face increased costs and 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 from unconventional sources that require hydraulic fracturing as part of the completion process. Legislation to amend the Safe Drinking Water Act (“SDWA”) to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed and the U.S. Congress continues to consider legislation to amend the SDWA. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a multi-year study of the potential environmental impacts of hydraulic fracturing. In December 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 water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas 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 into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. The EPA has also announced that it believes hydraulic fracturing using fluids containing diesel fuel can be regulated under the SDWA notwithstanding the SDWA’s general exemption for hydraulic fracturing. Several states have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing, 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 adoption of new laws and regulations at the federal or state level or if the agencies that issue the permits develop new interpretations of those requirements, that could lead to delays, increased operating costs and process prohibitions that could reduce demand for our compression services, which could materially adversely affect our revenue and results of operations.

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

Site remediation. The Comprehensive Environmental Response Compensation and Liability Act (“CERCLA”) and comparable state laws impose strict, joint and several liability without regard to fault or the legality of the original

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conduct on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner and operator of a disposal site where a hazardous substance release occurred and any company that transported, disposed of or arranged for the transport or disposal of hazardous substances released at the site. Under CERCLA, such persons may be liable for the costs of remediating the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. In addition, where contamination may be present, it is not uncommon for the neighboring landowners and other third parties to file claims for personal injury, property damage and recovery of response costs. While we generate materials in the course of our operations that may be regulated as hazardous substances, we have not received notification that we may be potentially responsible for cleanup costs under CERCLA at any site.

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

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

Employees

USAC Management Services, LLC (“USAC Management”), a wholly owned subsidiary of the General Partner, 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 of December 31, 2018, USAC Management had 864 full time employees. None of our employees are subject to collective bargaining agreements. We consider our employee relations to be good.

Available Information

Our website address is usacompression.com. We make available, free of charge at the “Investor Relations” section of our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as soon as reasonably practicable after such reports are electronically filed with, or furnished to, the SEC. The information contained on our website does not constitute part of this report.

The SEC maintains a website that contains these reports at sec.gov.

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ITEM 1A.Risk Factors

As described in Part I (“Disclosure Regarding Forward-Looking Statements”), this report contains forward-looking statements regarding us, our business and our industry. The risk factors described below, among others, could cause our actual results to differ materially from the expectations reflected in the forward-looking statements. If any of the following risks were to materialize, our business, financial condition or results of operations could be materially and adversely affected. In that case, we might not be able to continue to pay our current quarterly distribution on our common units or increase the level of such distributions in the future, and the trading price of our common units could decline.

Risks Related to Our Business

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to the General Partner, to enable us to make cash distributions on our common units at the current level.

In order to make cash distributions at our current distribution rate of $0.525 per common unit per quarter, or $2.10 per common unit per year, we will require available cash of $47.2 million per quarter, or $189.0 million per year, based on the number of common units outstanding as of February 14, 2019. In addition, each Class B Unit will automatically convert to one common unit of the Partnership following the record date attributable to the quarter ending June 30, 2019. Distributions on the newly converted Class B Units will require additional available cash of $3.4 million per quarter, or $13.4 million per year at our current distribution rate.

Furthermore, the Partnership Agreement prohibits us from paying distributions on our common units unless we have first paid the quarterly distribution on the Preferred Units, including any previously accrued but unpaid distributions on the Preferred Units. The Preferred Unit distributions require $12.2 million quarterly, or $48.8 million annually, based on the number of Preferred Units outstanding and the distribution rate of $24.375 per Preferred Unit per quarter, or $97.50 per Preferred Unit per year.

Under our cash distribution policy, the amount of cash we can distribute to our unitholders principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

| · |  | the level of production of, demand for, and price of natural gas and crude oil, particularly the level of production in the regions where we provide compression services;

| · |  | the fees we charge, and the margins we realize, from our compression services;

| · |  | the cost of achieving organic growth in current and new markets;

| · |  | the ability to effectively integrate any assets or businesses we acquire;

| · |  | the level of competition from other companies; and

| · |  | prevailing global and regional economic and regulatory conditions, and their impact on us and our customers.

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

| · |  | the levels of our maintenance and expansion capital expenditures;

| · |  | the level of our operating costs and expenses;

| · |  | our debt service requirements and other liabilities;

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| · |  | fluctuations in our working capital needs;

| · |  | restrictions contained in the Credit Agreement or the Indenture governing the Senior Notes;

| · |  | the cost of acquisitions;

| · |  | fluctuations in interest rates;

| · |  | the financial condition of our customers;

| · |  | our ability to borrow funds and access the capital markets; and

| · |  | the amount of cash reserves established by the General Partner.

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

The demand for our compression services depends upon the continued demand for, and production of, natural gas and crude oil. Demand may be affected by, among other factors, natural gas prices, crude oil prices, weather, availability of alternative energy sources, governmental regulation and the overall demand for energy. Any prolonged, substantial reduction in the demand for natural gas or crude oil would likely depress the level of production activity and result in a decline in the demand for our compression services, which could result in a reduction in our revenues and our cash available for distribution.

In particular, lower natural gas or crude oil prices over the long term could result in a decline in the production of natural gas or crude oil, respectively, resulting in reduced demand for our compression services. For example, the North American rig count, as measured by Baker Hughes, hit a 2014 peak of 1,931 rigs on September 12, 2014, and at that time, Henry Hub natural gas spot prices were $3.82 per MMBtu and West Texas Intermediate (“WTI”) crude oil spot prices were $92.18 per barrel. By contrast, the North American rig count hit a modern low of 404 rigs on May 20, 2016, and at that time, Henry Hub natural gas spot prices were $1.81 per MMBtu and WTI crude oil spot prices were $47.67 per barrel. This slowdown in new drilling activity caused some pressure on service rates for new and existing services and contributed to a decline in our utilization during 2015 and into 2016. By the end of December 2018, the North American rig count was 1,083 rigs, the price of WTI crude oil was $45.15 per barrel and Henry Hub natural gas spot prices were $3.25 per MMBtu. Although commodity prices and our utilization generally increased during 2016, 2017 and 2018, the increased activity resulting from such increased commodity prices may not continue. In addition, a small portion of our fleet is used in gas lift applications in connection with crude oil production using horizontal drilling techniques. During the period of low crude oil prices, we experienced pressure on service rates from our customers in gas lift applications; if commodity prices decline from current levels, we may again experience pressure on service rates.

Additionally, an increasing percentage of natural gas and crude oil production comes from unconventional sources, such as shales, tight sands and coalbeds. Such sources can be less economically feasible to produce in low commodity price environments, in part due to costs related to compression requirements, and a reduction in demand for natural gas or gas lift for crude oil may cause such sources of natural gas or crude oil to become uneconomic to drill and produce, which could in turn negatively impact the demand for our services. Further, if demand for our services decreases, we may be asked to renegotiate our service contracts at lower rates. In addition, governmental regulation and tax policy may impact the demand for natural gas or crude oil or impact the economic feasibility of the development of new fields or production of existing fields, which are important components of our ability to expand.

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

We provide compression services under contracts with several key customers. The loss of one of these key customers may have a greater effect on our financial results than for a company with a more diverse customer base. Our

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ten largest customers accounted for approximately 33% and 43% of our revenue for the years ended December 31, 2018 and 2017, respectively. The loss of all or even a portion of the compression services we provide to our key customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations, financial condition and cash available for distribution.

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

During times when the natural gas or crude oil markets weaken, our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our services. For example, our customers could seek to preserve capital by using lower cost providers, not renewing month-to-month contracts or determining not to enter into any new compression service contracts. A significant decline in commodity prices may cause certain of our customers to reconsider their near-term capital budgets, which may impact large-scale natural gas infrastructure and crude oil production activities. Reduced demand for our services could adversely affect our business, results of operations, financial condition and cash flows.

We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, suppliers or vendors could reduce our revenues, increase our expenses and otherwise have a negative impact on our ability to conduct our business, operating results, cash flows and ability to make distributions to our unitholders.

Weak economic conditions and widespread financial distress could reduce the liquidity of our customers, suppliers or vendors, making it more difficult for them to meet their obligations to us. We are therefore subject to risks of loss resulting from nonpayment or nonperformance by our customers. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. In the event that any of our customers was to enter into bankruptcy, we could lose all or a portion of the amounts owed to us by such customer, and we may be forced to cancel all or a portion of our service contracts with such customer at significant expense to us.

In addition, nonperformance by suppliers or vendors who have committed to provide us with critical products or services could raise our costs or interfere with our ability to successfully conduct our business.

We face significant competition that may cause us to lose market share and reduce our cash available for distribution.

The natural gas compression business is highly competitive. Some of our competitors have a broader geographic scope and greater financial and other resources than we do. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flows could be adversely affected by the activities of our competitors and our customers. If our competitors substantially increase the resources they devote to the development and marketing of competitive services or substantially decrease the prices at which they offer their services, we may be unable to compete effectively. Some of these competitors may expand or construct newer, more powerful or more flexible compression fleets, which would create additional competition for us. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and cash available for distribution.

Our customers may choose to vertically integrate their operations by purchasing and operating their own compression fleet, increasing the number of compression units they currently own or using alternative technologies for enhancing crude oil production.

Our customers that are significant producers, processors, gatherers and transporters of natural gas and crude oil may choose to vertically integrate their operations by purchasing and operating their own compression fleets in lieu of using our compression services. The historical availability of attractive financing terms from financial institutions and equipment manufacturers facilitates this possibility by making the purchase of individual compression units increasingly affordable to our customers. In addition, there are many technologies available for the artificial enhancement of crude oil production, and our customers may elect to use these alternative technologies instead of the gas lift compression services we provide. Such vertical integration, increases in vertical integration or use of alternative technologies could result in

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decreased demand for our compression services, which may have a material adverse effect on our business, results of operations, financial condition and reduce our cash available for distribution.

A significant portion of our services are provided to customers on a month-to-month basis, and we cannot be sure that such customers will continue to utilize our services.

Our contracts typically have an initial term of between six months and five years, depending on the application and location of the compression unit. After the expiration of the initial term, the contract continues on a month-to-month or longer basis until terminated by us or our customers upon notice as provided for in the applicable contract. As of December 31, 2018, approximately 47% of our compression services on a revenue basis were provided on a month-to-month basis to customers who continue to utilize our services following expiration of the primary term of their contracts. These customers can generally terminate their month-to-month compression services contracts on 30 days’ written notice. If a significant number of these customers were to terminate their month-to-month services, or attempt to renegotiate their month-to-month contracts at substantially lower rates, it could have a material adverse effect on our business, results of operations, financial condition and cash available for distribution.

We may be unable to grow our cash flows if we are unable to expand our business, which could limit our ability to maintain or increase the level of distributions to our common unitholders.

A principal focus of our strategy is to increase our per common unit distribution by expanding our business over time. Our future growth will depend upon a number of factors, some of which we cannot control. These factors include our 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 the level of distributions on our common units, in which event the market price of our common units will likely decline.

We may be unable to grow successfully through acquisitions, which may negatively impact our operations and limit our ability to maintain or increase the level of distributions on our common units.

From time to time, we may choose to make business acquisitions, such as the CDM Acquisition, to pursue market opportunities, increase our existing capabilities and expand into new geographic areas of operations. While we have reviewed acquisition opportunities in the past and will continue to do so in the future, we may not be able to identify attractive acquisition opportunities or successfully acquire identified targets.

Any acquisitions we do complete may require us to issue a substantial amount of equity or incur a substantial amount of indebtedness. If we consummate any future material acquisitions, our capitalization may change significantly,

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and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in connection with any future acquisition. Furthermore, competition for acquisition opportunities may escalate, increasing our costs of pursuing acquisitions or causing us to refrain from making acquisitions.

Also, our reviews of proposed business or asset acquisitions are inherently imperfect because it is generally not feasible to perform an in-depth review of each such proposal given time constraints imposed by sellers. Even if performed, a detailed review of assets and businesses may not reveal existing or potential problems, and may not provide sufficient familiarity with such business or assets to fully assess their deficiencies and potential. Inspections may not be performed on every asset, and environmental problems, such as groundwater contamination, may not be observable even when an inspection is undertaken.

Integration of assets acquired in past acquisitions or future acquisitions with our existing business can be a complex, time-consuming and costly process, particularly in the case of material acquisitions such as the CDM Acquisition, which significantly increased our size and expanded the geographic areas in which we operate. A failure to successfully integrate the acquired assets with our existing business in a timely manner may have a material adverse effect on our business, financial condition, results of operations or cash available for distribution to our unitholders.

The difficulties of integrating past and future acquisitions with our business include, among other things:

| · |  | operating a larger combined organization in new geographic areas and new lines of business;

| · |  | hiring, training or retaining qualified personnel to manage and operate our growing business and assets;

| · |  | integrating management teams and employees into existing operations and establishing effective communication and information exchange with such management teams and employees;

| · |  | diversion of management’s attention from our existing business;

| · |  | assimilation of acquired assets and operations, including additional regulatory programs;

| · |  | loss of customers;

| · |  | loss of key employees;

| · |  | maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002 as well as other regulatory compliance and corporate governance matters; and

| · |  | integrating new technology systems for financial reporting.

If any of these risks or other unanticipated liabilities or costs were to materialize, we may not realize the desired benefits from past and future acquisitions, resulting in a negative impact on our results of operations. For example, subsequent to the CDM Acquisition the attrition rate of specialized field technicians exceeded our projections and, as a result, we incurred unanticipated costs to utilize third-party contractors to service our compression units at a greater cost than we would have incurred to compensate employees to perform the same work.

We may not be successful in integrating acquisitions, including the CDM Acquisition, into our existing operations within our anticipated timeframe, which may result in unforeseen operational difficulties or diminished financial performance or require a disproportionate amount of our management’s attention. In addition, acquired assets may perform at levels below the forecasts used to evaluate their acquisition, due to factors beyond our control. If the acquired assets perform at levels below the forecasts, then our future results of operations could be negatively impacted.

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Our ability to fund purchases of additional compression units and complete acquisitions in the future is dependent on our ability to access external expansion capital.

The Partnership Agreement requires us to distribute all of our available cash to our unitholders (excluding prudent operating reserves). We expect that we will rely primarily upon cash generated by operating activities and, where necessary, borrowings under the Credit Agreement and the issuance of debt and equity securities, to fund expansion capital expenditures. However, we may not be able to obtain equity or debt financing on terms favorable to us or at all. To the extent we are unable to efficiently finance growth through external sources, our ability to maintain or increase the level of distributions on our common units could be significantly impaired. In addition, because we distribute all of our available cash, excluding prudent operating reserves, we may not grow as quickly as businesses that are able to reinvest their available cash to expand ongoing operations.

There are no limitations in the Partnership Agreement on our ability to issue additional equity securities, including securities ranking senior to the common units, subject to certain restrictions in the Partnership Agreement limiting our ability to issue units senior to or pari passu with the Preferred Units. To the extent we issue additional equity securities, including common units and preferred units, the payment of distributions on those additional securities may increase the risk that we will be unable to maintain or increase our per common unit distribution level. Similarly, our incurrence of borrowings or other debt to finance our growth strategy would increase our interest expense, which in turn would decrease our cash available for distribution.

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

The Credit Agreement is a $1.6 billion revolving credit facility that matures in April 2023. In addition, we have the option to increase the amount of total commitments under the Credit Agreement by up to $400.0 million, subject to receipt of lender commitments and satisfaction of other conditions. As of December 31, 2018, we had outstanding borrowings under the Credit Agreement of $1.1 billion and a leverage ratio of 4.33x, borrowing base availability (based on our borrowing base) of $550.5 million and, subject to compliance with the applicable financial covenants, available borrowing capacity under the Credit Agreement of $550.5 million. Financial covenants in the Credit Agreement permit a maximum leverage ratio of (A) 5.75 to 1.0 through the end of the fiscal quarter ending March 31, 2019, (B) 5.50 to 1.0 through the end of the fiscal quarter ending December 31, 2019 and (C) 5.00 to 1.0 thereafter. As of February 14, 2019, we had outstanding borrowings under the Credit Agreement of $1.1 billion.

Our ability to incur additional debt is also subject to limitations in the Credit Agreement, including certain financial covenants. 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 or other 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 would otherwise 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 a downturn in our business or the economy generally.

Additionally, in March 2018, the Issuers co-issued $725.0 million of Senior Notes. The Senior Notes mature in 2026 and accrue interest at the rate of 6.875% per year. Interest on the Senior Notes is payable semiannually in arrears on April 1 and October 1.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service our debt under the Credit Agreement could be impacted by market interest rates, as all of our outstanding borrowings under the Credit Agreement are subject to variable interest rates that fluctuate with changes in market interest rates. A substantial increase in the interest rates

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applicable to our outstanding borrowings could have a material negative impact on our cash available for distribution. If our operating results are not sufficient to service our current or future indebtedness, we could be forced to take actions such as reducing the level of distributions on our common units, curtailing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt or seeking additional equity capital. We may be unable to effect any of these actions on terms satisfactory to us or at all.

The terms of the Credit Agreement and the Indenture restrict our current and future operations, particularly our ability to respond to changes or to take certain actions, may limit our ability to pay distributions and may limit our ability to capitalize on acquisitions and other business opportunities.

The Credit Agreement and the Indenture governing the Senior Notes contain a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability to:

| · |  | incur additional indebtedness;

| · |  | pay dividends or make other distributions or repurchase or redeem equity interests;

| · |  | prepay, redeem or repurchase certain debt;

| · |  | issue certain preferred units or similar equity securities;

| · |  | make investments;

| · |  | sell assets;

| · |  | incur liens;

| · |  | enter into transactions with affiliates;

| · |  | alter the businesses we conduct;

| · |  | enter into agreements restricting our subsidiaries’ ability to pay dividends; and

| · |  | consolidate, merge or sell all or substantially all of our assets.

In addition, the Credit Agreement contains certain operating and financial covenants and requires us to maintain specified financial ratios and satisfy other financial condition tests. Our ability to comply with those covenants and meet those financial ratios and tests can be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other conditions deteriorate, our ability to comply with these covenants may be impaired.

A breach of the covenants or restrictions under the Credit Agreement or the Indenture could result in an event of default, in which case a significant portion of our indebtedness may become immediately due and payable and any other debt to which a cross-acceleration or cross-default provision applies may also be accelerated, our lenders’ commitment to make further loans to us may terminate, and we may be prohibited from making distributions to our unitholders. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. If we were unable to repay amounts due and payable under the Credit Agreement, those lenders could proceed against the collateral securing that indebtedness. We may not be able to replace the Credit Agreement, or if we are, any subsequent replacement of the Credit Agreement or any new indebtedness could be equally or more restrictive.

These restrictions may negatively affect our ability to grow in accordance with our strategy. In addition, our financial results, substantial indebtedness and credit ratings could adversely affect the availability and terms of our

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financing. Please read Part II, Item 7 (“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving Credit Facility and— Senior Notes”).

The Preferred Units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of our common units.

The Preferred Units rank senior to all of our other classes or series of equity securities with respect to distribution rights and rights upon liquidation. These preferences could adversely affect the market price for our common units, or could make it more difficult for us to sell our common units in the future.

In addition, distributions on the Preferred Units accrue and are cumulative, at the rate of 9.75% per annum on the original issue price, which amounts to a quarterly distribution of $24.375 per Preferred Unit. If we do not pay the required distributions on the Preferred Units, we will be unable to pay distributions on our common units. Additionally, because distributions on the Preferred Units are cumulative, we will have to pay all unpaid accumulated distributions on the Preferred Units before we can pay any distributions on our common units. Also, because distributions on our common units are not cumulative, if we do not pay distributions on our common units with respect to any quarter, our common unitholders will not be entitled to receive distributions covering any prior periods if we later recommence paying distributions on our common units.

The Preferred Units are convertible into common units by the holders of the Preferred Units or by us in certain circumstances. Our obligation to pay distributions on the Preferred Units, or on the common units issued following the conversion of the Preferred Units, could impact our liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions, and other general Partnership purposes. Our obligations to the holders of the Preferred Units could also limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition. See Note 11 to our consolidated financial statements.

Restrictions in the Partnership Agreement related to the Preferred Units may limit our ability to make distributions to our common unitholders and our ability to capitalize on acquisition and other business opportunities.

The operating and financial restrictions and covenants in the Partnership Agreement related to the Preferred Units could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. The Partnership Agreement restricts or limits our ability (subject to certain exceptions) to:

| · |  | pay distributions on any junior securities, including our common units, prior to paying the quarterly distribution payable 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 an unlimited number of securities ranking junior to the Preferred Units, including junior preferred units and additional common units; and

| · |  | incur Indebtedness (as defined in the Credit Agreement) if, after giving pro forma effect to such incurrence, the Leverage Ratio (as defined in the Credit Agreement) determined as of the last day of the most recently ended fiscal quarter would exceed 6.5x, subject to certain exceptions.

A prolonged downturn in the economic environment could cause an impairment of goodwill or other intangible assets and reduce our earnings.

We have recorded $619.4 million of goodwill and $392.6 million of other intangible assets as of December 31, 2018. Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets. Generally accepted accounting principles of the United States (“GAAP”) requires us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired. Any event that causes a reduction in demand for our services could result in a reduction of

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our estimates of future cash flows and growth rates in our business. These events could cause us to record impairments of goodwill or other intangible assets.

If we determine that any of our goodwill or other intangible assets are impaired, we will be required to take an immediate charge to earnings with a corresponding reduction of partners’ capital resulting in an increase in balance sheet leverage as measured by debt to total capitalization. For example, for the year ended December 31, 2017, the USA Compression Predecessor recognized a $223.0 million impairment of goodwill (see Note 7 to our consolidated financial statements).

Impairment in the carrying value of long-lived assets could reduce our earnings.

We have a significant number of long-lived assets on our consolidated balance sheet. Under GAAP, we are required to review our long-lived assets for impairment when events or circumstances indicate that the carrying value of such assets may not be recoverable or such assets will no longer be utilized in the operating fleet. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If business conditions or other factors cause the expected undiscounted cash flows to decline, we may be required to record non-cash impairment charges. Events and conditions that could result in impairment in the value of our long-lived assets include changes in the industry in which we operate, competition, advances in technology, adverse changes in the regulatory environment, or other factors leading to a reduction in our expected long-term profitability. For example, during the fiscal year ended December 31, 2018, we evaluated the future deployment of our idle fleet under then-current market conditions and determined to retire and re-utilize key components of 103 compressor units, or approximately 33,000 horsepower, that were previously used to provide services in our business. As a result, we recognized impairments of $8.7 million during the year ended December 31, 2018. The USA Compression Predecessor did not recognize any impairment of long-lived assets during the years ended December 31, 2017 or 2016.

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

We depend on the continuing efforts of our executive officers and the departure of any of our executive officers could have a significant negative effect on our business, operating results, financial condition and on our ability to compete effectively in the marketplace.

Additionally, our ability to hire, train and retain qualified personnel will continue to be important and could become more challenging as we grow and to the extent energy industry market conditions are competitive. When general industry conditions are favorable, the competition for experienced operational and field technicians increases as other energy and manufacturing companies’ needs for the same personnel increases. Our ability to grow or even to continue our current level of service to our current customers could be adversely impacted if we are unable to successfully hire, train and retain these important personnel.

We depend on a limited number of suppliers and are vulnerable to product shortages and price increases, which could have a negative impact 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 Ariel Corporation, GE Oil & Gas Gemini products and Arrow Engine Company for compressor frames and cylinders. Our reliance on these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply of required components in a timely manner. We also rely primarily on four vendors, A G Equipment Company, Alegacy Equipment, LLC, Standard Equipment Corp. and Genis Holdings LLC, to package and assemble our compression units. We do not have long-term contracts with these suppliers or packagers, and a partial or complete loss of any of these sources could have a negative impact on our results of operations and could damage our customer relationships. Some of these suppliers manufacture the components we purchase in a single facility, and any damage to that facility could lead to significant delays in delivery of completed compression units to us.

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

We are subject to stringent and complex federal, state and local laws and regulations, including laws and regulations regarding the discharge of materials into the environment, emissions controls and other environmental protection and occupational health and safety concerns, as discussed in detail in Item 1 (“Business—Our Operations—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 that was lawful at the time it occurred or the conduct of, or conditions caused by, prior owners or operators or other third parties. In addition, where contamination may be present, it is not uncommon for neighboring land owners and other third parties to file claims for personal injury, property damage and recovery of response costs. Remediation costs and other damages arising as a result of environmental laws and regulations, and costs associated with new information, changes in existing environmental laws and regulations or the adoption of new environmental laws and regulations could be substantial and could negatively impact our financial condition or results of operations. Moreover, failure to comply with these environmental laws and regulations may result in the imposition of administrative, civil and criminal penalties and the issuance of injunctions delaying or prohibiting operations.

We conduct operations in a wide variety of locations across the continental U.S. These operations require U.S. federal, state or local environmental permits or other authorizations. Our operations may require new or amended facility permits or licenses from time to time with respect to storm water discharges, waste handling or air emissions relating to equipment operations, 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 operate under various air regulatory programs established by rule or regulation. These permits and authorizations frequently contain numerous compliance requirements, including monitoring and reporting obligations and operational restrictions, such as emissions limits. Given the wide variety of locations in which we operate, and the numerous environmental permits and other authorizations that are applicable to our operations, we may occasionally identify or be notified of technical violations of certain requirements existing under various permits or other authorizations. We could be subject to penalties for any noncompliance in the future.

In our business, we routinely deal with natural gas, oil and other petroleum products at our worksites. Hydrocarbons or other hazardous substances or wastes may have been disposed or released on, under or from properties used by us to provide compression services or inactive compression unit storage or on or under other locations where such substances or wastes have been taken for disposal. These properties may be subject to investigatory, remediation and monitoring requirements under federal, state and local environmental laws and regulations.

The modification or interpretation of existing environmental laws or regulations, the more vigorous enforcement of existing environmental laws or regulations, or the adoption of new environmental laws or regulations may also negatively impact oil and natural gas exploration and production, gathering and pipeline companies, including our customers, which in turn could have a negative impact on us.

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

New regulations or proposed modifications to existing regulations under the Clean Air Act (“CAA”), as discussed in detail in Item 1 (“Business—Our Operations—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 the primary and secondary National Ambient Air Quality Standards (“NAAQS”) for ground level ozone, both of which are 8-hour concentration standards of 70 parts per billion. After the EPA revises a NAAQS standard, the states are expected to establish revised attainment/non-attainment regions. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our customers’ ability to obtain such permits, and result in increased expenditures for pollution control equipment, which could negatively impact our customers’ operations, increase the cost of additions to property, plant, and equipment, and negatively impact our business.

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In 2012, the EPA finalized rules that establish new air emissions controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package included New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emissions standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules established specific new requirements regarding emissions from compressors and controllers at natural gas processing plants, dehydrators, storage tanks and other production equipment as well as the first federal air standards for natural gas wells that are hydraulically fractured. In June 2016, the EPA took steps to expand on these regulations when it published New Source Performance Standards, known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce methane gas and VOC emissions. These Subpart OOOOa standards would 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 and repair requirements for natural gas compressor and booster stations. However, the EPA announced in April 2017 that it intended to reconsider certain aspects of the 2016 New Source Performance Standards, and in May 2017, the EPA issued an administrative stay of key provisions of the rule, but was promptly ordered by the D.C. Circuit to implement the rule. The EPA also proposed 60-day and two-year stays of certain provisions in June 2017 and published a Notice of Data Availability in November 2017 seeking comment and providing clarification regarding the agency’s legal authority to stay the rule. In March 2018, the EPA finalized narrow amendments to the rule, and in October 2018, the EPA proposed further reconsideration amendments to the rule. Among other things, these amendments would alter fugitive emissions requirements, monitoring frequencies and well site pneumatic pump standards.

Depending on whether the EPA finalizes these further amendments, Subpart OOOOa and any additional regulation of air emissions from the oil and gas sector could result in increased expenditures for pollution control equipment, which could impact our customers’ operations and negatively impact our business.

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

Climate change continues to attract considerable public and scientific attention. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases (“GHGs”). In recent years, the U.S. Congress has considered legislation to reduce GHG emissions. It presently appears unlikely that comprehensive climate legislation will be passed in the near future, although energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues. For example, such initiatives could include a carbon tax or cap and trade program. Further, although Congress has not passed such legislation, almost half of the states have begun to address GHG emissions, primarily through the planned development of emissions inventories or regional GHG cap and trade programs. Depending on the particular program, we could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations.

Independent of Congress, and as discussed in detail in Item 1 (“Business—Our Operations—Environmental and Safety Regulations”), the EPA undertook to adopt regulations controlling GHG emissions under its existing CAA authority. For example, in 2015, the EPA published standards of performance for GHG emissions from new power plants. The final rule establishes a performance standard for integrated gasification combined cycled units and utility boilers based on the use of the best system of emissions reduction that the EPA has determined has been adequately demonstrated for each type of unit. The rule also sets limits for stationary natural gas combustion turbines based on the use of natural gas combined cycle technology. The EPA also promulgated the Clean Power Plan rule (“CPP”), which is intended to reduce carbon emissions from existing power plants by 32 percent from 2005 levels by 2030. In February 2016, the U.S. Supreme Court granted a stay of the implementation of the CPP, which will remain in effect throughout the pendency of the appeals process, including at the United States Court of Appeals for the D.C. Circuit and the Supreme Court through any certiorari petition that may be granted. The stay suspends the rule, including the requirement that states must start submitting implementation plans. It is not yet clear how the courts will ultimately rule on the legality of the CPP. Additionally, in October 2017, the EPA proposed to repeal the CPP, and in August 2018, the EPA proposed the Affordable Clean Energy rule (“ACE”) to replace the CPP. If the effort to replace the CPP with the ACE is unsuccessful and rules similar to the CPP are upheld to control GHG emissions from electric utility generating units, demand for the oil and natural gas our customers produce may decrease.

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Although it is not currently possible to predict with specificity how any proposed or future GHG legislation, regulation, agreements or initiatives will impact our business, any legislation or regulation of GHG emissions that may be imposed in areas in which we conduct business or on the assets we operate could result in increased compliance or operating costs or additional operating restrictions or reduced demand for our services, and could have a material adverse effect on our business, financial condition and results of operations.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in Earth’s atmosphere may produce climate changes that have significant weather-related effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any of those effects were to occur, they could have an adverse effect on our assets and operations. Also, recent activism directed at shifting funding away from companies with energy-related assets could result in a reduction of funding for the energy sector overall, which could have an adverse effect on our ability to obtain external financing.

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

A significant portion of our customers’ natural gas production is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the rock 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 require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed and the U.S. Congress continues to consider legislation to amend the SDWA. Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a multi-year study of the potential environmental impacts of hydraulic fracturing. In December 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 water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: water withdrawals for fracturing in times or areas 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 into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits.

In addition to the EPA, the Bureau of Land Management (“BLM”) has also promulgated rules to regulate hydraulic fracturing. In 2015, the BLM promulgated new requirements relating to well construction, water management, and chemical disclosure for companies drilling on federal and tribal land, but subsequently finalized a rule in December 2017 rescinding the 2015 rule. This rescission has been challenged, and that litigation is ongoing. If this rescission is not upheld, it could increase the costs of operation for our customers who operate on BLM land, and negatively impact our business. Additionally, on November 15, 2016, the BLM also finalized a rule to reduce the flaring, venting and leaking of methane from oil and gas operations on federal and Indian lands. The Venting Rule requires operators to use certain technologies and equipment to reduce flaring and to periodically inspect their operations for leaks. The Venting Rule also specifies when operators owe the government royalties for flared gas. In December 2017, BLM finalized a decision to delay implementation of key requirements in the Venting Rule for one year. The agency subsequently finalized a rule in September 2018 to revise the 2016 Venting rule by rescinding certain requirements, such as the requirement to use certain technologies and equipment, as well as the leak detection and repair requirement. The Revised Venting Rule also specifies that the BLM will defer to the appropriate State or tribal authorities in determining whether royalties are owed for flared gas. Challenges to the Venting Rule and the Revised Venting Rule are pending in court. If the Revised Venting Rule is not upheld, and the Venting Rule is fully implemented, it could increase the costs of operations for our customers who operate on BLM land, and in turn negatively impact our business.

State and federal regulatory agencies have also recently focused on a possible connection between the operation of injection wells used for oil and gas waste disposal and seismic activity. Similar concerns have been raised that hydraulic fracturing may also contribute to seismic activity. When caused by human activity, such events are called induced seismicity. Developing research suggests that the link between seismic activity and wastewater disposal may vary by

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region, and that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity. In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas. In light of these concerns, some state regulatory agencies have modified their regulations or issued orders to address induced seismicity. Increased regulation and attention given to induced seismicity could lead to greater opposition to, and litigation concerning, oil and gas activities utilizing hydraulic fracturing or injection wells for waste disposal, which could indirectly impact our business, financial condition and results of operations. In addition, these concerns may give rise to private tort suits against our customers from individuals who claim they are adversely impacted by seismic activity they allege was induced. Such claims or actions could result in liability to our customers for property damage, exposure to waste and other hazardous materials, nuisance or personal injuries, and require our customers to expend additional resources or incur substantial 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 and permits were required through the adoption of new laws and regulations at the federal or state level or the development of new interpretations of those requirements by the agencies that issue the required permits, that could lead to operational delays, increased operating costs and process prohibitions that could reduce demand for our compression services, which would materially adversely affect our revenue and results of operations.

The CDM Acquisition could expose us to additional unknown and contingent liabilities.

The CDM Acquisition could expose us to additional unknown and contingent liabilities. We performed due diligence in connection with the CDM Acquisition and attempted to verify the representations made by ETP in connection therewith, but there may be unknown and contingent liabilities of which we are currently unaware. ETP has agreed to indemnify us for losses or claims relating to the operation of the business or otherwise only to a limited extent and for a limited period of time. There is a risk that we could ultimately be liable for obligations relating to the CDM Acquisition for which indemnification is not available, which could materially adversely affect our business, results of operations and cash flow.

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

Our operations are subject to inherent risks such as equipment defects, malfunctions and failures, and natural disasters that can result in uncontrollable flows of gas or well fluids, fires and explosions. These risks could expose us to substantial liability for personal injury, death, property damage, pollution and other environmental damages. Our insurance may be inadequate to cover our liabilities. Further, insurance covering the risks we face or in the amounts we desire may not be available in the future or, if available, the premiums may not be commercially justifiable. If we were to incur substantial liability and such damages were not covered by insurance or were in excess of policy limits, or if we were to incur liability at a time when we are not able to obtain liability insurance, our business, results of operations and financial condition could be adversely affected.

Cybersecurity breaches and other disruptions of our information systems could compromise our information and operations and expose us to liability, which would cause our business and reputation to suffer.

We rely on our information technology infrastructure to process, transmit and store electronic information critical to our business activities. In recent years, there has been a rise in the number of cyberattacks on other companies’ network and information systems by both state-sponsored and criminal organizations, and as a result, the risks associated with such an event continue to increase. A significant failure, compromise, breach or interruption of our information systems could result in a disruption of our operations, customer dissatisfaction, damage to our reputation, a loss of customers or revenues and potential regulatory fines. If any such failure, interruption or similar event results in improper disclosure of information maintained in our information systems and networks or those of our customers, suppliers or vendors, including personnel, customer, pricing and other sensitive information, we could also be subject to liability under relevant contractual obligations and laws and regulations protecting personal data and privacy. Our financial results could also be adversely affected if our information systems are breached or an employee causes our information systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating such systems.

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

The long-term impact of terrorist attacks and the magnitude of the threat of future terrorist attacks on the energy industry in general and on us in particular are not known at this time. Uncertainty surrounding sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil and natural gas supplies and markets for crude oil, natural gas and natural gas liquids and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurance markets attributable to terrorist attacks may make insurance against such attacks more difficult for us to obtain, if we choose to do so. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets resulting from terrorism or war could also negatively affect our ability to raise capital.

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

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. Although we continuously evaluate the effectiveness of and improve upon our internal controls, our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes Oxley Act of 2002 (“Section 404”). For example, Section 404 requires us to, among other things, review and report annually on the effectiveness of our internal control over financial reporting. In addition, our independent registered public accountants are now required to assess the effectiveness of our internal control over financial reporting since we ceased to be an emerging growth company under the Jumpstart Our Business Startups Act (the “JOBS Act”) on December 31, 2018, which means that we will no longer benefit from the reduced reporting requirements afforded to emerging growth companies under the JOBS Act.

Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our independent registered public accounting firm’s conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls will subject us to regulatory scrutiny and may result in a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

Risks Inherent in an Investment in Us

Holders of our common units have limited voting rights and are not entitled to elect the General Partner or its directors.

Unlike the holders of common stock in a corporation, our common unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Common unitholders have no right to elect the General Partner or the board of directors of the General Partner (the “Board”). ETO is the sole member of the General Partner and has the right to appoint the majority of the members of the Board, including all but one of its independent directors. Also, pursuant to that certain Board Representation Agreement entered into by us, the General Partner, ETE and EIG Veteran Equity Aggregator, L.P. (along with its affiliated funds, “EIG”) in connection with our private placement of Preferred Units and Warrants to EIG, EIG Management Company, LLC has the right to designate one of the members of the Board for so long as the holders of the Preferred Units hold more than 5% of the Partnership’s outstanding common units in the aggregate (taking into account the common units that would be issuable upon conversion of the Preferred Units and exercise of the Warrants).

If our common unitholders are dissatisfied with the General Partner’s performance, they have little ability to remove the General Partner. As a result of these limitations, the price of our common units may decline because of the absence or reduction of a takeover premium in the trading price. Furthermore, the Partnership Agreement contains provisions

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limiting the ability of common unitholders to call meetings or to obtain information about our operations, as well as other provisions limiting our common unitholders’ ability to influence the manner or direction of management.

ETO owns and controls the General Partner, and the General Partner has sole responsibility for conducting our business and managing our operations. The General Partner and its affiliates, including ETO, have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of us and our unitholders.

ETO owns and controls the General Partner and appointed all of the officers and a majority of the directors of the General Partner, some of whom are also officers and directors of ETO. Although the General Partner has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of the General Partner also have a fiduciary duty to manage the General Partner in a manner that is beneficial to its owner. Conflicts of interest will arise between the General Partner and its owner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, the General Partner may favor its own interests and the interests of its owner over our interests and the interests of our unitholders. These conflicts include the following situations, among others:

| · |  | neither the Partnership Agreement nor any other agreement requires ETO to pursue a business strategy that favors us;

| · |  | ETO and its affiliates are not prohibited from engaging in businesses or activities that are in direct competition with us or from offering business opportunities or selling assets to our competitors;

| · |  | the General Partner is allowed to take into account the interests of parties other than us, such as its owner, in resolving conflicts of interest;

| · |  | the Partnership Agreement limits the liability of and reduces the fiduciary duties owed by the General Partner, and also restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty;

| · |  | except in limited circumstances, the General Partner has the power and authority to conduct our business without unitholder approval;

| · |  | the General Partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership interests and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders;

| · |  | the General Partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders;

| · |  | the General Partner determines which costs it incurs are reimbursable by us;

| · |  | the General Partner may cause us to borrow funds in order to permit the payment of cash distributions;

| · |  | the Partnership Agreement permits us to classify up to $36.6 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus;

| · |  | the Partnership Agreement does not restrict the General Partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

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| · |  | the General Partner currently limits, and intends to continue limiting, its liability for our contractual and other obligations;

| · |  | the General Partner may exercise its right to call and purchase all of our common units not owned by it and its affiliates if together those entities at any time own more than 80% of our common units;

| · |  | the General Partner controls the enforcement of the obligations that it and its affiliates owe to us; and

| · |  | the General Partner decides whether to retain separate counsel, accountants or others to perform services for us.

The General Partner’s liability for our obligations is limited.

The General Partner has included, and will continue to include, provisions in its and our contractual arrangements that limit its liability under such contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against the General Partner or its assets. The General Partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to it. The Partnership Agreement provides that any action taken by the General Partner to limit its liability is not a breach of the General Partner’s fiduciary duties, even if we could have obtained more favorable terms without such limitation on liability. In addition, we are obligated to reimburse or indemnify the General Partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce our amount of cash otherwise available for distribution.

The Partnership Agreement limits the General Partner’s fiduciary duties to our unitholders.

The Partnership Agreement contains provisions that modify and reduce the fiduciary standards to which the General Partner would otherwise be held by state fiduciary duty law. For example, the Partnership Agreement permits the General Partner to make a number of decisions in its individual capacity, as opposed to its capacity as the General Partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles the General Partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that the General Partner may make in its individual capacity include:

| · |  | how to allocate business opportunities among us and its affiliates;

| · |  | whether to exercise its limited call right;

| · |  | how to exercise its voting rights with respect to the common units it owns; and

| · |  | whether or not to consent to any merger or consolidation of the Partnership or amendment to the Partnership Agreement.

By purchasing a unit, a unitholder agrees to become bound by the provisions of the Partnership Agreement, including the provisions discussed above.

Even if holders of our common units are dissatisfied, they currently cannot remove the General Partner without ETO’s consent.

Common unitholders are currently unable to remove the General Partner because the General Partner and its affiliates own sufficient number of our common units to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding common units is required to remove the General Partner, and ETO currently owns over 33 1/3% of our outstanding common units.

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The Partnership Agreement restricts the remedies available to holders of our common units for actions taken by the General Partner that might otherwise constitute breaches of fiduciary duty.

The Partnership Agreement contains provisions that restrict the remedies available to common unitholders for actions taken by the General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, the Partnership Agreement:

| · |  | provides that whenever the General Partner makes a determination or takes, or declines to take, any other action in its capacity as the General Partner, the General Partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any higher standard imposed by the Partnership Agreement, Delaware law, or any other law, rule or regulation, or at equity;

| · |  | provides that the General Partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as such decisions are made in good faith, meaning that it believed that the decisions were in the best interest of the Partnership;

| · |  | provides that the General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

| · |  | provides that the General Partner will not be in breach of its obligations under the Partnership Agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:

| (a) |  | approved by the conflicts committee of the Board, although the General Partner is not obligated to seek such approval;

| (b) |  | approved by the vote of a majority of our outstanding common units, excluding any common units owned by the General Partner and its affiliates;

| (c) |  | on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

| (d) |  | fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In a situation involving a transaction with an affiliate or a conflict of interest, any determination by the General Partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the Board determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in subclauses (c) or (d) above, then it will conclusively be deemed that, in making its decision, the Board acted in good faith.

The Partnership Agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Common unitholders’ voting rights are further restricted by a provision of the Partnership Agreement providing that any units held by a person or group that owns 20% or more of such class of units then outstanding, other than, with respect to our common units, the General Partner, its affiliates, their direct transferees and their indirect transferees approved by the General Partner (which approval may be granted in its sole discretion) and persons who acquired such common units with the prior approval of the General Partner, cannot vote on any matter.

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The general partner interest or the control of the General Partner may be transferred to a third party without unitholder consent.

The General Partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the common unitholders. Furthermore, the Partnership Agreement does not restrict the ability of ETO to transfer all or a portion of its ownership interest in the General Partner to a third party. The new owner of the General Partner would then be in a position to replace the majority of the Board, and all of the officers, of the General Partner with its own designees and thereby exert significant control over the decisions made by the Board and the officers of the General Partner.

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

The market price of master limited partnership units, like other yield-oriented securities, may be affected by, among other factors, implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, increases or decreases in interest rates may affect whether or not certain investors decide to invest in master limited partnership units, including ours, and a rising interest rate environment could have an adverse impact on our common unit price and impair our ability to issue additional equity or incur debt to fund growth or for other purposes, including distributions.

We may issue additional limited partner interests without the approval of the common unitholders, which would dilute the common unitholders’ existing ownership interests and may increase the risk that we will not have sufficient available cash to maintain or increase our per common unit distribution level.

The Partnership Agreement does not limit the number or timing of additional limited partner interests that we may issue, including limited partner interests that are convertible into our common units, without the approval of our common unitholders. Also, for the first four full calendar quarters following the Transactions Date, we are permitted to pay a portion of the quarterly distribution on the Preferred Units with additional Preferred Units, and the Preferred Units are convertible into common units in the future at the option of the holders of the Preferred Units, or under certain circumstances, at our option.

If a substantial portion of the Preferred Units are converted into common units, common unitholders could experience significant dilution. Furthermore, if holders of such converted Preferred Units were to dispose of a substantial portion of these common units in the public market, whether in a single transaction or series of transactions, it could adversely affect the market price of our common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future.

Our issuance of additional common units, including pursuant to our Distribution Reinvestment Plan (“DRIP”), or other equity securities of equal or senior rank, such as additional preferred units, will have the following effects:

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

| · |  | our amount of cash available for distribution to common unitholders may decrease;

| · |  | our ratio of taxable income to distributions may increase;

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

| · |  | the market price of our common units may decline.

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ETO and the holders of the Preferred Units may sell our common units in the public or private markets, and such sales could have an adverse impact on the trading price of our common units.

As of December 31, 2018, ETO holds an aggregate of 46,056,228 common units in us (after giving effect to the conversion of 6,397,965 Class B Units to common units). We have granted certain registration rights to ETO and its affiliates with respect to any common units they own, and have filed a registration statement with the SEC for the benefit of the holders of the Preferred Units with respect to any common units they may own upon conversion of the Preferred Units or exercise of the Warrants. The sale of these common units in the public or private markets could have an adverse impact on the price of our common units or on any trading market that may develop.

The General Partner has a call right that may require you to sell your common units at an undesirable time or price.

If at any time the General Partner and its affiliates own more than 80% of our outstanding common units, the General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of our common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of the Partnership Agreement. As a result, you may be required to sell your common units at an undesirable time or price. You may also incur a tax liability upon a sale of your common units. ETO currently owns an aggregate of approximately 44% of our outstanding common units (before giving effect to the conversion of the Class B Units into common units).

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

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. The Partnership is organized under Delaware law and conducts business in a number of other states, and in some of those states, the limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established. You could be liable for any and all of our obligations as if you were a general partner if a court or governmental 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 the General Partner, to approve some amendments to the Partnership Agreement or to take other actions under the Partnership Agreement constitute “control” of our business.

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

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. The Delaware Act provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their interest in the Partnership and liabilities that are nonrecourse to the Partnership are not counted for purposes of determining whether a distribution is permissible.

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

Our common units are listed on the NYSE. Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on the Board or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to investors in certain corporations that are subject to all of the NYSE corporate governance requirements. Please read Part III, Item 10 (“Directors, Executive Officers and Corporate Governance”).

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Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, then our cash available for distribution would be substantially reduced.

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

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

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

The Partnership Agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity level taxation for federal, state or local income tax purposes, the level of distributions on our common units may be adjusted to reflect the impact of that law or interpretation on us.

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

Changes in current state law may subject us to additional entity level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay the 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 cash available 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 potential legislative, 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 common units, may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of the U.S. Congress have proposed and considered substantive changes to the existing federal income tax laws that would affect publicly traded partnerships, including a prior legislative proposal that would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. Although there are no such current legislative or administrative proposals, there can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a publicly traded partnership in the future.

Any modification to the federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal

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income tax purposes. We are unable to predict whether any changes or other proposals will ultimately be enacted. Any future legislative changes could negatively impact the value of an investment in our common units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals 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 receive any cash distributions from us.

Because a unitholder will be treated as a partner to whom we will allocate taxable income that could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

We may engage in transactions to de-lever the Partnership and manage our liquidity that may result in income and gain to our unitholders. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale. Further, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” (also referred to as “COD income”) being allocated to our unitholders as taxable income. Unitholders may be allocated COD income, and income tax liabilities arising therefrom may exceed cash distributions. The ultimate effect of any such allocations will depend on the unitholder’s individual tax position with respect to its units. Unitholders are encouraged to consult their tax advisors with respect to the consequences of potential COD income or other transactions that may 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 impacted and 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 tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained.

It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court 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, our costs of any contest with the IRS will be borne indirectly by our unitholders and the General Partner because the costs will reduce 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 some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. To the extent possible under the new rules, the General Partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although the General Partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes,

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penalties and interest, our cash available for distribution to our unitholders might be reduced. These rules are not applicable for 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 the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.

A substantial portion of the amount realized from a unitholder’s sale of our units, whether or not representing gain, may be taxed as ordinary income to such unitholder due to potential recapture items, including depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than such unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells its units, such unitholder may recognize ordinary income from our allocations of income and gain to such unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.

Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business 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 “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction 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 to them.

Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. With respect to taxable years beginning after December 31, 2017, subject to the proposed aggregation rules for certain similarly situated businesses or activities issued by the Treasury Department, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our common units.

Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S.

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trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income 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 to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interests in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges. It is not clear if or when such regulations or other guidance will be issued. Non-U.S. unitholders should consult a tax advisor before investing in our common units.

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

Because we cannot match transferors and transferees of common units, we have adopted certain methods for allocating depreciation and amortization deductions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to the use of these methods could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

We generally prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We generally prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate (i) certain deductions for depreciation of capital additions, (ii) gain or loss realized on a sale or other disposition of our assets, and (iii) in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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

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

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

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

A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income 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 our unitholders’ 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 return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with state and local filing requirements.

We currently conduct business and control assets 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 our business, we may control assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax. It is your responsibility to file all foreign, federal, state and local tax returns and pay any taxes due in these jurisdictions. Unitholders should consult with their own tax advisors regarding the filing of such tax returns, the payment of such taxes, and the deductibility of any taxes paid.

ITEM 1B.Unresolved Staff Comments

None.

ITEM 2.Properties

We do not currently own or lease any material facilities or properties for storage or maintenance of our compression units. As of December 31, 2018, our headquarters consisted of 12,342 square feet of leased space located at 100 Congress Avenue, Austin, Texas 78701.

ITEM 3.Legal Proceedings

From time to time, we and our subsidiaries may be involved in various claims and litigation arising in the ordinary course of business. In management’s opinion, the resolution of such matters is not expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

ITEM 4.Mine Safety Disclosures

None.

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PART II

ITEM 5.Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our Partnership Interests

As of February 14, 2019, we had 90,000,504 common units outstanding. ETO owns 100% of the membership interests in the General Partner. As of February 14, 2019, ETO owned approximately 44% of our outstanding common units (before giving effect to the conversion of the Class B Units into common units).

As of February 14, 2019, we had outstanding 6,397,965 Class B Units which represent limited partner interests in the Partnership, all of which were held by ETO. Each Class B Unit will automatically be converted into one common unit following the record date attributable to the quarter ending June 30, 2019. Each Class B Unit has all of the rights and obligations of a common unit except the right to participate in distributions made prior to conversion into common units.

As of February 14, 2019, we had outstanding 500,000 Preferred Units representing limited partner interests in the Partnership, all of which were held by certain investment funds managed or advised by EIG Global Energy Partners and FS Energy and Power Fund (collectively, the “Preferred Unitholders”). The Preferred Units rank senior to the common units with respect to distributions and rights upon liquidation. The Preferred Unitholders are entitled to receive cumulative quarterly distributions equal to $24.375 per Preferred Unit, which may be paid in cash or, subject to certain limits, a combination of cash and additional Preferred Units as determined by the General Partner with respect to any quarter ending on or prior to June 30, 2019.

The Preferred Units are convertible, at the option of the Preferred Unitholders, into common units as follows: one third on or after April 2, 2021, two thirds on or after April 2, 2022, and the remainder on or after April 2, 2023. On or after April 2, 2023, we have the option to redeem all or any portion of the Preferred Units then outstanding. On or after April 2, 2028, the Preferred Unitholders have the right to require us to redeem all or a portion of the Preferred Units then outstanding, the purchase price for which we may elect to pay up to 50% in common units, subject to certain additional limits.

Our common units, which represent limited partner interests in us, are listed on the New York Stock Exchange (“NYSE”) under the symbol “USAC.”

Holders

At the close of business on February 14, 2019, based on information received from the transfer agent of the common units, we had 58 holders of record of our common units. The number of record holders does not include holders of common units held in “street name” or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories. There is no established public trading market for the Preferred Units, all of which are owned by the Preferred Unitholders. Please read Part II, Item 8 (“Financial Statements and Supplementary Data—Note 11—Preferred Units and Warrants and –Note 12—Partners’ Capital”).

Selected Information from the Partnership Agreement

Set forth below is a summary of the significant provisions of the Partnership Agreement that relate to available cash.

Available Cash

The Partnership Agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date, first to the holders of the Preferred Units and then to the common unitholders. The Partnership Agreement generally defines available cash, for each quarter, as cash on hand at the end of a quarter plus cash on hand resulting from working capital borrowings made after the end of the quarter less the amount of reserves established by the General Partner to provide for the proper conduct of our business, comply with

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applicable law, the Credit Agreement or other agreements; and provide funds for distributions to our unitholders for any one or more of the next four quarters. Working capital borrowings are borrowings made under a credit facility, commercial paper facility or other similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months from sources other than working capital borrowings.

Issuer Purchases of Equity Securities

None.

Sales of Unregistered Securities; Use of Proceeds from Sale of Securities

None.

Equity Compensation Plan

For disclosures regarding securities authorized for issuance under equity compensation plans, see Part III, Item 12 (“Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters”).

ITEM 6.Selected Financial Data

SELECTED HISTORICAL FINANCIAL DATA

In the table below we have presented certain selected financial data for USA Compression Partners, LP and the USA Compression Predecessor for each of the years in the five-year period ended December 31, 2018, which has been derived from our audited consolidated financial statements for the years ended December 31, 2018, 2017, 2016 and 2015. The financial data for the year ended December 31, 2014 is unaudited. For periods prior to the Transactions Date, the table presents selected financial data for the USA Compression Predecessor and periods after the Transactions Date refer to the Partnership. The following information should be read together with Management’s Discussion and Analysis of Financial Condition 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 data included herein not to be indicative of our future financial condition or results of operations. A discussion of our critical accounting estimates and how these estimates could impact our future financial condition and results of operations is included in “Management's Discussion and Analysis of Financial Condition and Results of Operations” contained in Part II, Item 7 of this report. In addition, a discussion of the risk factors that could affect our business and future financial condition and results of operations is included under Part I, Item 1A (“Risk Factors”) of this report. Additionally, Note 2 – Basis of Presentation and Significant Accounting Policies and Note 17 – Commitments and Contingencies under Part II, Item 8 (“Financial Statements and Supplementary Data”) of this report provide descriptions of areas where estimates and judgments and contingent liabilities could result in different amounts being recognized in our accompanying consolidated financial statements.

We believe that investors benefit from having access to the same financial measures utilized by management. The following table includes the non-GAAP financial measures of gross operating margin, Adjusted EBITDA and Distributable Cash Flow (or “DCF”). For definitions of gross operating margin, Adjusted EBITDA and DCF, and reconciliations of such measures to their most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Non-GAAP Financial Measures” below.

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|  | Year Ended December 31, |
|  | 2018 |  | 2017 |  | 2016 |  | 2015 |  | 2014 |
|  | (in thousands, except per unit amounts) |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Contract operations |  | $ | 546,896 |  | $ | 249,346 |  | $ | 239,143 |  | $ | 281,589 |  | $ | 243,371 |
Parts and service |  |  | 20,402 |  |  | 10,085 |  |  | 7,921 |  |  | 27,686 |  |  | 56,108 |
Related party |  |  | 17,054 |  |  | 17,240 |  |  | 16,873 |  |  | 15,200 |  |  | 20,688 |
Total revenues |  |  | 584,352 |  |  | 276,671 |  |  | 263,937 |  |  | 324,475 |  |  | 320,167 |
Costs of operations: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Costs of operations, exclusive of depreciation and amortization |  |  | 214,724 |  |  | 125,204 |  |  | 112,898 |  |  | 139,301 |  |  | 154,448 |
Gross operating margin (1) |  |  | 369,628 |  |  | 151,467 |  |  | 151,039 |  |  | 185,174 |  |  | 165,719 |
Other operating and administrative costs and expenses: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Selling, general and administrative |  |  | 68,995 |  |  | 24,944 |  |  | 22,739 |  |  | 33,961 |  |  | 23,339 |
Depreciation and amortization |  |  | 213,692 |  |  | 166,558 |  |  | 155,134 |  |  | 148,930 |  |  | 134,477 |
Loss (gain) on disposition of assets |  |  | 12,964 |  |  | (367) |  |  | 120 |  |  | (603) |  |  | 986 |
Impairment of compression equipment |  |  | 8,666 |  |  | — |  |  | — |  |  | — |  |  | — |
Impairment of goodwill |  |  | — |  |  | 223,000 |  |  | — |  |  | — |  |  | — |
Total other operating and administrative costs and expenses |  |  | 304,317 |  |  | 414,135 |  |  | 177,993 |  |  | 182,288 |  |  | 158,802 |
Operating income (loss) |  |  | 65,311 |  |  | (262,668) |  |  | (26,954) |  |  | 2,886 |  |  | 6,917 |
Other income (expense): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest expense, net |  |  | (78,377) |  |  | — |  |  | — |  |  | — |  |  | — |
Other |  |  | 41 |  |  | (223) |  |  | (153) |  |  | (140) |  |  | (114) |
Total other expense |  |  | (78,336) |  |  | (223) |  |  | (153) |  |  | (140) |  |  | (114) |
Net income (loss) before income tax expense (benefit) |  |  | (13,025) |  |  | (262,891) |  |  | (27,107) |  |  | 2,746 |  |  | 6,803 |
Income tax expense (benefit) |  |  | (2,474) |  |  | 1,843 |  |  | (163) |  |  | (1,445) |  |  | 1,678 |
Net income (loss) |  | $ | (10,551) |  | $ | (264,734) |  | $ | (26,944) |  | $ | 4,191 |  | $ | 5,125 |
Adjusted EBITDA (1) |  | $ | 320,475 |  | $ | 130,348 |  | $ | 131,686 |  | $ | 155,045 |  | $ | 145,168 |
DCF (1) |  | $ | 177,757 |  | $ | 109,326 |  | $ | 123,442 |  | $ | 147,192 |  | $ | 136,774 |
Basic and diluted net loss per common unit (2) |  | $ | (0.43) |  |  |  |  |  |  |  |  |  |  |  |  |
Basic and diluted net loss per Class B Unit (2) |  | $ | (2.33) |  |  |  |  |  |  |  |  |  |  |  |  |
Cash distributions declared per common unit (2) |  | $ | 1.575 |  |  |  |  |  |  |  |  |  |  |  |  |
Other Financial Data: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Capital expenditures |  | $ | 241,179 |  | $ | 175,508 |  | $ | 59,234 |  | $ | 249,788 |  | $ | 318,099 |
Cash flows provided by (used in): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating activities |  | $ | 226,340 |  | $ | 135,956 |  | $ | 130,063 |  | $ | 164,324 |  | $ | 141,292 |
Investing activities |  | $ | (779,663) |  | $ | (142,458) |  | $ | (36,767) |  | $ | (249,805) |  | $ | (346,869) |
Financing activities |  | $ | 549,409 |  | $ | (3,666) |  | $ | (90,367) |  | $ | 96,733 |  | $ | 205,577 |
Balance Sheet Data (at period end): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Working capital (3) |  | $ | 68,141 |  | $ | 27,091 |  | $ | 62,424 |  | $ | 55,519 |  | $ | 9,550 |
Total assets |  | $ | 3,774,649 |  | $ | 1,718,953 |  | $ | 1,960,416 |  | $ | 2,102,933 |  | $ | 2,037,977 |
Long-term debt |  | $ | 1,759,058 |  | $ | — |  | $ | — |  | $ | — |  | $ | — |
Partners' capital and predecessor parent company net investment |  | $ | 1,378,856 |  | $ | 1,664,870 |  | $ | 1,929,223 |  | $ | 2,042,996 |  | $ | 1,930,817 |

| (1) |  | Please refer to “—Non-GAAP Financial Measures” below.

| (2) |  | Earnings per unit is not applicable to the USA Compression Predecessor as the USA Compression Predecessor had no outstanding common units prior to the Transactions.

| (3) |  | Working capital is defined as current assets minus current liabilities.

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Non-GAAP Financial Measures

Gross Operating Margin

The table above includes gross operating margin, which is a non-GAAP financial measure, and a reconciliation to operating income (loss), its most directly comparable GAAP financial measure. We define gross operating margin as revenue less cost of operations, exclusive of depreciation and amortization expense. We believe that gross operating margin is useful as a supplemental measure of our operating profitability. Gross operating margin is impacted primarily by the pricing trends for service operations and cost of operations, including labor rates for service technicians, volume and per unit costs for lubricant oils, quantity and pricing of routine preventative maintenance on compression units and property tax rates on compression units. Gross operating margin should not be considered an alternative to, or more meaningful than, operating income (loss) or any other measure of financial performance presented in accordance with GAAP. Moreover, gross operating margin as presented may not be comparable to similarly titled measures of other companies. Because we capitalize assets, depreciation and amortization of equipment is a necessary element of our costs. To compensate for the limitations of gross operating margin as a measure of our performance, we believe that it is important to consider operating income (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 income tax expense (benefit). We define Adjusted EBITDA as EBITDA plus impairment of compression equipment, impairment of goodwill, interest income on capital lease, unit-based compensation expense, severance charges, certain transaction fees, loss (gain) on disposition of assets and other. We view Adjusted EBITDA as one of management’s primary tools for evaluating our results of operations, and we track this item on a monthly basis both as an absolute amount and as a percentage of revenue compared to the prior month, year-to-date, prior year and budget. Adjusted EBITDA is used as a supplemental financial measure by our management and external users of our financial statements, such as investors and commercial banks, to assess:

| · |  | the financial performance of our assets without regard to the impact of financing methods, capital structure or historical cost basis of our assets;

| · |  | the viability of capital expenditure projects and the overall rates of return on alternative investment opportunities;

| · |  | the ability of our assets to generate cash sufficient to make debt payments and to make distributions; and

| · |  | our operating performance as compared to those of other companies in our industry without regard to the impact of financing methods and capital structure.

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

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

Because we use capital assets, depreciation, impairment of compression equipment and the interest cost of acquiring compression equipment are also necessary elements of our costs. Unit-based compensation expense related to 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 is important to consider both net income (loss) and net cash provided by operating activities determined under GAAP, as well as Adjusted EBITDA, to evaluate

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our financial performance and our liquidity. Our Adjusted EBITDA excludes some, but not all, items that affect net income (loss) and net cash provided by operating activities, and these measures may vary among companies. Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the most closely comparable GAAP measures, understanding the differences between the measures and incorporating this knowledge into their decision making processes.

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

|  | Year Ended December 31,
|  | 2018 |  | 2017 |  | 2016 |  | 2015 |  | 2014
Net income (loss) |  | $ | (10,551) |  | $ | (264,734) |  | $ | (26,944) |  | $ | 4,191 |  | $ | 5,125
Interest expense, net |  |  | 78,377 |  |  | — |  |  | — |  |  | — |  |  | —
Depreciation and amortization |  |  | 213,692 |  |  | 166,558 |  |  | 155,134 |  |  | 148,930 |  |  | 134,477
Income tax expense (benefit) |  |  | (2,474) |  |  | 1,843 |  |  | (163) |  |  | (1,445) |  |  | 1,678
EBITDA |  | $ | 279,044 |  | $ | (96,333) |  | $ | 128,027 |  | $ | 151,676 |  | $ | 141,280
Impairment of compression equipment (1) |  |  | 8,666 |  |  | — |  |  | — |  |  | — |  |  | —
Impairment of goodwill (2) |  |  | — |  |  | 223,000 |  |  | — |  |  | — |  |  | —
Interest income on capital lease |  |  | 709 |  |  | — |  |  | — |  |  | — |  |  | —
Unit-based compensation expense (3) |  |  | 11,740 |  |  | 4,048 |  |  | 3,539 |  |  | 3,972 |  |  | 2,902
Transaction expenses for acquisitions (4) |  |  | 4,181 |  |  | — |  |  | — |  |  | — |  |  | —
Severance charges |  |  | 3,171 |  |  | — |  |  | — |  |  | — |  |  | —
Loss (gain) on disposition of assets |  |  | 12,964 |  |  | (367) |  |  | 120 |  |  | (603) |  |  | 986
Adjusted EBITDA |  | $ | 320,475 |  | $ | 130,348 |  | $ | 131,686 |  | $ | 155,045 |  | $ | 145,168
Interest expense, net |  |  | (78,377) |  |  | — |  |  | — |  |  | — |  |  | —
Income tax expense (benefit) |  |  | 2,474 |  |  | (1,843) |  |  | 163 |  |  | 1,445 |  |  | (1,678)
Interest income on capital lease |  |  | (709) |  |  | — |  |  | — |  |  | — |  |  | —
Non-cash interest expense |  |  | 5,080 |  |  | — |  |  | — |  |  | — |  |  | —
Transaction expenses for acquisitions |  |  | (4,181) |  |  | — |  |  | — |  |  | — |  |  | —
Severance charges |  |  | (3,171) |  |  | — |  |  | — |  |  | — |  |  | —
Other |  |  | (2,030) |  |  | 24 |  |  | (748) |  |  | 3,380 |  |  | 2,433
Changes in operating assets and liabilities |  |  | (13,221) |  |  | 7,427 |  |  | (1,038) |  |  | 4,454 |  |  | (4,631)
Net cash provided by operating activities |  | $ | 226,340 |  | $ | 135,956 |  | $ | 130,063 |  | $ | 164,324 |  | $ | 141,292

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

| (2) |  | For further discussion of the goodwill impairment the USA Compression Predecessor recognized for the year ended December 31, 2017, please refer to Item 7 (“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Goodwill Impairment Assessments”).

| (3) |  | For the year ended December 31, 2018, unit-based compensation expense included $1.3 million of cash payments related to quarterly payments of distribution equivalent rights on outstanding phantom unit awards and $3.7 million related to the cash portion of any settlement of phantom unit awards upon vesting. The remainder of the unit-based compensation expense is related to non-cash adjustments to the unit-based compensation liability.

| (4) |  | Represents certain transaction expenses related to potential and completed acquisitions and other items. We believe it is useful to investors to exclude these fees.

Distributable Cash Flow

We define DCF as net income (loss) plus non-cash interest expense, non-cash income tax expense (benefit), depreciation and amortization 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 distributions on Preferred Units and maintenance capital expenditures.

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We believe DCF is an important measure of operating performance because it allows management, investors and others to compare basic cash flows we generate (after distributions on our Preferred Units but prior to any retained cash reserves established by the General Partner and the effect of the DRIP) to the cash distributions we expect to pay our common unitholders. Using DCF, management can quickly compute the coverage 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 as measures of operating performance and liquidity. Moreover, our DCF as presented may not be comparable to similarly titled measures of other companies.

Because we use capital assets, depreciation and impairment of compression equipment, (gain) loss on disposition of assets, and maintenance capital expenditures are necessary elements of our costs. Unit-based compensation expense related to 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 is important to consider both net income (loss) and net cash provided by operating activities determined under GAAP, as well as DCF, to evaluate our financial performance and our liquidity. Our DCF excludes some, but not all, items that affect net income (loss) and net cash provided by operating activities, and these measures may vary among companies. Management compensates for the limitations of DCF as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating this knowledge into their decision making processes.

The following table reconciles DCF to net income (loss) and net cash provided by operating activities, its most directly comparable GAAP financial measures, for each of the periods presented (in thousands):

|  | Year Ended December 31,
|  | 2018 |  | 2017 |  | 2016 |  | 2015 |  | 2014
Net income (loss) |  | $ | (10,551) |  | $ | (264,734) |  | $ | (26,944) |  | $ | 4,191 |  | $ | 5,125
Non-cash interest expense |  |  | 5,080 |  |  | — |  |  | — |  |  | — |  |  | —
Non-cash income tax expense (benefit) |  |  | (2,663) |  |  | 1,801 |  |  | (155) |  |  | (1,461) |  |  | 1,683
Depreciation and amortization |  |  | 213,692 |  |  | 166,558 |  |  | 155,134 |  |  | 148,930 |  |  | 134,477
Unit-based compensation expense (1) |  |  | 11,740 |  |  | 4,048 |  |  | 3,539 |  |  | 3,972 |  |  | 2,902
Impairment of compression equipment (2) |  |  | 8,666 |  |  | — |  |  | — |  |  | — |  |  | —
Impairment of goodwill (3) |  |  | — |  |  | 223,000 |  |  | — |  |  | — |  |  | —
Transaction expenses for acquisitions (4) |  |  | 4,181 |  |  | — |  |  | — |  |  | — |  |  | —
Severance charges |  |  | 3,171 |  |  | — |  |  | — |  |  | — |  |  | —
Proceeds from insurance recovery |  |  | 409 |  |  | — |  |  | — |  |  | — |  |  | —
Loss (gain) on disposition of assets |  |  | 12,964 |  |  | (367) |  |  | 120 |  |  | (603) |  |  | 986
Distributions on Preferred Units |  |  | (36,430) |  |  | — |  |  | — |  |  | — |  |  | —
Maintenance capital expenditures (5) |  |  | (32,502) |  |  | (20,980) |  |  | (8,252) |  |  | (7,837) |  |  | (8,399)
DCF |  | $ | 177,757 |  | $ | 109,326 |  | $ | 123,442 |  | $ | 147,192 |  | $ | 136,774
Maintenance capital expenditures |  |  | 32,502 |  |  | 20,980 |  |  | 8,252 |  |  | 7,837 |  |  | 8,399
Changes in operating assets and liabilities |  |  | (13,221) |  |  | 7,427 |  |  | (1,038) |  |  | 4,454 |  |  | (4,631)
Transaction expenses for acquisitions |  |  | (4,181) |  |  | — |  |  | — |  |  | — |  |  | —
Severance charges |  |  | (3,171) |  |  | — |  |  | — |  |  | — |  |  | —
Distributions on Preferred Units |  |  | 36,430 |  |  | — |  |  | — |  |  | — |  |  | —
Other |  |  | 224 |  |  | (1,777) |  |  | (593) |  |  | 4,841 |  |  | 750
Net cash provided by operating activities |  | $ | 226,340 |  | $ | 135,956 |  | $ | 130,063 |  | $ | 164,324 |  | $ | 141,292

| (1) |  | For the year ended December 31, 2018, unit-based compensation expense includes $1.3 million of cash payments related to quarterly payments of distribution equivalent rights on outstanding phantom unit awards and $3.7 million related to the cash portion of any settlement of phantom unit awards upon vesting. The remainder of the unit-based compensation expense is related to non-cash adjustments to the unit-based compensation liability.

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| (2) |  | Represents non-cash charges incurred to write down long-lived assets with recorded values that are not expected to be recovered through future cash flows.

| (3) |  | For further discussion of the goodwill impairment the USA Compression Predecessor recognized for the year ended December 31, 2017, please refer to Item 7 (“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Goodwill Impairment Assessments”).

| (4) |  | Represents certain transaction expenses related to potential and completed acquisitions and other items. We believe it is useful to investors to exclude these fees.

| (5) |  | Reflects actual maintenance capital expenditures for the period presented. Maintenance capital expenditures are capital expenditures made to maintain the operating capacity of our assets and extend their useful lives, replace partially or fully depreciated assets, or other capital expenditures that are incurred in maintaining our existing business and related operating income.

Coverage Ratios

DCF Coverage Ratio is defined as DCF divided by distributions declared to common unitholders in respect of such period. Cash Coverage Ratio is defined as DCF divided by cash distributions expected to be paid to common 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 operating performance because they allow management, investors and others to gauge our ability to pay cash distributions to common unitholders using the cash flows that we generate. Our DCF Coverage Ratio and Cash Coverage Ratio as presented may not be comparable to similarly titled measures of other companies.

The following table summarizes our coverage ratios for the periods presented (dollars in thousands):

|  | Year Ended December 31,
|  | 2018 (4) |  | 2017 (5) |  | 2016 (5) |  | 2015 (5) |  | 2014 (5)
DCF |  | $ | 177,757 |  | $ | 109,326 |  | $ | 123,442 |  | $ | 147,192 |  | $ | 136,774
Distributions for DCF coverage ratio (1) |  | $ | 141,699 |  |  |  |  |  |  |  |  |  |  |  |
Distributions reinvested in the DRIP (2) |  |  | 688 |  |  |  |  |  |  |  |  |  |  |  |
Distributions for Cash Coverage Ratio (3) |  | $ | 141,011 |  |  |  |  |  |  |  |  |  |  |  |
DCF Coverage Ratio |  |  | 1.25 |  |  |  |  |  |  |  |  |  |  |  |
Cash Coverage Ratio |  |  | 1.26 |  |  |  |  |  |  |  |  |  |  |  |

| (1) |  | Represents distributions to the holders of our common units as of the record date.

| (2) |  | Represents estimated distributions to holders enrolled in the DRIP as of the record date.

| (3) |  | Represents cash distributions declared on our common units not participating in the DRIP.

| (4) |  | Distributions for the year ended December 31, 2018 reflect only three quarters of distributions as the USA Compression Predecessor did not pay distributions prior to the Transactions Date. DCF, however, reflects a full year of DCF. On a pro forma basis, both the DCF Coverage Ratio and Cash Coverage Ratio for the year ended December 31, 2018 was 1.10x when using comparable three quarters of DCF and three quarters of distributions.

| (5) |  | DCF Coverage Ratio and Cash Coverage Ratio are not applicable to the USA Compression Predecessor as the USA Compression Predecessor had no outstanding common units for each period.

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ITEM 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations

Following the transactions described in further detail below, CDM Resource Management LLC and CDM Environmental & Technical Services LLC, which together represent the CDM Compression Business (the “USA Compression Predecessor”), has been determined to be the historical predecessor of USA Compression Partners, LP (the “Partnership”) for financial reporting purposes. The USA Compression Predecessor is considered the predecessor of the Partnership because Energy Transfer Equity, L.P. (“ETE”), through its wholly owned subsidiary Energy Transfer Partners, L.L.C., controlled the USA Compression Predecessor prior to the transactions described below and obtained control of the Partnership through its acquisition of USA Compression GP, LLC, the general partner of the Partnership (the “General Partner”).

The closing of the Transactions occurred on April 2, 2018 (the “Transactions Date”) and has been reflected in the consolidated financial statements of the Partnership.

In October 2018, ETE and Energy Transfer Partners, L.P. (“ETP”) completed the merger of ETP with a wholly owned subsidiary of ETE in a unit-for-unit exchange (the “ETE Merger”). Following the closing of the ETE Merger, ETE changed its name to “Energy Transfer LP” and ETP changed its name to “Energy Transfer Operating, L.P.” (“ETO”). Upon the closing of the ETE Merger, ETE contributed to ETP 100% of the limited liability company interests in the General Partner. References herein to “ETP” refer to Energy Transfer Partners, L.P. for periods prior to the ETE Merger and ETO following the ETE Merger, and references to “ETE” refer to Energy Transfer Equity, L.P. for periods prior to the ETE Merger and Energy Transfer LP following the ETE Merger.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements, the notes thereto, and the other financial information appearing elsewhere in this report. The following discussion includes forward-looking statements that involve certain risks and uncertainties. See Part I (“Disclosure Regarding Forward-Looking Statements”) and Part I, Item 1A (“Risk Factors”). All references in this section to the USA Compression Predecessor, as well as the terms “our,” “we,” “us” and “its” refer to the USA Compression Predecessor when used in a historical context or in reference to the periods prior to the Transactions Date, unless the context otherwise requires or where otherwise indicated. All references in this section to the Partnership, as well as the terms “our,” “we,” “us” and “its” refer to USA Compression Partners, LP, together with its consolidated subsidiaries, including the USA Compression Predecessor, when used in the present or future tense and for periods subsequent to the Transactions Date, unless the context otherwise requires or where otherwise indicated.

Overview

We provide compression services in a number of shale plays throughout the U.S., including the Utica, Marcellus, Permian Basin, Delaware Basin, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, Haynesville, Niobrara and Fayetteville shales. 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 in 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 to the comparatively attractive economic returns versus returns achieved in many conventional basins. Furthermore, the changes in production volumes and pressures of shale plays over time require a wider range of compression services than in conventional basins. We believe we are well-positioned to meet these changing operating conditions due to the flexibility of our 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 compression units, typically in shale plays, we also provide compression services in more mature conventional basins, including gas lift applications on crude oil wells targeted by horizontal drilling techniques. Gas lift, a process by which natural gas is injected into the production tubing of an existing producing well, in order to reduce the hydrostatic pressure and allow the oil to flow at a higher rate, and other artificial lift technologies are critical to the enhancement of oil production from horizontal wells operating in tight shale plays.

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CDM Acquisition and Issuance of Class B Units

On the Transactions Date, we consummated the transactions contemplated by the Contribution Agreement dated January 15, 2018, pursuant to which, among other things, we acquired all of the issued and outstanding membership interests of the USA Compression Predecessor from ETP (the “CDM Acquisition”) in exchange for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 common units representing limited partner interests in us (ii) 6,397,965 Class B units representing limited partner interests in us (“Class B Units”) and (iii) $1.2 billion in cash (including customary closing adjustments).

General Partner Purchase Agreement

On the Transactions Date and in connection with the closing of the CDM Acquisition, we consummated the transactions contemplated by the Purchase Agreement dated January 15, 2018, by and among ETE, ETP LLC, USA Compression Holdings, LLC (“USA Compression Holdings”) and, solely for certain purposes therein, R/C IV USACP Holdings, L.P. and ETP, pursuant to which, among other things, ETE acquired from USA Compression Holdings (i) all of the outstanding limited liability company interests in the General Partner and (ii) 12,466,912 common units for cash consideration paid by ETE to USA Compression Holdings equal to $250.0 million (the “GP Purchase”). Upon the closing of the ETE Merger, ETE contributed all of the interests in the General Partner and the 12,466,912 common units to ETP.

Equity Restructuring Agreement

On the Transactions Date and in connection with the closing of the CDM Acquisition, we consummated the transactions contemplated by the Equity Restructuring Agreement dated January 15, 2018, pursuant to which, among other things, the Partnership, the General Partner and ETE agreed to cancel the Partnership’s Incentive Distribution Rights (“IDRs”) and convert the General Partner Interest (as defined in the Equity Restructuring Agreement) into a non-economic general partner interest, in exchange for the Partnership’s issuance of 8,000,000 common units to the General Partner (the “Equity Restructuring”).

The CDM Acquisition, GP Purchase and Equity Restructuring are collectively referred to as the “Transactions.”

Series A Preferred Unit and Warrant Private Placement

On the Transactions Date, we completed a private placement of $500 million in the aggregate of (i) newly authorized and established Preferred Units and (ii) warrants to purchase common units (the “Warrants”) pursuant to a Series A Preferred Unit and Warrant Purchase Agreement dated January 15, 2018, between the Partnership and certain investment funds managed or advised by EIG Global Energy Partners and FS Energy and Power Fund (collectively, the “Preferred Unitholders”). We issued 500,000 Preferred Units with a face value of $1,000 per Preferred Unit and issued two tranches of Warrants to the Preferred Unitholders, which included Warrants to purchase 5,000,000 common units with a strike price of $17.03 per unit and 10,000,000 common units with a strike price of $19.59 per unit. The Warrants may be exercised by the holders thereof at any time beginning April 2, 2019 and before April 2, 2028.

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Senior Notes Issuance

On March 23, 2018, the Partnership and its wholly-owned subsidiary, USA Compression Finance Corp. (“Finance Corp”), co-issued $725.0 million in aggregate principal amount of the Senior Notes that mature on April 1, 2026. The Senior Notes accrue interest at the rate of 6.875% per year. Interest on the Senior Notes is payable semi-annually in arrears on April 1 and October 1, with the first such payment having occurred on October 1, 2018.

On January 14, 2019, the Partnership completed an exchange offer whereby holders of the Senior Notes exchanged all of the Senior Notes for an equivalent amount of senior notes registered under the Securities Act of 1933 (the “Exchange Notes”). The Exchange Notes are substantially identical to the Senior Notes, except that the Exchange Notes have been registered with the SEC and do not contain the transfer restrictions, restrictive legends, registration rights or additional interest provisions of the Senior Notes.

Credit Agreement Amendment and Restatement

On the Transactions Date, we entered into the Sixth Amended and Restated Credit Agreement (the “Credit Agreement”) by and among the Partnership, as borrower, USAC OpCo 2, LLC, USAC Leasing 2, LLC, USA Compression Partners, LLC, USAC Leasing, LLC, CDM Resource, CDM E&T and Finance Corp, the lenders party thereto from time to time, JPMorgan Chase Bank, N.A., as agent and a letter of credit (“LC”) issuer, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Regions Capital Markets, a division of Regions Bank, RBC Capital Markets and Wells Fargo Bank, N.A., as joint lead arrangers and joint book runners, Barclays Bank PLC, Regions Bank, RBC Capital Markets and Wells Fargo Bank, N.A., as syndication agents, and MUFG Union Bank, N.A., SunTrust Bank and The Bank of Nova Scotia, as senior managing agents. The Credit Agreement amended and restated that certain Fifth Amended and Restated Credit Agreement, dated as of December 13, 2013, as amended (the “Fifth A&R Credit Agreement”).

The Credit Agreement amended the Fifth A&R Credit Agreement to, among other things, (i) increase the borrowing capacity under the Credit Agreement from $1.1 billion to $1.6 billion (subject to availability under a borrowing base), (ii) extend the termination date (and the maturity date of the obligations thereunder) from January 6, 2020 to April 2, 2023, (iii) subject to the terms of the Credit Agreement, permit up to $400.0 million of future increases in borrowing capacity, (iv) modify the leverage ratio covenant to be 5.75 to 1.0 through the end of the fiscal quarter ending March 31, 2019, 5.5 to 1.0 through the end of the fiscal quarter ending December 31, 2019, and 5.0 to 1.0 thereafter and (v) increase the applicable margin for eurodollar borrowings to range from 2.00% to 2.75%, depending on our leverage ratio, all as more fully set forth in the Credit Agreement.

General Trends and Outlook

Natural gas compression is a critical part of the natural gas value chain, facilitating the movement of natural gas throughout the domestic pipeline system. Our business is driven in part by the increasing volumes of natural gas being produced in this country and the areas and conditions in which it is produced. Without compression, natural gas will generally not move through a pipeline.

A significant amount of our assets are utilized in natural gas infrastructure applications, primarily in centralized natural gas gathering systems and processing facilities. Rather than being more closely tied to the wellhead impact of commodity price variability, these applications generally tend to be characterized by a long-term investment horizon on the part of our customers; as such, we have generally experienced stability in rates and higher sustained utilization rates relative to other businesses more tied to drilling activity and wellhead economics. In addition to assets utilized in infrastructure applications, a small portion of our fleet is used for gas lift applications in connection with crude oil production using horizontal drilling techniques.

Increasing levels of domestic natural gas production as a general rule require more installed compression in order to move the gas through the pipeline system and to the ultimate end user, whether that user be commercial, industrial or residential in nature. The U.S. Energy Information Administration January 2019 Short-Term Energy Outlook (“EIA Outlook”) expects dry natural gas production to increase to 90.2 billion cubic feet per day (“Bcf/d”) in 2019 (an increase

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of 8% over the record high production of 83.3 Bcf/d in 2018) and to 92.2 Bcf/d in 2020. The expected growth in natural gas production is largely in response to improved drilling efficiency and cost reductions, higher associated gas production from oil-directed rigs, and increased takeaway pipeline capacity from the highly productive Appalachia and Permian production regions, which are regions in which we provide compression services. Forecasted natural gas production growth is supported by planned expansions in liquefied natural gas (“LNG”) capacity and increased pipeline exports to Mexico. The EIA Outlook projects LNG gross exports will increase from 3.0 Bcf/d in 2018 to 5.1 Bcf/d in 2019 and to 6.8 Bcf/d in 2020, as three new liquefaction projects come online. Also from the EIA Outlook, natural gas pipeline exports to Mexico have increased as more infrastructure has been built to transport natural gas both to and within Mexico. U.S. pipeline exports to Mexico through October averaged 4.6 Bcf/d, increasing by 10% in 2018 compared with the same period in 2017. Exports to Mexico should continue to increase as more natural gas-fired power plants come online in Mexico and more pipeline infrastructure within Mexico is built.

We believe this increasing demand for natural gas will also create increasing demand for compression services, for both existing natural gas fields as they age and for the development of new natural gas fields. As such, we expect demand for our compression services to continue to increase throughout 2019 although we cannot predict any possible changes in such demand with reasonable certainty.

Particularly in the Permian and Delaware Basins, natural gas tends to be produced alongside crude oil, and is thus known as “associated” gas. Due to many factors, the Permian and Delaware Basins have experienced significant activity levels in recent years, and along with the production of crude oil, the EIA has reported an 81% increase in associated natural gas produced in those areas since December 2015. Because customers must handle the gas that is produced simultaneously with the oil, compression has been a critical part of the equation for our customers to be able to produce the desired crude oil and move it to market. As crude oil production grows in these areas, there will be demand for additional compression to handle the natural gas.

The EIA Outlook forecasts total U.S. crude oil production to average 12.1 million barrels per day (“b/d”) in 2019, up 10% from 2018 average production of 10.9 million b/d, which was the highest annual average on record, surpassing the previous record of 9.6 million b/d set in 1970. Average production in 2020 is expected to increase to 12.9 million b/d. Increased crude oil production from tight rock formations within the Permian region in Texas and New Mexico accounts for 0.6 million b/d of the U.S. total growth expected in 2019 and 0.5 million b/d in 2020. The EIA Outlook expects the Permian region to produce 4.8 million b/d of crude oil by the end of 2020, which is about 1.0 million b/d more than estimated December 2018 levels and would represent about 36% of total U.S. crude oil production at the end of 2020. Favorable geology and technological and operational improvements have allowed the Permian to become one of the most economic regions for oil production. The forecasted annual growth rate in 2019 of 0.6 million b/d is 0.4 million b/d slower than in 2018. The flattening of the growth rate reflects increasing pipeline capacity constraints in the Permian region, which is expected to temporarily lower wellhead prices for the region’s oil producers and to have a dampening effect on the Permian’s full production potential in the short term. Pipeline capacity constraints in the Permian are expected to be alleviated in the second half of 2019, with growth expected to accelerate on a monthly basis into 2020. WTI crude oil spot prices are forecast within the EIA Outlook to average $54 per barrel in 2019 and $60 per barrel in 2020, compared with $65 per barrel in 2018. Daily and monthly average crude oil prices could vary significantly from annual average forecasts due to global economic developments and geopolitical events in the coming months that could have the potential to push oil prices higher or lower than forecast. Uncertainty remains regarding the duration of, and members’ adherence to, the current Organization of the Petroleum Exporting Countries (“OPEC”) production cuts, which could influence prices in either direction.

We believe the increase and relative stabilization of crude oil prices allowed for the continued build-out of related large-scale natural gas infrastructure projects, particularly in areas with favorable economics. These projects increased demand for our compression services throughout 2018 as we saw horsepower utilization increase from 87.5% at December 31, 2017 for the USA Compression Predecessor, to 94.0% at December 31, 2018 for our combined business.

We intend to prudently deploy capital for new compressor units in 2019. We have already entered into commitments to purchase all of our large horsepower compressor units in 2019, as the lead time to build these units is approximately one year or shorter. Most of our 2019 purchases of large horsepower compressor units are already committed to customers or under contract with customers due to the high demand and limited supply of these units.

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Factors Affecting the Comparability of our Operating Results

As described above, the USA Compression Predecessor has been deemed to be the accounting acquirer of the Partnership in accordance with applicable business combination accounting guidance, and, as a result, the historical financial statements reflect the balance sheet and results of operations of the USA Compression Predecessor for periods prior to the Transactions Date. Therefore, the Partnership’s future results of operations may not be comparable to the USA Compression Predecessor’s historical results of operations for the reasons described below.

The revenues generated by the Partnership will consist of the revenues from compression services as well as related ancillary revenues, including those generated by the USA Compression Predecessor, subsequent to the Transactions Date. The historical revenues included within the Partnership’s financial statements relating to periods prior to the Transactions Date will only be comprised of those of the USA Compression Predecessor.

Additionally, selling, general and administrative expenses will not be comparable to the selling, general and administrative expenses previously allocated to the USA Compression Predecessor by ETP. The Partnership’s selling, general and administrative expenses will also not be comparable to the historical USA Compression Predecessor’s selling, general and administrative expenses because the Partnership’s selling, general and administrative expenses will include the expenses associated with being a publicly traded master limited partnership whereas the USA Compression Predecessor was operated as a component of a larger company.

In connection with the Transactions, the Partnership and Finance Corp co-issued the Senior Notes and the Partnership entered into the Credit Agreement. The USA Compression Predecessor held no long-term debt and had no outstanding publicly traded equity securities. As a result, the Partnership’s long-term debt and related charges will not be comparable to the USA Compression Predecessor’s historical long-term debt and related charges. We expect ongoing sources of liquidity to include cash generated from operating activities, borrowings under the Credit Agreement, and additional issuances of debt and equity securities.

During the year ended December 31, 2018, we recorded $4.2 million in transaction expenses, $3.2 million in severance expenses and $6.8 million in unit-based compensation expense, all of which related to the CDM Acquisition.

Operating Highlights

The following table summarizes certain horsepower and horsepower utilization percentages for the periods presented and excludes certain gas treating assets for which horsepower is not a relevant metric.

|  | Year Ended December 31, |  | Percent Change |
Operating Data: |  | 2018 |  | 2017 (9) |  | 2016 (9) |  | 2018 |  | 2017 |
Fleet horsepower (at period end) (1) |  |  | 3,597,097 |  |  | 1,730,820 |  |  | 1,600,842 |  | 107.8 | % | 8.1 | %
Total available horsepower (at period end) (2) |  |  | 3,675,447 |  |  | 1,780,893 |  |  | 1,606,424 |  | 106.4 | % | 10.9 | %
Revenue generating horsepower (at period end) (3) |  |  | 3,262,470 |  |  | 1,395,328 |  |  | 1,227,899 |  | 133.8 | % | 13.6 | %
Average revenue generating horsepower (4) |  |  | 2,760,029 |  |  | 1,293,864 |  |  | 1,203,487 |  | 113.3 | % | 7.5 | %
Average revenue per revenue generating horsepower per month (5) |  | $ | 16.09 |  | $ | 15.84 |  | $ | 16.58 |  | 1.6 | % | (4.5) | %
Revenue generating compression units (at period end) |  |  | 4,753 |  |  | 2,076 |  |  | 1,789 |  | 128.9 | % | 16.0 | %
Average horsepower per revenue generating compression unit (6) |  |  | 674 |  |  | 681 |  |  | 668 |  | (1.0) | % | 1.9 | %
Horsepower utilization (7): |  |  |  |  |  |  |  |  |  |  |  |  |  |
At period end |  |  | 94.0 | % |  | 87.5 | % |  | 77.7 | % | 7.4 | % | 12.6 | %
Average for the period (8) |  |  | 91.9 | % |  | 82.4 | % |  | 77.0 | % | 11.5 | % | 7.0 | %

| (1) |  | Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order). As of December 31, 2018, we had 131,750 horsepower on order for delivery during 2019.

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

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

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

| (5) |  | Calculated as the average of the result of dividing the contractual monthly rate for all units at the end of each month in the period by the sum 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 the months 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 contract, but is not yet generating revenue and (c) horsepower not yet in our fleet that is under contract, not yet generating revenue and that is subject to a purchase order, divided by (ii) total available horsepower less idle horsepower that is under repair. Horsepower utilization based on revenue generating horsepower and fleet horsepower was 90.7%, 80.6% and 76.7% at December 31, 2018, 2017 and 2016, 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. Average horsepower utilization based on revenue generating horsepower and fleet horsepower was 88.0%, 76.9% and 75.9% for the years ended December 31, 2018, 2017 and 2016, respectively.

| (9) |  | Certain historical metrics attributable to the USA Compression Predecessor have been conformed to the Partnership’s calculation methodology.

The 107.8% increase in fleet horsepower as of December 31, 2018 over the fleet horsepower as of December 31, 2017 was attributable to the horsepower acquired from the Partnership’s historical assets as well as compression units added to our fleet to meet incremental demand for our compression services by new and existing customers. The 133.8% increase in revenue generating horsepower as of December 31, 2018 over December 31, 2017 was primarily due to the addition of the Partnership’s historical assets in addition to organic growth in our large horsepower fleet. T he 1.6% increase in average revenue per revenue generating horsepower per month for the year ended December 31, 2018 over December 31, 2017 was primarily due to contracts on new compression units as well as selective price increases on the existing fleet.

The 8.1% increase in fleet horsepower as of December 31, 2017 compared to the fleet horsepower as of December 31, 2016 was attributable to new compression units added to the USA Compression Predecessor’s fleet to meet the then-expected demand by new and existing customers for compression services. The 13.6% increase in revenue generating horsepower as of December 31, 2017 compared to December 31, 2016 was primarily due to increased customer demand in the Permian, Niobrara and Mid-continent Regions. The 1.9% increase in average horsepower per revenue generating compression unit as of December 31, 2017 compared to December 31, 2016 was primarily due to the redeployment of smaller horsepower units that were previously idle. The 4.5% decrease in average revenue per revenue generating horsepower per month for the year ended December 31, 2017 compared to December 31, 2016 was primarily due to an increase in the average horsepower per revenue generating compression unit in the current period, resulting from an increase in the number of large horsepower compression units which typically generate lower average revenue per revenue generating horsepower than do small horsepower compression units.

The 9.5% increase in average horsepower utilization during the year ended December 31, 2018 compared to the year ended December 31, 2017 was primarily attributable to the higher utilization of the Partnership’s historical fleet that was added to the USA Compression Predecessor’s fleet during the year ended December 31, 2018, and resulted in a decrease in total idle horsepower as a percentage of total available horsepower during the year ended December 31, 2018.

The 5.4% increase in average horsepower utilization during the year ended December 31, 2017 compared to the year ended December 31, 2016 was primarily attributable to increased customer demand due to increased operating activity in the oil and gas industry. The fluctuation in utilization components also describes the changes in period end horsepower utilization as of December 31, 2017 compared to December 31, 2016.

The 11.1% increase in average horsepower utilization based on revenue generating horsepower and fleet horsepower during the year ended December 31, 2018 compared to December 31, 2017 was primarily attributable to the higher

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utilization of the Partnership’s fleet that was added to the USA Compression Predecessor’s fleet during the year ended December 31, 2018, and resulted in an increase in total active horsepower as a percentage of total fleet horsepower during the year ended December 31, 2018.

The 1.0% increase in average horsepower utilization based on revenue generating horsepower and fleet horsepower during the year ended December 31, 2017 compared to December 31, 2016 was primarily attributable to increased customer demand in the Permian, Niobrara and Mid-continent Regions. The overall decrease in idle horsepower is the result of increased customer demand as a result of increased operating activity in the oil and gas industry. These factors also describe the variances in period end horsepower utilization based on revenue generating horsepower and fleet horsepower between the year ended December 31, 2017 and the year ended December 31, 2016.

Financial Results of Operations

Year ended December 31, 2018 compared to the year ended December 31, 2017

The following table summarizes our results of operations for the periods presented (dollars in thousands):

|  | Year Ended December 31, |  | Percent |
|  | 2018 |  | 2017 |  | Change |
Revenues: |  |  |  |  |  |  |  |  |  |
Contract operations |  | $ | 546,896 |  | $ | 249,346 |  |  | 119.3 | %
Parts and service |  |  | 20,402 |  |  | 10,085 |  |  | 102.3 | %
Related party |  |  | 17,054 |  |  | 17,240 |  |  | (1.1) | %
Total revenues |  |  | 584,352 |  |  | 276,671 |  |  | 111.2 | %
Costs and expenses: |  |  |  |  |  |  |  |  |  |
Cost of operations, exclusive of depreciation and amortization |  |  | 214,724 |  |  | 125,204 |  |  | 71.5 | %
Gross operating margin |  |  | 369,628 |  |  | 151,467 |  |  | 144.0 | %
Other operating and administrative costs and expenses: |  |  |  |  |  |  |  |  |  |
Selling, general and administrative |  |  | 68,995 |  |  | 24,944 |  |  | 176.6 | %
Depreciation and amortization |  |  | 213,692 |  |  | 166,558 |  |  | 28.3 | %
Loss (gain) on disposition of assets |  |  | 12,964 |  |  | (367) |  |  | 3,632.4 | %
Impairment of compression equipment |  |  | 8,666 |  |  | — |  |  | * | %
Impairment of goodwill |  |  | — |  |  | 223,000 |  |  | (100.0) | %
Total other operating and administrative costs and expenses |  |  | 304,317 |  |  | 414,135 |  |  | (26.5) | %
Operating income (loss) |  |  | 65,311 |  |  | (262,668) |  |  | (124.9) | %
Other income (expense): |  |  |  |  |  |  |  |  |  |
Interest expense, net |  |  | (78,377) |  |  | — |  |  | * | %
Other |  |  | 41 |  |  | (223) |  |  | (118.4) | %
Total other expense |  |  | (78,336) |  |  | (223) |  |  | * | %
Net loss before income tax expense (benefit) |  |  | (13,025) |  |  | (262,891) |  |  | (95.0) | %
Income tax expense (benefit) |  |  | (2,474) |  |  | 1,843 |  |  | (234.2) | %
Net loss |  | $ | (10,551) |  | $ | (264,734) |  |  | (96.0) | %

* Not meaningful.

Contract operations revenue. During the year ended December 31, 2018, we increased our operational capability and expanded our geographic footprint as a result of the addition of the Partnership’s historical assets and experienced a year-to-year increase in demand for our compression services driven by increased operating activity in the oil and gas industry, resulting in a $297.6 million increase in our contract operations revenue. The Partnership’s historical assets accounted for $252.1 million of contract operations revenue for the year ended December 31, 2018. Average revenue generating horsepower increased 113.3% during the year ended December 31, 2018 over the year ended December 31, 2017 and average revenue per revenue generating horsepower per month increased 1.6% from $15.84 for the year ended December 31, 2017 to $16.09 for the year ended December 31, 2018.

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Parts and service revenue. The $10.3 million increase in parts and service revenue was primarily attributable to an increase in maintenance work performed on units at our customers’ locations that are outside the scope of our core maintenance activities and offered as a courtesy to our customers, and freight and crane charges that are directly reimbursable by customers. Demand for retail parts and services fluctuates from period to period based on the varying needs of our customers.

Related party revenue. Related party revenue was materially consistent between periods. The related parties of the USA Compression Predecessor remain related parties of the Partnership because the USA Compression Predecessor’s ultimate parent company obtained control of the Partnership through its control of the General Partner.

Cost of operations, exclusive of depreciation and amortization. The $89.5 million increase in cost of operations was driven by (1) a $38.2 million increase in direct expenses, such as parts, fluids and freight expenses, (2) an $18.2 million increase in direct labor expenses, (3) a $9.5 million increase in retail parts and service expenses, which have a corresponding increase in parts and service revenue, (4) a $9.4 million increase in property and other taxes, (5) a $5.5 million increase in outside maintenance expenses and (6) a $5.2 million increase in vehicle expenses. The increase in direct parts, fluids, labor, property taxes and vehicle expenses is primarily driven by the increase in average revenue generating horsepower during the current period as a result of the addition of the Partnership’s historical assets. The increase in outside maintenance expenses was due to greater use of third-party labor during 2018. We do not expect to incur significant amounts of outside maintenance expense in future periods.

Gross operating margin. The $218.2 million increase in gross operating margin was primarily due to an increase in revenues, partially offset by an increase in cost of operations, exclusive of depreciation and amortization, during the year ended December 31, 2018 due to the addition of the Partnership’s historical assets.

Selling, general and administrative expense. The $44.1 million increase in selling, general and administrative expense for the year ended December 31, 2018 was primarily attributable to (1) a $19.7 million increase in payroll and benefits expenses, (2) a $7.7 million increase in unit-based compensation expense, (3) a $5.6 million increase in professional fees expenses, (4) $4.2 million of non-recurring advisory, legal and accounting fees, all related to the Transactions, (5) $3.0 million of severance charges, all related to the Transactions, and (6) a $2.4 million increase in bad debt expense, primarily due to a $1.8 million recovery of bad debt expense during the year ended December 31, 2017. Payroll and benefits expenses and professional fees increased due to the addition of the Partnership’s historical assets to the USA Compression Predecessor’s operations. Unit-based compensation expense increased primarily due to the accelerated vesting of certain outstanding phantom units as a result of the change in control associated with the Transactions along with the difference in the number of outstanding unvested phantom units of the USA Compression Predecessor as of December 31, 2017 compared to the Partnership as of December 31, 2018.

Depreciation and amortization expense. The $47.1 million increase in depreciation and amortization expense was primarily a result of $66.2 million in depreciation and amortization expense attributable to the addition of the Partnership’s historical assets, which were adjusted to fair value in connection with the Transactions, offset by a $33.8 million decrease in depreciation expense to conform the useful lives used by the USA Compression Predecessor to those used by the Partnership. The remaining change in depreciation and amortization expense was primarily related to an increase in the USA Compression Predecessor’s gross property and equipment balances during the year ended December 31, 2018 compared to gross balances during the year ended December 31, 2017.

Loss (gain) on disposition of assets. The $13.0 million net loss on disposition of assets during the year ended December 31, 2018 was primarily attributable to disposals of various property and equipment by the USA Compression Predecessor prior to the Transactions Date.

Impairment of compression equipment. The $8.7 million impairment charge during the year ended December 31, 2018 was primarily a result of our evaluation of the future deployment of our idle fleet under then-current market conditions. Our evaluation determined that due to certain performance characteristics of the impaired equipment, such as excessive maintenance costs and the inability of the equipment to meet then-current emissions standards without excessive retrofitting costs, this equipment was unlikely to be accepted by customers under then-current market conditions. As a result of our evaluation during the year ended December 31, 2018, we determined to retire and re-utilize

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the key components of 103 compression units, with a total of approximately 33,000 horsepower that had been previously used to provide compression services in our business.

Impairment of goodwill. The USA Compression Predecessor recognized a $223.0 million impairment on goodwill during the year ended December 31, 2017 as a result of its annual goodwill impairment test, for which the USA Compression Predecessor’s management determined its fair value using a weighted combination of the discounted cash flow method and the guideline company method. Additionally, the USA Compression Predecessor considered the presence and probability of subsequent events on market transactions in estimating the fair value of the company, such as the Transactions discussed in Note 1 to our consolidated financial statements. There was no impairment of goodwill during the year ended December 31, 2018.

Interest expense, net. The $78.4 million increase in interest expense, net was primarily attributable to interest expense incurred on the Senior Notes and outstanding borrowings under the Credit Agreement for which there were no comparable borrowings by the USA Compression Predecessor in the prior period. The interest rate on the Credit Agreement was 4.97% at December 31, 2018, and the weighted-average interest rate was 4.69% for the period from the Transactions Date to December 31, 2018. Average outstanding borrowings under the Credit Agreement was $984.7 million for the period from the Transactions Date to December 31, 2018.

Income tax expense (benefit). During the year ended December 31, 2018, we recorded an income tax benefit of $2.5 million, primarily related to a decrease in the deferred tax expense booked for the Texas Franchise Tax accrual, while during the year ended December 31, 2017, the USA Compression Predecessor recorded an income tax expense of $1.8 million, resulting from an increase in the deferred tax expense booked for the Texas Franchise Tax accrual.

Year ended December 31, 2017 compared to the year ended December 31, 2016

The following table summarizes our results of operations for the periods presented (dollars in thousands):

|  | Year Ended December 31, |  | Percent |
|  | 2017 |  | 2016 |  | Change |
Revenues: |  |  |  |  |  |  |  |  |  |
Contract operations |  | $ | 249,346 |  | $ | 239,143 |  |  | 4.3 | %
Parts and service |  |  | 10,085 |  |  | 7,921 |  |  | 27.3 | %
Related party |  |  | 17,240 |  |  | 16,873 |  |  | 2.2 | %
Total revenues |  |  | 276,671 |  |  | 263,937 |  |  | 4.8 | %
Costs and expenses: |  |  |  |  |  |  |  |  |  |
Cost of operations, exclusive of depreciation and amortization |  |  | 125,204 |  |  | 112,898 |  |  | 10.9 | %
Gross operating margin |  |  | 151,467 |  |  | 151,039 |  |  | 0.3 | %
Other operating and administrative costs and expenses: |  |  |  |  |  |  |  |  |  |
Selling, general and administrative |  |  | 24,944 |  |  | 22,739 |  |  | 9.7 | %
Depreciation and amortization |  |  | 166,558 |  |  | 155,134 |  |  | 7.4 | %
Loss (gain) on disposition of assets |  |  | (367) |  |  | 120 |  |  | (405.8) | %
Impairment of compression equipment |  |  | — |  |  | — |  |  | * | %
Impairment of goodwill |  |  | 223,000 |  |  | — |  |  | * | %
Total other operating and administrative costs and expenses |  |  | 414,135 |  |  | 177,993 |  |  | 132.7 | %
Operating loss |  |  | (262,668) |  |  | (26,954) |  |  | 874.5 | %
Other income (expense): |  |  |  |  |  |  |  |  |  |
Interest expense |  |  | — |  |  | — |  |  | * | %
Other |  |  | (223) |  |  | (153) |  |  | 45.8 | %
Total other expense |  |  | (223) |  |  | (153) |  |  | 45.8 | %
Net loss before income tax expense (benefit) |  |  | (262,891) |  |  | (27,107) |  |  | 869.8 | %
Income tax expense (benefit) |  |  | 1,843 |  |  | (163) |  |  | 1,230.7 | %
Net loss |  | $ | (264,734) |  | $ | (26,944) |  |  | 882.5 | %

* Not meaningful.

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Contract operations revenue. During 2017, the USA Compression Predecessor experienced a year-to-year increase in demand for its compression services driven by increased operating activity in natural gas and crude oil production, resulting in a $10.2 million increase in contract compression and treating revenues. The increase was primarily attributable to increased customer demand in the Permian, Niobrara and Mid-Continent regions.

Parts and service revenue. The $2.2 million increase in installation services revenues was primarily attributable to the construction of additional amine plants.

Related party revenue. Related party revenues were earned through related party transactions in the ordinary course of business and at arms’ length with various affiliated entities of ETP, including Regency Intrastate Gas, LP, Edwards Lime Gathering LLC and certain wholly owned subsidiaries of ETP. The $0.4 million increase in related party revenues was primarily attributable to additional compression service demand from such affiliates.

Cost of operations, exclusive of depreciation and amortization. The $12.3 million increase in cost of operations was primarily attributable to (1) horsepower growth of approximately 160,000, (2) a corresponding increase in parts and service revenue attributable to construction of additional amine plants and (3) an increase in revenue generating horsepower and treating equipment, labor rates, and the amount of overtime for employees.

Gross operating margin. The gross operating margin for the year ended December 31, 2017 was materially consistent with the year ended December 31, 2016.

Selling, general and administrative expense. The $2.2 million increase in general and administrative expense for the year ended December 31, 2017 was primarily attributable to an increase in salaries, health care, and unit-based compensation expenses driven by increased headcount and higher health insurance claims. ETP has allocated certain overhead costs associated with general and administrative services, including salaries and benefits, facilities, insurance, information services, human resources and other support departments to the USA Compression Predecessor. Where costs incurred on the USA Compression Predecessor’s behalf could not be determined by specific identification, the costs were primarily allocated to the USA Compression Predecessor based on an average percentage of fixed assets, gross margin, capital, employee costs, and headcount. The USA Compression Predecessor’s management believed these allocations were a reasonable reflection of the utilization of services provided. However, the allocations may not fully reflect the expenses that would have been incurred had the USA Compression Predecessor been a stand-alone company during the periods presented. During the years ended December 31, 2017 and 2016, ETP allocated general and administrative expenses of $3.6 million and $4.7 million, respectively, to the USA Compression Predecessor.

Depreciation and amortization expense. The $11.4 million increase in depreciation and amortization was primarily related to increased make ready cost with a useful life of two years as a result of increased utilization.

Loss (gain) on disposition of assets. During the year ended December 31, 2017, the $0.4 million gain was primarily attributable to the sale of select compression equipment with a sales price greater than book value. During the year ended December 31, 2016, the $0.1 million loss was primarily attributable to the sale of select compression equipment with a sales price less than book value.

Goodwill impairment. The $223.0 million impairment on goodwill during the year ended December 31, 2017 was a result of the USA Compression Predecessor’s annual goodwill impairment test, for which the USA Compression Predecessor’s management determined its fair value using a weighted combination of the discounted cash flow method and the guideline company method. Additionally, the USA Compression Predecessor considered the presence and probability of subsequent events on market transactions in estimating the fair value of the company, such as the Transactions discussed in Note 1 to our consolidated financial statements. There was no impairment of goodwill during the year ended December 31, 2016.

Income tax expense (benefit). The $2.0 million increase in income tax expense is primarily related to an increase in the deferred tax expense booked for the Texas Franchise Tax accrual.

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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) |  | 2018 |  | 2017 (3) |  | 2016 (3) |  | 2018 |  | 2017 |
Gross operating margin |  | $ | 369,628 |  | $ | 151,467 |  | $ | 151,039 |  | 144.0 | % | 0.3 | %
Gross operating margin percentage (2) |  |  | 63.3 | % |  | 54.7 | % |  | 57.2 | % | 15.7 | % | (4.4) | %
Adjusted EBITDA |  | $ | 320,475 |  | $ | 130,348 |  | $ | 131,686 |  | 145.9 | % | (1.0) | %
Adjusted EBITDA percentage (2) |  |  | 54.8 | % |  | 47.1 | % |  | 49.9 | % | 16.3 | % | (5.6) | %
DCF |  | $ | 177,757 |  | $ | 109,326 |  | $ | 123,442 |  | 62.6 | % | (11.4) | %
DCF Coverage Ratio (4) |  |  | 1.25 | x |  |  |  |  |  |  |  |  |  |
Cash Coverage Ratio (4) |  |  | 1.26 | x |  |  |  |  |  |  |  |  |  |

| (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 and presented in accordance with GAAP, can be found under the caption “Non-GAAP Financial Measures” in Part II, Item 6.

| (2) |  | Gross operating margin percentage and Adjusted EBITDA percentage are calculated as a percentage of revenue.

| (3) |  | Amounts attributed to the USA Compression Predecessor are calculated using the same definitions used by the Partnership. DCF Coverage Ratio and Cash Coverage Ratio are not applicable to the USA Compression Predecessor as the USA Compression Predecessor had no outstanding common units for each period.

| (4) |  | Distributions for the year ended December 31, 2018 reflect only three quarters of distributions as the USA Compression Predecessor did not pay distributions prior to the Transactions Date. DCF, however, reflects a full year of DCF. On a pro forma basis, both the DCF Coverage Ratio and Cash Coverage Ratio for the year ended December 31, 2018 was 1.10x when using comparable three quarters of DCF and three quarters of distributions.

Adjusted EBITDA. The $190.1 million, or 145.9%, increase in Adjusted EBITDA during the year ended December 31, 2018 was primarily attributable to the addition of the Partnership’s historical assets which was the primary cause of a $218.2 million increase in gross operating margin, offset by a $29.2 million increase in selling, general and administrative expenses, excluding transaction expenses, unit-based compensation expense and other non-recurring charges, during the year ended December 31, 2018.

The $1.3 million, or 1.0%, decrease in Adjusted EBITDA during the year ended December 31, 2017 was primarily attributable to a $1.7 million increase in selling, general and administrative expenses, excluding unit-based compensation expense, offset by a $0.4 million increase in gross operating margin during the year ended December 31, 2017.

Distributable Cash Flow. The $68.4 million, or 62.6%, increase in DCF during the year ended December 31, 2018 was primarily attributable to the addition of the Partnership’s historical assets which was the primary cause of (1) a $218.2 million increase in gross operating margin offset by (2) a $73.3 million increase in cash interest expense, net, (3) $36.4 million of distributions on Preferred Units, (4) a $29.2 million increase in selling, general and administrative expenses, excluding transaction expenses, unit-based compensation expense and other non-recurring charges and (5) an $11.5 million increase in maintenance capital expenditures during the comparable period. The USA Compression Predecessor had no outstanding debt on which cash interest expense was paid in the prior period. The increase in selling, general and administrative expenses and maintenance capital expenditures was primarily due to additional activity as a result of the combination of the Partnership’s legacy operations with those of the USA Compression Predecessor.

The $14.1 million, or 11.4%, decrease in DCF during the year ended December 31, 2017 was primarily due to a $12.7 million increase in maintenance capital expenditures and a $1.7 million increase in selling, general and administrative expenses, excluding unit-based compensation expense, offset by a $0.4 million increase in gross operating margin during the comparable period.

Coverage Ratios. Historical coverage ratios are not applicable as the USA Compression Predecessor had no outstanding common units for each period. Coverage ratios for the year ended December 31, 2018 reflect a full year of

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DCF but only three quarters of distributions as the USA Compression Predecessor did not pay any distributions prior to the Transactions Date.

Liquidity and Capital Resources

Overview

We operate in a capital-intensive industry, and our primary liquidity needs are to finance the purchase of additional compression units and make other capital expenditures, service our debt, fund working capital, and pay distributions. Our principal sources of liquidity include cash generated by operating activities, borrowings under the Credit Agreement and issuances of debt and equity securities, including under the DRIP.

We believe cash generated by operating activities and, where necessary, borrowings under the Credit Agreement will be sufficient to service our debt, fund working capital, fund our estimated expansion capital expenditures, fund our maintenance capital expenditures and pay distributions through 2019. Because we distribute all of our available cash, which excludes prudent operating reserves, we expect to fund any future expansion capital expenditures or acquisitions primarily with capital from external financing sources, such as borrowings under the Credit Agreement and issuances of debt and equity securities, including under the DRIP.

To fund a portion of the CDM Acquisition, on March 23, 2018 the Partnership and Finance Corp co-issued $725.0 million in aggregate principal amount of the Senior Notes and, on the Transactions Date, the Partnership issued the Preferred Units and Warrants for aggregate gross consideration of $500.0 million. The transaction fees associated with these issuances were financed with borrowings under the Credit Agreement. Also on the Transactions Date, the borrowing capacity under the Credit Agreement was increased from $1.1 billion to $1.6 billion.

We are not aware of any regulatory changes or environmental liabilities that we currently expect to have a material impact on our current or future operations. Please see “—Capital Expenditures” below.

Cash Flows

The following table summarizes our sources and uses of cash for the years ended December 31, 2018, 2017 and 2016 (in thousands):

|  | Year Ended December 31,
|  | 2018 |  | 2017 |  | 2016
Net cash provided by operating activities |  | $ | 226,340 |  | $ | 135,956 |  | $ | 130,063
Net cash used in investing activities |  |  | (779,663) |  |  | (142,458) |  |  | (36,767)
Net cash provided by (used in) financing activities |  |  | 549,409 |  |  | (3,666) |  |  | (90,367)

Net cash provided by operating activities. The $90.4 million increase in net cash provided by operating activities for the year ended December 31, 2018 was due primarily to a $111.0 million increase in net income, as adjusted for non-cash items, and changes in other working capital.

The $5.9 million increase in net cash provided by operating activities for the year ended December 31, 2017 was due primarily to net horsepower growth and an increase in treating utilization in 2017.

Net cash used in investing activities. Net cash used in investing activities for the year ended December 31, 2018 related primarily to $1.2 billion of cash paid, offset by $710.5 million of cash received, each as part of the CDM Acquisition. Additionally, during the year ended December 31, 2018, net cash used in investing activities of $266.6 million related to purchases of new compression units, reconfiguration costs and related equipment and net cash provided by investing activities of $7.5 million and $0.4 million related to proceeds from disposition of property and equipment and proceeds from insurance recoveries, respectively.

Net cash used in investing activities for the years ended December 31, 2017 and 2016 related primarily to capital expenditures, including net horsepower growth, partially offset by proceeds from asset sales. For the years ended

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December 31, 2017 and 2016, total capital expenditures were $157.3 million and $61.6 million, respectively, and proceeds from asset sales were $14.8 million and $24.8 million, respectively.

Net cash provided by (used in) financing activities. During the year ended December 31, 2018, we borrowed $230.5 million, on a net basis, to support our purchases of new compression units, reconfiguration costs and related equipment as well as fund certain costs associated with the CDM Acquisition. During the year ended December 31, 2018, we received $479.1 million in net proceeds from the issuance of Preferred Units and Warrants which was used to partially fund the CDM Acquisition and a $28.5 million contribution from the USA Compression Predecessor’s former parent company, ETP. Additionally, and in connection with the CDM Acquisition, we paid various fees of $17.7 million related primarily to the Credit Agreement. During the year ended December 31, 2018, we also paid cash related to the net settlement of unit-based equity awards under our long-term incentive plan in the amount of $4.4 million, made cash distributions to our common unitholders of $142.3 million and made cash distributions on the Preferred Units of $24.2 million.

For the years ended December 31, 2017 and 2016, net cash used in financing activities reflected the payment of cash distributions to the USA Compression Predecessor’s former parent company, ETP, of $3.7 million and $90.4 million, respectively.

Capital Expenditures

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

| · |  | maintenance capital expenditures, which are capital expenditures made to maintain the operating capacity of our assets and extend their useful lives, to replace partially or fully depreciated assets, or other capital expenditures that are 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 operating income capacity of assets, including by acquisition of compression units or through modification of existing compression units to increase their capacity, or to replace certain partially or fully depreciated assets that were not currently generating operating income.

We classify capital expenditures as maintenance or expansion on an individual asset basis. Over the long term, we expect that our maintenance capital expenditure requirements will continue to increase as the overall size and age of our fleet increases. Our aggregate maintenance capital expenditures for the years ended December 31, 2018 and 2017 were $32.5 million and $21.0 million, respectively. We currently plan to spend approximately $25 million in maintenance capital expenditures during 2019, including parts consumed from inventory.

Given our growth objectives and anticipated demand from our customers as a result of the increasing natural gas activity described above under the heading “—General Trends and Outlook,” we anticipate that we will continue to make significant expansion capital expenditures. Without giving effect to any equipment we may acquire pursuant to any future acquisitions, we currently have budgeted between $140 million and $150 million in expansion capital expenditures during 2019. Our expansion capital expenditures for the years ended December 31, 2018 and 2017 were $208.7 million and $154.5 million, respectively.

Revolving Credit Facility

As of December 31, 2018, we were in compliance with all of our covenants under the Credit Agreement. As of December 31, 2018, we had outstanding borrowings under the Credit Agreement of $1.1 billion, $550.5 million of borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of $550.5 million. As described in Note 10 to our consolidated financial statements, we entered into the Credit Agreement on the Transactions Date, which amended the Fifth Amended and Restated Credit Agreement to, among other things, (i) increase the borrowing capacity under the Credit Agreement from $1.1 billion to $1.6 billion (subject to

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availability under a borrowing base), (ii) extend the termination date (and the maturity date of the obligations thereunder) from January 6, 2020 to April 2, 2023, (iii) subject to the terms of the Credit Agreement, permit up to $400.0 million of future increases in borrowing capacity, (iv) modify the leverage ratio covenant to be 5.75 to 1.0 through the end of the fiscal quarter ending March 31, 2019, 5.5 to 1.0 through the end of the fiscal quarter ending December 31, 2019, and 5.0 to 1.0 thereafter and (v) increase the applicable margin for eurodollar borrowings to range from 2.00% to 2.75%, depending on our leverage ratio, all as more fully set forth in the Credit Agreement.

As of February 14, 2019, we had outstanding borrowings of $1.1 billion. We expect to remain in compliance with our covenants under the Credit Agreement throughout 2019. If our current cash flow projections prove to be inaccurate, we expect to be able to remain in compliance with such financial covenants by taking one or more of the following actions: issue debt and equity securities in conjunction with the acquisition of another business; issue equity in a public or 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 the Credit Agreement.

For a more detailed description of the Credit Agreement including the covenants and restrictions contained therein, please refer to Note 10 to our consolidated financial statements.

Senior Notes

See Note 10 to our consolidated financial statements for information regarding the Senior Notes.

Distribution Reinvestment Plan

During the year ended December 31, 2018, distributions of $0.6 million were reinvested under the DRIP resulting in the issuance of 39,280 common units. Such distributions are treated as non-cash transactions in the accompanying Consolidated 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 12 to our consolidated financial statements.

Total Contractual Cash Obligations

The following table summarizes our total contractual cash obligations as of December 31, 2018:

|  | Payments Due by Period |
|  |  |  |  |  |  |  |  |  |  |  |  |  | More than |
Contractual Obligations |  | Total |  | 1 year |  | 2 - 3 years |  | 4 - 5 years |  | 5 years |
|  | (in thousands) |
Long-term debt (1) |  | $ | 1,774,547 |  | $ | — |  | $ | — |  | $ | 1,049,547 |  | $ | 725,000 |
Interest on long-term debt obligations (2) |  |  | 591,376 |  |  | 101,964 |  |  | 203,929 |  |  | 169,182 |  |  | 116,302 |
Equipment/capital purchases (3) |  |  | 107,457 |  |  | 107,457 |  |  | — |  |  | — |  |  | — |
Operating and capital lease obligations (4) |  |  | 7,910 |  |  | 3,773 |  |  | 2,417 |  |  | 1,078 |  |  | 642 |
Total contractual cash obligations |  | $ | 2,481,290 |  | $ | 213,194 |  | $ | 206,346 |  | $ | 1,219,807 |  | $ | 841,944 |

| (1) |  | We assumed that the amount outstanding under the Credit Agreement at December 31, 2018 would be repaid in April 2023, the maturity date of the facility. The aggregate principal amount of our Senior Notes outstanding is due April 2026.

| (2) |  | Represents future interest payments under the Credit Agreement based on the interest rate as of December 31, 2018 of 4.97% and on $725.0 million aggregate principal amount of the Senior Notes.

| (3) |  | Represents commitments for new compression units that are being fabricated, and is a component of our overall projected expansion capital expenditures during 2019 of $140 million to $150 million.

| (4) |  | Represents commitments for future minimum lease payments on noncancelable operating and capital leases.

Effects of Inflation. Our revenues and results of operations have not been materially impacted by inflation and changing prices in the past three fiscal years.

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Off-Balance Sheet Arrangements

We have no off-balance sheet financing activities. Please refer to Note 17 to our consolidated financial statements included in this report for a description of our commitments and contingencies.

Critical Accounting Policies and Estimates

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

Revenue Recognition

We recognize revenue when obligations under the terms of a contract with our customer are satisfied; generally this occurs with the transfer of our services or goods. Revenue is measured at the amount of consideration we expect to receive in exchange for providing services or transferring goods. Sales taxes incurred on behalf of, and passed through to, customers are excluded from revenue. Incidental items, if any, that are immaterial in the context of the contract are recognized as expense.

Contract operations revenue

Revenue from contracted compression, station, gas treating and maintenance services is recognized ratably under our fixed-fee contracts over the term of the contract as services are provided to our customers. Initial contract terms typically range from six months to five years. However, we usually continue to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. We primarily enter into fixed-fee contracts whereby our customers are required to pay our monthly fee even during periods of limited or disrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the service month, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of our invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue. The amount of consideration we receive and revenue we recognize is based upon the fixed fee rate stated in each service contract.

Retail parts and services revenue

Retail parts and services revenue is earned primarily on freight and crane charges that are directly reimbursable by our customers and maintenance work on units at our customers’ locations that are outside the scope of our core maintenance activities. Revenue from retail parts and services is recognized at the point in time the part is transferred or service is provided and control is transferred to the customer. At such time, the customer has the ability to direct the use of the benefits of such part or service after we have performed our services. We bill upon completion of the service or transfer of the parts, and payment is generally due 30 days after receipt of our invoice. The amount of consideration we receive and revenue we recognize is based upon the invoice amount.

Business Combinations and Goodwill

Goodwill acquired in connection with business combinations represents the excess of consideration over the fair value of net assets acquired. Certain assumptions and estimates are employed in determining the fair value of assets acquired and liabilities assumed. Goodwill is not amortized, but is reviewed for impairment annually based on the carrying values as of October 1, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered.

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Goodwill—Impairment Assessments

We evaluate goodwill for impairment annually on October 1 and whenever events or changes indicate that 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 fiscal quarter 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 would receive if we sold the reporting unit, enterprise value, discount rates and projected cash flows. Estimating projected cash flows requires us to make certain assumptions as it relates to future operating performance. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. Due to the imprecise nature of these projections and assumptions, actual results can, and often do, differ from our estimates. If the growth assumptions embodied in the current year impairment testing prove inaccurate, we could incur an impairment charge in the future.

As of October 1, 2018, we performed our annual goodwill impairment analysis which included a qualitative assessment and concluded that it is not more likely than not that the fair value of our single reporting unit was less than its carrying value and that our goodwill was not impaired. As a result, w e recorded no goodwill impairment charges for the year ended December 31, 2018. We had approximately $619.4 million of goodwill recorded on the balance sheet as of December 31, 2018.

For the year ended December 31, 2017, the USA Compression Predecessor performed a quantitative assessment for its annual goodwill impairment test and determined its fair value using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The USA Compression Predecessor believed the estimates and assumptions used in the impairment assessment were reasonable and based on available market information, but variations in any of the assumptions could have resulted in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the USA Compression Predecessor determined fair value based on estimated future cash flows including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflects the overall level of inherent risk of the company. Cash flow projections were derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which were developed by management. Subsequent period cash flows were developed using growth rates that management believed were reasonably likely to occur. Under the guideline company method, the USA Compression Predecessor determined its estimated fair value by applying valuation multiples of comparable publicly-traded companies to the projected EBITDA of the company and then averaging that estimate with similar historical calculations using a three-year average. In addition, the USA Compression Predecessor estimated a reasonable control premium representing the incremental value that accrues to the predecessor’s majority owner from the opportunity to dictate the strategic and operational actions of the business. Additionally, the USA Compression Predecessor considered the presence and probability of subsequent events on market transactions in estimating the fair value of the company, such as the Transactions discussed in Note 1 to our consolidated financial statements.

One key assumption for the measurement of goodwill impairment is management’s estimate of future cash flows and EBITDA. These estimates are based on the annual budget for the upcoming year and forecasted amounts for multiple subsequent years. The annual budget process is typically completed near the annual goodwill impairment testing date, and management uses the most recent information for the annual impairment tests. The forecast is also subjected to a comprehensive update annually in conjunction with the annual budget process and is revised periodically to reflect new information and/or revised expectations.

Based on the completion of the annual goodwill impairment testing as described above, the USA Compression Predecessor recorded a $223.0 million impairment for the year ended December 31, 2017. The USA Compression

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Predecessor had approximately $253.4 million of goodwill remaining on the balance sheet as of December 31, 2017 following this impairment. There was no goodwill impairment for the year ended December 31, 2016.

As discussed above, estimates of fair value can be affected by a variety of external and internal factors. Volatility in crude oil prices can cause disruptions in global energy industries and markets. Potential events or circumstances that could reasonably be expected to negatively affect the key assumptions we used in estimating the fair value of our reporting unit include the consolidation or failure of crude 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 or achieve less revenue per customer. We continue to monitor the $619.4 million balance of goodwill and if the estimated fair value of our reporting unit declines due to any of these or other factors, we may be 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 our total assets. Long-lived assets to be held and used by us are reviewed to determine whether any events or changes in circumstances indicate the carrying amount of the asset may not be recoverable. For long-lived assets to be held and used, we base our evaluation on impairment indicators such as the nature of the assets, the future economic benefit of the assets, the consistency of performance characteristics of compression units in our idle fleet with the performance characteristics of our revenue generating horsepower, any historical or future profitability measurements and other external market conditions or factors that may be present. If such impairment indicators are present or other factors exist that indicate the carrying amount of the asset may not be recoverable, we determine whether an impairment has occurred through the use of an undiscounted cash flows analysis. If an impairment has occurred, we recognize a loss for the difference between the carrying amount and the estimated fair value of the asset. The fair value of the asset is measured using quoted market prices or, in the absence of quoted market prices, is based on an estimate of discounted cash flows, the expected net sale proceeds compared to other similarly configured fleet units we recently sold, a review of other units recently offered for sale by third parties, or the estimated 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 in estimating whether or not the carrying value of our long-lived assets are recoverable include the consolidation or failure of crude 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 or achieve less revenue per customer. If our projections of cash flows associated with our units decline, we may have to record an impairment of compression equipment in future periods.

Allowances and Reserves

We maintain an allowance for doubtful accounts based on specific customer collection issues and historical experience. The determination of the allowance for doubtful accounts requires us to make estimates and judgments regarding our customers’ ability to pay amounts due. On an ongoing basis, we conduct an evaluation of the financial strength of our customers based on payment history, the overall business climate in which our customers operate and specific identification of customer bad debt and make adjustments to the allowance as necessary. Our evaluation of our customers’ financial strength is based on the aging of their respective receivables balance, customer correspondence, financial information and third-party credit ratings. Our evaluation of the business climate in which our customers operate is based on a review of various publicly-available materials regarding our customers’ industries, including the solvency of various companies in the industry.

Recent Accounting Pronouncements

For a discussion on specific recent accounting pronouncements affecting us, please see Note 18 to our consolidated financial statements.

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ITEM 7A.Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. We do not take title to any natural gas or crude oil in connection with our services and, accordingly, have no direct revenue exposure to fluctuating commodity prices. However, the demand for our compression services depends upon the continued demand for, and production of, natural gas and crude oil. Natural gas or crude oil prices remaining low over the long-term could result in a decline in the production of natural gas or crude oil, which could result in reduced demand for our compression services. We do not intend to hedge our indirect exposure to fluctuating commodity prices. A 1% decrease in average revenue generating horsepower of our active fleet during the year ended December 31, 2018 would have resulted in a decrease of approximately $5.3 million and $3.4 million in our revenue and gross operating margin, respectively. Gross operating margin is a non-GAAP financial measure. 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”). Please also read Part I, Item 1A (“Risk Factors—Risks Related to Our Business—A long-term reduction in the demand for, or production of, natural gas or crude oil in the locations where we operate could adversely affect the demand for our services or the prices we charge for our services, which could result in a decrease in our revenues and cash available for distribution to unitholders”).

Interest Rate Risk

We are exposed to market risk due to variable interest rates under our financing arrangements.

As of December 31, 2018, we had approximately $1.1 billion of variable-rate outstanding indebtedness at a weighted-average interest rate of 4.69%. A 1% increase or decrease in the effective interest rate on our variable-rate outstanding debt as of December 31, 2018 would result in an annual increase or decrease in our interest expense of approximately $10.5 million.

For further information regarding our exposure to interest rate fluctuations on our debt obligations, see Note 10 to our consolidated financial statements. Although we do not currently hedge our variable rate debt, we may, in the future, hedge all or a portion of such debt.

Credit Risk

Our credit exposure generally relates to receivables for services provided. If any significant customer of ours should have credit or financial problems resulting in a delay or failure to repay the amount it owes us, it could have a material adverse effect 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 participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports

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that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2018 at the reasonable assurance level.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting for us. Our internal control system was designed to provide reasonable assurance regarding the preparation and fair presentation of our published financial statements.

There are inherent limitations to the effectiveness of any control system, however well designed, including the possibility of human error and the possible circumvention or overriding of controls. Further, the design of a control system must 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 the likelihood of future events, and there can be no assurance that a control will be effective under all potential future conditions. As a result, even an effective system of internal control over financial reporting can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared.

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2018. In making this assessment, management used the criteria set forth by the 2013 Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework. Based on this assessment, our management believes that, as of December 31, 2018, our internal control over financial reporting was effective. Grant Thornton LLP, an independent registered public accounting firm, has audited the effectiveness of our internal control over financial reporting as of December 31, 2018, as stated in their report, which is included herein.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of USA Compression GP, LLC and

Unitholders of USA Compression Partners, LP

Opinion on internal control over financial reporting

We have audited the internal control over financial reporting of USA Compression Partners, LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2018, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2018, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2018, and our report dated February 19, 2019 expressed an unqualified opinion on those financial statements.

Basis for opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

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

Definition and limitations of internal control over financial reporting

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

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ GRANT THORNTON LLP

Houston, Texas

February 19, 2019

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Changes in Internal Control over Financial Reporting

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

ITEM 9B.Other Information

On February 13, 2019, the Board approved the USA Compression Partners, LP Amended and Restated Annual Cash Incentive Plan (the “A&R Bonus Plan”). See “Part III—Item 11. Executive Compensation—Compensation Discussion & Analysis—Annual Cash Incentive Compensation for 2019” for a description of the A&R Bonus Plan; such description does not purport to be complete and is qualified by reference to the A&R Bonus Plan, which is filed as Exhibit 10.21 hereto and is incorporated herein by reference.

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PART III

ITEM 10.Directors, Executive Officers and Corporate Governance

Board of Directors

Our general partner, USA Compression GP, LLC (the “General Partner”), manages our operations and activities. As a result of several transactions (the “Transactions”) that closed on April 2, 2018 (the “Transactions Date”), the General Partner is solely owned by Energy Transfer Operating, L.P. (“ETO”), a wholly owned subsidiary of Energy Transfer LP (“ET” and, collectively with ETO and their affiliates, “Energy Transfer”). The General Partner has a board of directors (the “Board”) that manages our business. The Board is not elected by our unitholders and is not subject to re-election on a regular basis in the future. As the sole member of the General Partner, ETO is entitled under the limited liability company agreement of the General Partner (the “GP LLC Agreement”) to appoint all directors of the General Partner, subject to rights and restrictions contained in other agreements. The GP LLC Agreement provides that the Board shall consist of between two and nine persons, at least two of whom are required to meet the independence standards required of directors who serve on an audit committee of a board of directors established by the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the rules and regulations of the SEC thereunder, and by the NYSE pertaining to qualification for service on an audit committee.

Prior to the Transactions Date, the Board was comprised of eight members, and Eric D. Long, our President and Chief Executive Officer (“CEO”), is the only director who remained on the Board subsequent to the Transactions Date. Effective as of the Transactions Date, the Board is comprised of nine members, eight of whom were designated by ETO and one of whom was designated by EIG Management Company, LLC (“EIG Management”) pursuant to that certain Board Representation Agreement among us, the General Partner, Energy Transfer Equity, L.P. (whose wholly owned subsidiary, Energy Transfer Partners, L.L.C. acquired the General Partner in the Transactions and subsequently contributed it to ETO in connection with a merger among several Energy Transfer entities that closed in October 2018) and EIG Veteran Equity Aggregator, L.P. (along with its affiliated funds, “EIG”) on the Transactions Date in connection with our private placement to EIG and FS Energy and Power Fund (“FS Energy”) of Series A Preferred Units in the Partnership (the “Preferred Units”) and warrants to purchase common units of the Partnership (the “Warrants”). Under the Board Representation Agreement, EIG Management has the right to designate one member of the Board for so long as EIG and FS Energy own, in the aggregate, more than 5% of the Partnership’s outstanding common units (taking into account the common units issuable upon conversion of the Preferred Units and exercise of the Warrants). Three members of the Board are independent as defined under the independence standards established by the NYSE and the SEC. Although the NYSE does not require a publicly traded limited partnership like us to have a majority of independent directors on the Board or to establish a compensation committee or a nominating committee, the Board has elected to have a standing compensation committee (the “Compensation Committee”). We do not have a nominating committee in light of the fact that ETO and EIG currently collectively appoint all of the members of the Board.

Our CEO is currently the only management member of the Board. The non-management members of the Board meet in executive session without any members of management present at least twice a year. Mr. William S. Waldheim presides at such meetings. Interested parties can communicate directly with non-management members of the Board by mail in care of the General Counsel and Secretary at USA Compression Partners, LP, 100 Congress Avenue, Suite 450, Austin, Texas 78701. Such communications should specify the intended recipient or recipients. Commercial solicitations or similar communications will not be forwarded to the Board.

As a limited partnership, NYSE rules do not require us to seek unitholder approval for the election of any of our directors. We do not have a formal process for identifying director nominees, nor do we have a formal policy regarding consideration of diversity in identifying director nominees. We believe, however, that the individuals appointed as directors have experience, skills and qualifications relevant to our business and have a history of service in senior leadership positions with the qualities and attributes required to provide effective oversight of the Partnership.

Independent Directors. The Board has determined that Matthew S. Hartman, Glenn E. Joyce and William S. Waldheim are independent directors under the standards established by the NYSE and the Securities Exchange Act of 1934 (the “Exchange Act”). The Board considered all relevant facts and circumstances and applied the independence

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guidelines of the NYSE and the Exchange Act in determining that none of these directors has any material relationship with us, our management, the General Partner or its affiliates or our subsidiaries.

Mr. Hartman is a Managing Director at EIG, and, since the Transactions Date, EIG owns over 80% of the Preferred Units and Warrants in the Partnership. The Board determined that EIG’s ownership of Preferred Units and Warrants did not preclude the independence of Mr. Hartman because (i) the Preferred Units and Warrants do not confer voting rights sufficient to participate in the control of the Partnership or influence its management, (ii) the Board Representation Agreement does not grant to EIG a sufficient number of seats on the Board to significantly influence or control its decision making or materially influence the management or operation of the Partnership and (iii) the Board has determined that ownership of even a significant amount of the Partnership’s securities does not, by itself, preclude a finding of independence. In addition, Mr. Hartman serves on the board of directors of one of our customers, Southcross Holdings GP LLC (“Southcross”). During the period of Mr. Hartman’s directorship during 2018, Southcross made compression service payments to us of approximately $0.3 million. The Board determined that Mr. Hartman’s relationship with Southcross did not preclude his independence.

Prior to the Transactions, the Board included the following directors that it had determined were independent under the standards established by the NYSE and the Exchange Act: Robert F. End, Jerry L. Peters and Forrest E. Wylie. Mr. Peters served on the Board from October 2017 until the Transactions Date, and since September 2012, Mr. Peters also served on the board of directors and the audit committee of one of our customers. During the period of Mr. Peters’ directorship during 2018, subsidiaries of this customer made compression service payments to us of approximately $0.3 million. The Board previously determined that Mr. Peters’ relationship with this customer did not preclude his independence. Each of Messrs. End, Peters and Wylie resigned effective the Transactions Date in connection with the Transactions.

The Board’s Role in Risk Oversight

The Board administers its risk oversight function as a whole and through its committees. It does so in part through discussion and review of our business, financial reporting and corporate governance policies, procedures and practices, with opportunity to make specific inquiries of management. In addition, at each regular meeting of the Board, management provides a report of the Partnership’s operational and financial performance, which often prompts questions and feedback from the Board. The audit committee of the Board (the “Audit Committee”) provides additional risk oversight through its quarterly meetings, where it discusses policies with respect to risk assessment and risk management, reviews contingent liabilities and risks that may be material to the Partnership and assesses major legislative and regulatory developments that could materially impact the Partnership’s contingent liabilities and risks. The Audit Committee is also required to discuss any material violations of our policies brought to its attention on an ad hoc basis. Additionally, the Compensation Committee reviews our overall compensation program and its effectiveness at both linking executive pay to performance and aligning the interests of our executives and our unitholders.

Committees of the Board of Directors

Audit Committee. T he Board appoints the Audit Committee, which is comprised solely of directors who meet the independence and experience standards established by the NYSE and the Exchange Act. The Audit Committee consists of Messrs. Hartman, Joyce and Waldheim, and Mr. Waldheim serves as chairman of the Audit Committee. The Board determined that Mr. Waldheim is an “audit committee financial expert” as defined in Item 407(d)(5)(ii) of SEC Regulation S-K, and that each of Messrs. Hartman, Joyce and Waldheim is “independent” within the meaning of the applicable NYSE and Exchange Act rules governing audit committee independence. The Audit Committee assists the Board in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements as well as the effectiveness of our corporate policies and internal controls. The Audit Committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The Audit Committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the Audit Committee.

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In April 2018, the Audit Committee recommended that the Board approve an amended and restated Audit Committee charter (the “A&R Audit Committee Charter”) that is based on Energy Transfer’s audit committee charter, and in May 2018 the Board approved the A&R Audit Committee Charter. The A&R Audit Committee Charter is available under the Investor Relations tab on our website at usacompression.com. We will provide a copy of the A&R Audit Committee Charter to any of our unitholders without charge upon written request to Investor Relations, 100 Congress Avenue, Suite 450, Austin, TX 78701.

Compensation Committee. The NYSE does not require a listed limited partnership like us to have a compensation committee. However, the Board established the Compensation Committee to, among other things, oversee our compensation program described below in Part III, Item 11 “Executive Compensation.” The Compensation Committee consists of Messrs. Joyce and Waldheim and is chaired by Mr. Joyce. The Compensation Committee establishes and reviews general policies related to our compensation and benefits and is responsible for making recommendations to the Board with respect to the compensation and benefits of the Board. In addition, the Compensation Committee administers the USA Compression Partners, LP 2013 Long-Term Incentive Plan, as amended and as may be further amended or replaced from time to time (the “LTIP”).

In February 2019, the Compensation Committee recommended that the Board approve, and the Board approved, an amended and restated Compensation Committee charter (the “A&R Compensation Committee Charter”) that is based on Energy Transfer’s compensation committee charter. Under the A&R Compensation Committee Charter, a director serving as a member of the Compensation Committee may not be an officer of or employed by the General Partner, us or our subsidiaries. During 2018, neither Mr. Joyce nor Mr. Waldheim was an officer or employee of Energy Transfer or any of its affiliates, or served as an officer of any company with respect to which any of our executive officers served on such company’s board of directors. In addition, neither Mr. Joyce nor Mr. Waldheim is a former employee of Energy Transfer or any of its affiliates.

The A&R Compensation Committee Charter is available under the Investor Relations tab on our website at usacompression.com. We will provide a copy of the A&R Compensation Committee Charter to any of our unitholders without charge upon written request to Investor Relations, 100 Congress Avenue, Suite 450, Austin, TX 78701.

Conflicts Committee. As set forth in the GP LLC Agreement, the General Partner may, from time to time, establish a conflicts committee to which the Board will appoint independent directors and which may be asked to review specific matters that the Board believes may involve conflicts of interest between us, our limited partners and Energy Transfer. Such conflicts committee will determine the resolution of the conflict of interest in any matter referred to it in good faith. The members of the conflicts committee may not be officers or employees of the General Partner or directors, officers or employees of its affiliates, including Energy Transfer, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on the Audit Committee, and certain other requirements. Any matters approved by the conflicts committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by the General Partner of any duties it may owe us or our unitholders.

Corporate Governance Guidelines and Code of Ethics

The Board has adopted Corporate Governance Guidelines (the “Guidelines”) that outline important policies and practices regarding our governance and provide a framework for the function of the Board and its committees. In February 2019, the Board approved certain amendments to the Guidelines to reflect current Board practices since the Transactions. The Board has also adopted a Code of Business Conduct and Ethics (the “Code”) that applies to the General Partner and its subsidiaries and affiliates, including us, and to all of its and their directors, employees and officers, including its principal executive officer, principal financial officer and principal accounting officer. We intend to post any amendments to the Code, or waivers of its provisions applicable to our directors or executive officers, including our principal executive officer and principal financial officer, on our website. The Guidelines and the Code are available under the Investor Relations tab on our website at usacompression.com. We will provide copies of the Guidelines and the Code to any of our unitholders without charge upon written request to Investor Relations, 100 Congress Avenue, Suite 450, Austin, TX 78701.

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Note that the preceding internet addresses are for informational purposes only and are not intended to be hyperlinked. Accordingly, no information found on or provided at those internet addresses or on our website in general is intended or deemed to be incorporated by reference herein.

Directors and Executive Officers

The following table shows information as of February 14, 2019 regarding the current directors and executive officers of USA Compression GP, LLC.

Name |  | Age |  | Position with USA Compression GP, LLC
Eric D. Long |  | 60 |  | President and Chief Executive Officer and Director
Matthew C. Liuzzi |  | 44 |  | Vice President, Chief Financial Officer and Treasurer
William G. Manias |  | 56 |  | Vice President and Chief Operating Officer
David A. Smith |  | 56 |  | Vice President and President, Northeast Region
Sean T. Kimble |  | 54 |  | Vice President, Human Resources
Christopher W. Porter |  | 35 |  | Vice President, General Counsel and Secretary
Michael Bradley |  | 64 |  | Director
Christopher R. Curia |  | 63 |  | Director
Matthew S. Hartman |  | 38 |  | Director
Glenn E. Joyce |  | 61 |  | Director
Thomas E. Long |  | 62 |  | Director
Thomas P. Mason |  | 62 |  | Director
Matthew S. Ramsey |  | 63 |  | Director
William S. Waldheim |  | 62 |  | Director

The directors of the General Partner hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the Board. There are no family relationships among any of the directors or executive officers of the General Partner.

Eric D. Long has served as our President and CEO since September 2002 and has served as a director of the General Partner since June 2011. Mr. Long co-founded USA Compression in 1998 and has over 35 years of experience in the oil and gas industry. From 1980 to 1987, Mr. Long served in a variety of technical and managerial roles for several major pipeline and oil and natural gas producing companies, including Bass Enterprises Production Co. and Texas Oil & Gas. Mr. Long then served in a variety of senior officer level operating positions with affiliates of Hanover Energy, Inc., a company primarily engaged in the business of gathering, compressing and transporting natural gas. In 1993, Mr. Long co-founded Global Compression Services, Inc., a compression services company. Mr. Long was formerly on the board of directors of the Wiser Oil Company, an NYSE listed company from May 2001 until it was sold to Forest Oil Corporation in May 2004. Mr. Long received his bachelor’s degree, with honors, in Petroleum Engineering from Texas A&M University. He is a registered Professional Engineer in the state of Texas.

As a result of his professional background, Mr. Long brings to us executive level strategic, operational and financial skills. These skills, combined with his over 35 years of experience in the oil and natural gas industry, including in particular his experience in the compression services sector, make Mr. Long a valuable member of the Board.

Matthew C. Liuzzi has served as our Vice President, Chief Financial Officer and Treasurer since January 2015. Prior to such time, Mr. Liuzzi served as our Senior Vice President – Strategic Development since joining us in April 2013. Mr. Liuzzi joined us after nine years in investment banking, since 2008 at Barclays, where he was most recently a Director in the Global Natural Resources Group in Houston. At Barclays, Mr. Liuzzi worked primarily with midstream clients on a variety of investment banking assignments, including initial public offerings, public and private debt and equity offerings, as well as strategic advisory assignments. He holds a B.A. and an M.B.A., both from the University of Virginia.

William G. Manias has served as our Vice President and Chief Operating Officer since July 2013. He served as a director of the General Partner from February 2013 to July 2013. From October 2009 until January 2013, Mr. Manias

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served as Senior Vice President and Chief Financial Officer of Crestwood Midstream Partners LP and its affiliates, where his general responsibilities included managing the partnership’s financial and treasury activities. Before joining Crestwood in January 2009, Mr. Manias was the Chief Financial Officer of TEPPCO Partners, L.P. starting in January 2006. From September 2004 until January 2006, he served as Vice President of Business Development and Strategic Planning at Enterprise Products Partners L.P. He previously served as Vice President and Chief Financial Officer of GulfTerra Energy Partners, L.P. from February 2004 to September 2004 at which time GulfTerra Energy Partners, L.P. was merged with Enterprise Products Partners L.P. Prior to GulfTerra Energy Partners, L.P., Mr. Manias held several executive management positions with El Paso Corporation. Prior to El Paso, he worked as an energy investment banker for J.P. Morgan Securities Inc. and its predecessor companies from May 1992 to August 2001. Mr. Manias earned a B.S.E. in civil engineering from Princeton University in 1984, a M.S. in petroleum engineering from Louisiana State University in 1986 and an M.B.A. from Rice University in 1992.

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

Sean T. Kimble has served as our Vice President, Human Resources since June 2014. Mr. Kimble brings to us over twenty-five years of human resources leadership experience. Prior to joining us, he was most recently the Senior Vice President of Human Resources at Millard Refrigerated Services from January 2011 to May 2014 where he led all aspects of human resources. Before joining Millard, he was the Chief Administrative Officer and Executive Vice President of Human Resources at MV Transportation from March 2005 to February 2009 where he led human resources, safety, labor relations and various other operating support functions. Mr. Kimble holds a B.S. in marketing from Sacramento State University and an M.B.A. from Saint Mary’s College of California. Mr. Kimble also completed the University of Michigan’s Strategic HR and Strategic Collective Bargaining Programs.

Christopher W. Porter has served as our Vice President, General Counsel and Secretary since January 2017, and, prior to that, had served as our Associate General Counsel and Assistant Secretary since October 2015. From January 2010 through October 2015, Mr. Porter practiced corporate and securities law at Hunton Andrews Kurth LLP, representing public and private companies, including master limited partnerships, in capital markets offerings and mergers and acquisitions. Mr. Porter holds a B.B.A. degree in accounting from Texas A&M University, a M.S. degree in finance from Texas A&M University, and a J.D. degree from The George Washington University.

Michael Bradley has served on the Board since April 2018. Mr. Bradley currently serves as the Executive Vice President—LNG & International Business Development at ETO. He served on the board of directors of Regency GP, LLC, the general partner of Regency Energy Partners LP (“Regency”) and as the President and Chief Executive Officer of Regency until its merger with ETP in May 2015. Prior to joining Regency, he served as President, Chief Executive Officer and a director of Matrix Service Company. Prior to joining Matrix Service Company, Mr. Bradley served as President and Chief Executive Officer of DCP Midstream Partners, LP (“DCP Midstream”) and as a member of the board of its general partner. Mr. Bradley also previously served as Group Vice President of Gathering and Processing for Duke Energy Field Services (“DEFS”) and Executive Vice President of DEFS and Senior Vice President of DEFS. Mr. Bradley holds a bachelor’s degree in civil engineering from the University of Kansas and completed the Duke University Executive Management Program. Mr. Bradley is a member of the American Society of Civil Engineers and serves on the advisory board for the University of Kansas School of Engineering.

Mr. Bradley was selected to serve on the Board due to his many years of experience in the natural gas industry and midstream energy sector and proven record of effective executive level leadership.

Christopher R. Curia has served on the Board since April 2018. Mr. Curia has also served as a director on the board of directors of the general partner of Sunoco LP (NYSE: SUN) since August 2014 and as its Executive Vice President-

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Human Resources since April 2015. Mr. Curia also serves as the Executive Vice President and Chief Human Resources Officer of LE GP, LLC (“LE GP”), the general partner of Energy Transfer LP (“ET LP”) and has served in that capacity since January 2015. Mr. Curia joined ETO in July 2008 and was appointed the Executive Vice President and Chief Human Resources Officer of ET LP in January 2015. Prior to joining Energy Transfer, Mr. Curia held HR leadership positions at both Valero Energy Corporation and Pennzoil and has more than three decades of Human Resources experience in the oil and gas field. Mr. Curia holds a master’s degree in Industrial Relations from the University of West Virginia.

Mr. Curia was selected to serve on the Board due to the valuable perspective he brings from his extensive experience working as a human resources professional in the energy industry, and the insights he brings to the Board on matters such as succession planning, compensation, employee management and acquisition evaluation and integration.

Matthew S. Hartman has served on the Board since April 2018. Mr. Hartman is a Managing Director at EIG Global Energy Partners and is the co-head of EIG’s midstream investment team. In this capacity, he invests in and monitors energy midstream investments. Mr. Hartman also serves on the board of directors of Southcross Holdings GP LLC. Prior to joining EIG in 2014, Mr. Hartman served in various roles within the Citigroup and UBS investment banking divisions, where he advised on mergers as well as equity and debt financings for midstream energy companies. Mr. Hartman also previously worked in Ernst & Young’s tax practice. Mr. Hartman received a B.B.A. and B.P.A. from Oklahoma Baptist University and an M.B.A. from the University of Texas.

Mr. Hartman was selected to serve on the Board because of his financial and investment acumen and experience with the midstream energy sector.

Glenn E. Joyce has served on the Board since April 2018. Mr. Joyce has served as Chief Administrative Officer of Apex International Energy (“Apex”) since January 2017. He previously served as Director – HR and Administration since he joined Apex in April 2016. Prior to joining Apex, he spent over 17 years with Apache Corporation where his last position was Director of Global Human Resources in which he managed the HR functions of the international regions of Apache (Australia, Argentina, UK, Egypt). Previously, he worked for Amoco and was involved in international operations in many different countries. Mr. Joyce received his bachelor’s degree in accounting from Texas A&M University.

Mr. Joyce was selected to serve on the Board due to his extensive experience in senior human resources leadership positions in the energy industry.

Thomas E. Long has served on the Board since April 2018. He has also served on the board of directors of the general partner of Sunoco LP since May 2016. Mr. Long was appointed the Chief Financial Officer of the general partner of ET LP following the merger of ETE and ETP in October 2018 and prior to the merger he was the Group Chief Financial Officer since February 2016. Mr. Long previously served as Chief Financial Officer of ETO’s general partner and as Executive Vice President and Chief Financial Officer of Regency Energy Partners LP’s general partner from November 2010 to April 2015. From May 2008 to November 2010, Mr. Long served as Vice President and Chief Financial Officer of Matrix Service Company. Prior to joining Matrix, he served as Vice President and Chief Financial Officer of DCP Midstream, a publicly traded natural gas and natural gas liquids midstream business company located in Denver, Colorado. In that position, he was responsible for all financial aspects of the company since its formation in December 2005. From 1998 to 2005, Mr. Long served in several executive positions with subsidiaries of Duke Energy Corp., one of the nation’s largest electric power companies. Mr. Long has a Bachelor of Arts in Accounting and is a Certified Public Accountant.

Mr. Long was selected to serve on the Board because of his understanding of energy-related corporate finance gained through his extensive experience in the energy industry.

Thomas P. Mason has served on the Board since April 2018. Mr. Mason was appointed Executive Vice President, General Counsel & President – LNG of LE GP after the merger of ETE and ETP in October 2018. Prior to the merger he was Executive Vice President and General Counsel of the general partner of ETE. Mr. Mason previously served as Senior Vice President, General Counsel and Secretary of ETO’s general partner from April 2012 to December 2015, as

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Vice President, General Counsel and Secretary from June 2008 and as General Counsel and Secretary from February 2007. Prior to joining Energy Transfer, he was a partner in the Houston office of Vinson & Elkins L.L.P. Mr. Mason has specialized in securities offerings and mergers and acquisitions for more than 25 years. Mr. Mason also previously served on the Board of Directors of the general partner of Sunoco Logistics Partners L.P.

Mr. Mason was selected to serve on the Board because of his decades of legal experience in securities, mergers and acquisitions and corporate governance in the energy sector.

Matthew S. Ramsey has served on the Board since April 2018. Mr. Ramsey has also served on the board of directors of the general partner of SUN since August 2014, and as the chairman of the board of directors of the general partner of SUN since April 2015. Mr. Ramsey is the Chief Operating Officer and director of ET LP’s general partner and has served in that capacity since the completion of the merger of ETE and ETP in October 2018. Mr. Ramsey served as President and Chief Operating Officer of ETO’s general partner from November 2015 until the merger between ETE and ETP in October 2018. Mr. Ramsey has served on the board of directors of the general partner of ETO since July 2012. Mr. Ramsey served as President and Chief Operating Officer and Chairman of the board of directors of PennTex Midstream Partners, LP’s general partner from November 2016 until ETP completed its acquisition of PennTex in June 2017. Prior to joining Energy Transfer in November 2015, Mr. Ramsey served as president of Houston-based RPM Exploration Ltd., a private oil and gas exploration partnership generating and drilling 3-D seismic prospects on the Gulf Coast of Texas. Mr. Ramsey is currently a director of RSP Permian, Inc. (NYSE: RSPP), where he serves as chairman of the compensation committee and as a member of the audit committee. Mr. Ramsey formerly served as President of DDD Energy, Inc. until its sale in 2002. From 1996 to 2000, Mr. Ramsey served as President and Chief Executive Officer of OEC Compression Corporation, Inc., a publicly traded oil field service company, providing gas compression services to a variety of energy clients. Mr. Ramsey holds a B.B.A. in Marketing from the University of Texas at Austin and a J.D. from South Texas College of Law. Mr. Ramsey is a graduate of the Harvard Business School Advanced Management Program. Mr. Ramsey is licensed to practice law in the State of Texas. He is qualified to practice in the Western District of Texas and the United States Court of Appeals for the Fifth Circuit. Mr. Ramsey formerly served as a director of Southern Union Company.

Mr. Ramsey was selected to serve on the Board in recognition of his vast knowledge of the energy space and valuable industry, operational and management experience.

William S. Waldheim has served on the Board since April 2018. Mr. Waldheim served as a director and a member of the Audit, Finance & Risk Committee of Enbridge Energy Company, Inc. and Enbridge Energy Management, L.L.C. from February 2016 through December 2018. He previously served as President of DCP Midstream where he had overall responsibility for DCP Midstream’s affairs including commercial, trading and business development until his retirement in 2015. Prior to this, Mr. Waldheim was President of Midstream Marketing and Logistics for DCP Midstream and managed natural gas, crude oil and natural gas liquids marketing and logistics. From 2005 to 2008, he was Group Vice President of Commercial for DCP Midstream, managing its upstream and downstream commercial business. Mr. Waldheim started his professional career in 1978 with Champlin Petroleum as an auditor and financial analyst and served in roles involving NGL and crude oil distribution and marketing. He served as Vice President of NGL and Crude Oil Marketing for Union Pacific Fuels from 1987 until 1998 at which time it was acquired by DCP Midstream.

Mr. Waldheim was selected to serve on the Board because of his broad and extensive experience in senior leadership roles in the energy industry and his financial and accounting expertise.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires that the members of the Board, our executive officers and persons who own more than 10 percent of a registered class of our equity securities file initial reports of ownership and reports of changes in ownership of our common units and other equity securities with the SEC and any exchange or other system on which such securities are traded or quoted. SEC regulations also require that the members of the Board, our executive officers and persons who own greater than 10 percent of a registered class of our equity securities furnish to us and any exchange or other system on which such securities are traded or quoted copies of all Section 16(a) forms they have filed with the SEC. To our knowledge and based solely on a review of the copies of such reports furnished to us, we believe

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that all reporting obligations of the members of the Board, our executive officers and greater than 10 percent unitholders under Section 16(a) were satisfied during the year ended December 31, 2018.

Common Unit Ownership by Directors and Executive Officers

We encourage our directors and executive officers to invest in and retain ownership of our common units, but we do not require such individuals to establish and maintain a particular level of ownership.

Reimbursement of Expenses of the General Partner

The General Partner does not receive any management fee or other compensation for its management of us, but we reimburse the General Partner and its affiliates for all expenses incurred on our behalf, including the compensation of employees of the General Partner or its affiliates that perform services on our behalf. These expenses include all expenditures necessary or appropriate to the conduct of our business and that are allocable to us. The Second Amended and Restated Agreement of Limited Partnership of USA Compression Partners, LP (the “Partnership Agreement”) provides that the General Partner will determine in good faith the expenses that are allocable to us. There is no cap on the amount that may be paid or reimbursed to the General Partner or its affiliates for compensation or expenses incurred on our behalf.

ITEM 11.Executive Compensation

As is commonly the case with publicly traded limited partnerships, we have no officers, directors or employees. Under the terms of the Partnership Agreement, we are ultimately managed by the General Partner, which is controlled by Energy Transfer. All of our employees, including our executive officers, are employees of USA Compression Management Services, LLC (“USAC Management”), a wholly owned subsidiary of the General Partner. References to “our officers” and “our directors” refer to the officers and directors of the General Partner.

Compensation Discussion & Analysis

Named Executive Officers

The following disclosure describes the executive compensation program for the named executive officers identified below (the “NEOs”). For the year ended December 31, 2018, the NEOs were:

| · |  | Eric D. Long, President and CEO;

| · |  | Matthew C. Liuzzi, Vice President, Chief Financial Officer and Treasurer;

| · |  | William G. Manias, Vice President and Chief Operating Officer;

| · |  | David A. Smith, Vice President and President, Northeast Region; and

| · |  | Sean T. Kimble, Vice President, Human Resources.

Compensation Philosophy and Objectives

Since our initial public offering in 2013, we have consistently based our compensation philosophy and objectives on the premise that a significant portion of each NEO’s total compensation should be incentive-based or “at-risk” compensation. We share Energy Transfer’s philosophy that the NEOs’ total compensation levels should be competitive in the marketplace for executive talent and abilities. The Compensation Committee generally targets at or near the 50th percentile of the market for the three main components of our compensation program: base salary, annual discretionary cash bonus and long-term equity incentive awards. The Compensation Committee believes the incentive-based balance is achieved by (i) the payment of annual discretionary cash bonuses that consider (a) the achievement of the financial performance objectives for a fiscal year set at the beginning of such fiscal year and (b) the individual contributions of each of the NEOs to our level of success in achieving the annual financial performance objectives, and (ii) the annual grant of time-based restricted phantom unit awards under the LTIP, which awards are intended to incentivize and retain our key employees for the long-term and motivate them to focus their efforts on increasing the market price of our common units and the level of cash distributions we pay to our common unitholders.

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The following charts illustrate the level of at-risk incentive compensation we awarded in 2018 to our CEO and, on an averaged basis, the other NEOs. “Variable/at-risk” compensation is comprised of long-term equity incentive awards and annual discretionary cash bonuses, and “fixed” compensation is comprised of base salary.

Our compensation program is structured to achieve the following:

| · |  | compensate executives with an industry-competitive total compensation package of competitive base salaries and significant incentive opportunities yielding a total compensation package at or near the 50th percentile of the market;

| · |  | attract, retain and reward talented executive officers and key members of management by providing a total compensation package competitive with those of their counterparts at similarly situated companies;

| · |  | motivate executive officers and key employees to achieve strong financial and operational performance;

| · |  | emphasize performance-based or “at risk” compensation; and

| · |  | reward individual performance.

Methodology to Setting Compensation Packages

Our executive compensation program is administered by the Compensation Committee. The Compensation Committee considers market trends in compensation, including the practices of identified competitors, and the alignment of the compensation program with the Partnership’s strategy. Specifically, for the NEOs, the Compensation Committee:

| · |  | establishes and approves target compensation levels for each NEO;

| · |  | approves Partnership performance measures and goals;

| · |  | determines the mix between cash and equity compensation, short-term and long-term incentives and benefits;

| · |  | verifies the achievement of previously established performance goals; and

| · |  | approves the resulting cash or equity awards to the NEOs.

The Compensation Committee also considers other factors such as the role, contribution and performance of an individual relative to his or her peers at the Partnership. The Compensation Committee does not assign specific weight to these factors, but rather makes a subjective judgment taking all of these factors into account.

The Compensation Committee reviews and approves all compensation for the NEOs. In determining the compensation for the NEOs, the Compensation Committee takes into account input from the CEO for the compensation of the other NEOs. The CEO considers comparative compensation data and evaluates the individual performance of each NEO and their respective contributions to the Partnership. The recommendations are then reviewed by the Compensation Committee, which may accept the recommendations or make adjustments to the recommended compensation based on

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the Compensation Committee’s assessment of the individual’s performance and contributions to the Partnership. The CEO’s compensation is reviewed and approved by the Compensation Committee based on comparative compensation data and the Compensation Committee’s independent evaluation of the CEO’s contributions to the Partnership’s performance.

Periodically, we engage a third-party consultant to provide the Compensation Committee with market information about compensation levels at peer companies to assist in setting compensation levels for our executives, including the NEOs. In 2016, the Compensation Committee engaged Longnecker & Associates (“Longnecker”) to assist the Compensation Committee in determining appropriate compensation levels for senior management, including the NEOs, by: (i) providing market information for compensation levels at peer companies; (ii) evaluating the market competitiveness of our total compensation levels; and (iii) confirming that our compensation program is yielding compensation packages consistent with our overall compensation philosophy. The compensation analysis provided by Longnecker in 2016 (the “2016 Longnecker Report”) covered all major components of total compensation, including annual base salary, annual short-term cash bonus and long-term equity incentive awards for the NEOs as compared to executives at similarly situated companies in terms of industry, annual revenue and market capitalization.

The Compensation Committee also benchmarked results for the annual base salary, annual short-term cash bonus and long-term equity incentive awards of the NEOs against data for compensation levels for specific executive positions reported in published executive compensation surveys within each of the (i) energy industry and (ii) overall market. The Compensation Committee also reviewed publicly filed peer group executive compensation disclosures pertaining to certain executive roles, but because of limited sample size due to the relatively small number of publicly traded natural gas compression companies, the Compensation Committee used this data as a reference point rather than a primary data source.

On November 2, 2017, the Compensation Committee determined that the 2016 Longnecker Report was completed recently enough to be utilized in setting 2018 compensation levels for the NEOs, and consulted the 2016 Longnecker Report, adjusted to account for general inflation and other relevant information obtained from other sources, such as 2018 third party survey results, in its determination of compensation levels for 2018 for our executives, including the NEOs.

In light of the Transactions and resulting increased size of the Partnership and greater level of responsibility for each of the NEOs, in May 2018 the Compensation Committee again engaged Longnecker, who is also the independent compensation advisor to Energy Transfer, to provide an updated targeted market review and benchmarking for certain members of our senior leadership team (the “2018 Longnecker Report”). The Compensation Committee relied on the results of the 2018 Longnecker Report for determinations of base salary and bonus and long-term equity incentive targets for 2019 for the NEOs.

In connection with its engagement of Longnecker, based on the information presented to it, the Compensation Committee assessed the independence of Longnecker under applicable SEC and NYSE rules and concluded that Longnecker’s work for the Compensation Committee did not raise any conflict of interest for 2018.

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Our 2018 peer group selected by the Compensation Committee in consultation with Longnecker included the following companies:

Company | Ticker
1. American Midstream Partners, LP | AMID
2. Archrock, Inc. | AROC
3. Buckeye Partners, L.P. | BPL
4. Crestwood Equity Partners LP | CEQP
5. Enlink Midstream, LLC | ENLC
6. EQT Midstream Partners, LP | EQM
7. Exterran Corporation | EXTN
8. Genesis Energy, L.P. | GEL
9. Martin Midstream Partners L.P. | MMLP
10. SemGroup Corporation | SEMG
11. Summit Midstream Partners, LP | SMLP
12. MPLX LP | MPLX
13. Tallgrass Energy Partners, LP | TEP
14. TETRA Technologies, Inc. | TTI

Elements of the Compensation Program

Compensation for the NEOs consists primarily of the following elements and corresponding objectives:

Compensation Element |  | Primary Objective
Base salary |  | To recognize performance of job responsibilities and to attract and retain individuals with superior talent.
Annual incentive compensation |  | To promote near-term performance objectives and reward individual contributions to the achievement of those objectives.
Long-term equity incentive awards |  | To emphasize long-term performance objectives, encourage the maximization of unitholder value and retain key executives by providing an opportunity to participate in the ownership of the Partnership.
Retirement savings (401(k)) plan |  | To provide an opportunity for tax-efficient savings.
Other elements of compensation and perquisites |  | To attract and retain talented executives in a cost-efficient manner by providing benefits comparable to those offered by similarly situated companies.

Base Salary for 2018 and 2019

Base salaries for the NEOs have generally been set at a level deemed necessary to attract and retain individuals with superior talent. Base salary increases are determined based upon the job responsibilities, demonstrated proficiency and performance of the NEO and market conditions. In connection with determining base salaries for each of the NEOs for 2018, the Compensation Committee and CEO utilized the 2016 Longnecker Report to determine comparable salaries for such executive roles within our peer group.

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Following the Transactions, the Compensation Committee in consultation with Longnecker, and in consideration of the available compensation data, determined that three of the NEOs’ 2018 salaries were at appropriate levels for 2019, and adjusted two of the NEOs’ base salaries for 2019.

The 2018 and current 2019 base salaries for the NEOs, including our CEO, are set forth in the following table:

|  | 2018 Base Salary |  | Current 2019 Base Salary
Name and Principal Position |  | ($) |  | ($)
Eric D. Long, President and Chief Executive Officer |  | 644,709 |  | 644,709
Matthew C. Liuzzi, Vice President, Chief Financial Officer and Treasurer |  | 387,239 |  | 400,000
William G. Manias, Vice President and Chief Operating Officer |  | 437,092 |  | 437,092
David A. Smith, Vice President and President, Northeast Region |  | 502,357 |  | 517,428
Sean T. Kimble, Vice President, Human Resources |  | 307,670 |  | 307,670

Annual Cash Incentive Compensation for 2018

The Board previously approved the USA Compression Partners, LP Annual Cash Incentive Program (the “Bonus Plan”). Each of the NEOs is entitled to participate in the Bonus Plan and their potential bonus is governed by the Bonus Plan and, for Messrs. Smith and Kimble, also governed by their respective employment agreements. The Compensation Committee acts as the administrator of the Bonus Plan under the supervision of the full Board, and has the discretion to amend, modify or terminate the Bonus Plan at any time. Although for 2018 the Bonus Plan utilized both Partnership and individual performance goals to assist in determining bonus amounts, the Bonus Plan is ultimately a discretionary annual bonus plan and awards are therefore reported in the “Bonus” column within the Summary Compensation Table below.

For the year ended December 31, 2018, the Compensation Committee set a target bonus amount (the “Target Bonus”) for each NEO prior to the first quarter of the year, which was set as a percentage of the NEO’s base salary. For the bonus applicable to the year ended December 31, 2018, the Target Bonus, as a percentage of base salary and as a dollar amount, is reflected in the table below.

|  | Percentage of |  | Amount
Name |  | Base Salary |  | ($)
Eric D. Long |  | 100% |  | 644,709
Matthew C. Liuzzi |  | 75% |  | 290,429
William G. Manias |  | 80% |  | 349,674
David A. Smith |  | 60% |  | 301,346
Sean T. Kimble |  | 70% |  | 215,369

The Target Bonus for 2018 was generally subject to the satisfaction of both a Partnership performance goal (accounting for 75% of the Target Bonus) and an individual performance goal (accounting for 25% of the Target Bonus). Prior to 2018, seventy-five percent (75%) of the Target Bonus was subject to the Partnership’s achievement of its budgeted distributable cash flow (“DCF”) target for the year. For the year ended December 31, 2018, because the Partnership’s predecessor for financial reporting purposes, the USA Compression Predecessor, did not historically calculate DCF on a basis directly comparable to the Partnership’s calculation of DCF, the Compensation Committee determined that seventy-five percent (75%) of the Target Bonus would be instead subject to the Partnership’s achievement of its budgeted Adjusted EBITDA target, as determined by the Compensation Committee. Additionally, because the Transactions closed on April 2, 2018, and prior to that Partnership management had no oversight of or involvement with the USA Compression Predecessor, the Compensation Committee determined that only the second, third and fourth quarters of 2018 (together, the “2018 Bonus Period”) would be considered when determining whether the Adjusted EBITDA target had been met. For the bonus applicable to 2018, the Compensation Committee determined that, as with the previous DCF target, payouts with respect to the portion of the bonus determined by Adjusted EBITDA (the “Adjusted EBITDA Bonus”) would not occur unless we satisfied the Adjusted EBITDA threshold, which was set at 80% of the Partnership’s budgeted Adjusted EBITDA target. For the 2018 Bonus Period, the Compensation Committee set the budget for Adjusted EBITDA at $278.8 million. The threshold, target and maximum requirements for the Adjusted EBITDA target for the 2018 Bonus Period, as well as the portion of the Adjusted EBITDA Bonus that could

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become payable if Adjusted EBITDA performance was satisfied for the 2018 Bonus Period at such levels, are set forth below.

|  | Adjusted EBITDA as a |  | Percentage of |
|  | Percentage of |  | Adjusted EBITDA |
Levels of |  | Budgeted Adjusted |  | Bonus that would |
Adjusted EBITDA Bonus |  | EBITDA for 2018 Bonus Period |  | be Paid |
Threshold |  | 80% |  | 50% |
Target |  | 100% |  | 100% |
Maximum |  | 110% |  | 200% |

For 2018, if Adjusted EBITDA performance for the 2018 Bonus Period fell in between threshold and target, or between target and maximum levels, the amounts payable would be adjusted ratably using straight line interpolation. If Adjusted EBITDA was achieved above maximum levels, the potential payment of the Adjusted EBITDA Bonus was capped at the maximum level of 200%.

For the year ended December 31, 2018, the remaining twenty-five percent (25%) of the Target Bonus was determined by the satisfaction of individual objectives specific to each NEO’s role (the “Individual Bonus”). The individual objectives were agreed upon in advance between the NEO and the CEO (or, with respect to the CEO, between the Compensation Committee and the CEO) and such objectives addressed the key priorities for that NEO’s position. For the year ended December 31, 2018, the Individual Bonus objectives included key operating goals as well as personal development criteria. For the year ended December 31, 2018, the Individual Bonus was subject to a maximum payout of 100% of the targeted Individual Bonus amount, although the Compensation Committee retained sole discretion to determine to pay out smaller amounts ranging from 0% to 100% after analyzing the NEO’s personal performance for the year. In connection with the Individual Bonus for the year ended December 31, 2018, each of the NEOs met with the CEO (or, in the case of the CEO, the Compensation Committee) to set individual objectives that reflected the responsibilities and priorities of their respective positions.

For the year ended December 31, 2018, in the aggregate, the maximum amount payable with respect to a Target Bonus under the Bonus Plan was 175%, as the Adjusted EBITDA Bonus was capped at 200% of target and the Individual Bonus was 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 financial statements for the year to which the Target Bonus relates, but in any case no later than March 15 of the year following the year to which the Target Bonus relates. For the 2018 Bonus Period, Adjusted EBITDA exceeded the target level by 3.60%, which resulted in the Adjusted EBITDA Bonus (comprising seventy-five percent of the overall Target Bonus) being paid to each NEO at the rate of 136.0%. With respect to the Individual Bonus portion of the overall Target Bonus, the CEO (or in the case of the CEO, the Compensation Committee (based on the recommendation of management)) determined that each NEO satisfied his individual objectives and therefore was entitled to receive 100% of the Individual Bonus. The awards made pursuant to the Bonus Plan with respect to the year ended December 31, 2018 were:

Name |  |  | Bonus
Eric D. Long |  | $ | 818,597
Matthew C. Liuzzi |  | $ | 368,763
William G. Manias |  | $ | 443,986
David A. Smith |  | $ | 382,710
Sean T. Kimble |  | $ | 273,457

Annual Cash Incentive Compensation for 2019

In February 2019, the Compensation Committee approved the USA Compression Partners, LP Amended and Restated Annual Cash Incentive Plan (the “A&R Bonus Plan”), which is effective beginning with respect to fiscal year 2019 and makes several modifications to the Partnership’s annual cash incentive program. The Compensation Committee will make determinations whether to make discretionary annual cash bonus awards to executives attributable to 2019, including the NEOs, under the A&R Bonus Plan following the year ended December 31, 2019. The A&R Bonus Plan contains four payout factors and corresponding percentages that comprise the total annual target bonus for all

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eligible employees, including our named executive officers (the “Annual Target Bonus Pool”): (i) the Adjusted EBITDA Budget Target Factor (the “Adjusted EBITDA Factor”): 30%; (ii) the Distributable Cash Flow Budget Target Payout Factor (the “DCF Factor”): 30%; (iii) the Leverage Ratio Budget Target Factor (the “Leverage Ratio Factor”): 30% and (iv) the Safety Budget Target Payout Factor (the “Safety Factor”): 10%.

Each of the Adjusted EBITDA Factor and DCF Factor assign payout factors from 0% to 120% based on the percentage of the Partnership’s budgeted Adjusted EBITDA and DCF, respectively, achieved for the year, as shown in the following chart.

Adjusted EBITDA and DCF Factors
% of Budget Target |  | Bonus Pool Payout Factor
Greater than or equal to 110% |  | 1.20x
109.9%-105.0% |  | 1.10x
104.9%-95.0% |  | 1.00x
94.9%-90.0% |  | 0.90x
89.9%-80.0% |  | 0.75x
Less than 80.0% |  | 0.00x

The Leverage Ratio Factor assigns payout factors based on the Partnership’s achievement of its budgeted Leverage Ratio (as defined in the Partnership’s Sixth Amended and Restated Credit Agreement, provided that, for the purposes of calculating the Leverage Ratio for the A&R Bonus Plan, EBITDA attributable to the full plan year shall be used in lieu of any other time period) for the year, as shown in the following chart.

Leverage Ratio Factor
Range within Budget Target |  | Bonus Pool Payout Factor
More than 0.250 below budget target |  | 1.20x
0.250-0.125 below |  | 1.10x
0.124 below-0.125 above |  | 1.00x
0.126-0.375 above |  | 0.70x
0.376-0.500 above |  | 0.50x
Greater than 0.500 above |  | 0.00x

The Safety Factor assigns payout factors based on the Partnership’s Total Recordable Incident Rate, or TRIR (as calculated by the U.S. Occupational Safety and Health Administration) against the Partnership’s TRIR target, as shown in the following chart.

Safety Factor
% of Target |  | Bonus Pool Payout Factor
Less than 100% |  | 1.00x
100%-105% |  | 0.90x
105.1%-110% |  | 0.80x
110.1%-115% |  | 0.70x
115.1%-125% |  | 0.60x
Greater than 125% |  | 0.00x

The establishment and amount of the Funded Bonus Pool is 100% discretionary and subject to approval and/or adjustment by the Compensation Committee. In determining bonuses for the NEOs, the Compensation Committee takes into account whether the Partnership achieved or exceeded its targeted performance objectives. In the case of the NEOs, their bonus pool targets range from 60% to 125% of their respective annual base earnings (which amount reflects the actual base salary earned during the calendar year to reflect periods before and after any base salary adjustment). For 2019, the annual cash bonus pool targets for the NEOs are as follows: for Mr. Long, 125%; for Mr. Liuzzi, 105%; for Mr. Manias, 100%; for Mr. Smith, 60%; and for Mr. Kimble, 70%. The annual cash bonus pool targets for 2019 are

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based on the determination of the Compensation Committee in consultation with Longnecker, and in consideration of the available compensation data and internal compensation levels within Energy Transfer.

Long-Term Equity Incentive Awards

The Board adopted the LTIP, which is designed to promote our interests, as well as the interests of our unitholders, by rewarding our officers, directors and certain of our employees for delivering desired performance results, as well as by strengthening our ability to attract, retain and motivate qualified individuals to serve as officers, directors and employees. The LTIP provides for the grant, from time to time at the discretion of the Board, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights (“DERs”) and other common unit-based awards, although since our initial public offering in 2013 the Board has only granted awards of phantom units with DERs under the LTIP. The outstanding, unvested phantom units granted under the LTIP and held by the NEOs are reflected below in “—Outstanding Equity Awards as of December 31, 2018.”

During 2018, the Board granted phantom unit awards to certain key employees, including the NEOs. With respect to the annual awards granted under the LTIP in February of each of 2016, 2017 and 2018, twenty percent (20%) of the phantom units awarded to each individual were subject to a performance-based vesting formula (the “Performance Units”) and the remaining eighty percent (80%) of the phantom units were subject to time-based vesting restrictions (the “Standard Units”).

Performance Units granted prior to the Transactions were scheduled to vest (i) based upon our level of total unitholder return (“TUR”) relative to a group of peer companies over a certain period of time or (ii) immediately prior to a “Change in Control.” As the Transactions constituted a “Change in Control,” all outstanding Performance Units vested on the Transactions Date, including those Performance Units granted in February of 2018. Since we have not granted any Performance Units subsequent to the awards granted in February 2018, there are currently no Performance Units outstanding under the LTIP. The Standard Units granted to our CEO were also accelerated in connection with the Transactions pursuant to the terms of his then-current LTIP award agreements, but the other NEOs continue to hold outstanding Standard Units granted prior to the Transactions that have not vested pursuant to time-based vesting in the ordinary course. See “Units Vested During the Year Ended December 31, 2018” below. Standard Units that were granted prior to July 30, 2018 vest in three equal annual installments, with the first installment vesting February 15 of the year following the grant.

The target level of annual long-term incentive awards for each of the NEOs is expressed as a percentage of the NEO’s base salary. In 2016, the Compensation Committee, in consultation with Longnecker, set the individual long-term incentive target percentages for the NEOs, and the Compensation Committee did not make any changes to those individual long-term incentive target percentages for the NEOs during 2017 or for the grants in 2018 that occurred prior to the Transactions. The following table shows each NEO’s long-term incentive target for 2018 prior to the Transactions (expressed as a percentage of base salary).

Pre-Transactions Long-Term Incentive Target Amounts |  |  |  |
|  | Percentage of |  | Amount
Name |  | Base Salary |  | ($)
Eric D. Long |  | 300% |  | 1,934,127
Matthew C. Liuzzi |  | 200% |  | 774,478
William G. Manias |  | 225% |  | 983,457
David A. Smith |  | 70% |  | 351,650
Sean T. Kimble |  | 175% |  | 538,423

On November 1, 2018, the Board adopted a new form of employee phantom unit award agreement under the LTIP (the “New Award Agreement”) to bring our long-term equity incentive compensation program in line with Energy Transfer’s practices. The New Award Agreement (i) alters the vesting schedule of Standard Units from three equal annual installments to incremental vesting over five years (60% on the third December 5 following the grant and 40% on the fifth December 5 following the grant) and (ii) provides for vesting of 100% of the outstanding, unvested Standard Units in the event of a Change in Control (as defined under the LTIP and set forth below under “Potential Payments upon Termination or Change in Control”).

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In determining the level of the December 2018 grants of Standard Units to the NEOs, the Compensation Committee, in consultation with Longnecker and taking into account internal compensation levels within Energy Transfer, determined to modify certain of the NEOs’ long-term incentive targets, as shown in the following table:

Post-Transactions Long-Term Incentive Target Amounts |  |  |  |
|  | Percentage of |  | Amount
Name |  | Base Salary |  | ($)
Eric D. Long |  | 400% |  | 2,578,836
Matthew C. Liuzzi |  | 250% |  | 1,000,000
William G. Manias |  | 225% |  | 983,457
David A. Smith |  | 97% |  | 500,000
Sean T. Kimble |  | 175% |  | 538,423

Under the LTIP, the Compensation Committee has the discretion to determine whether any portion of phantom units should be settled in cash upon vesting for the purpose of conserving common units approved for issuance under the LTIP. For the awards made in February 2018, the Compensation Committee recommended to the Board, and on February 9, 2018 the Board approved, the default settlement method for phantom units of 50% in cash (valued based on the closing price on the NYSE of the Partnership’s common units on the date of vesting) and 50% in common units. However, the Board also specified that if an employee affirmatively requests in writing that the percentage of cash settlement be set at a specific amount that is less than 50% (and such employee agrees to pay out of his or her own funds the amount of any required federal withholding to the extent that the cash portion is insufficient for the Partnership to withhold and pay such amounts on the employee’s behalf), the Board approves in advance such lesser cash settlement percentage.

Each phantom unit granted to an employee, including the NEOs, is granted in tandem with a corresponding DER, which entitles the recipient to receive an amount in cash on a quarterly basis equal to the product of (a) the number of phantom units granted to the grantee that remain outstanding and unvested as of the record date for the distribution on the Partnership’s common units for such quarter and (b) the quarterly distribution with respect to the Partnership’s common units. With respect to Performance Units, DERs were granted for the target number of underlying common units and were not adjusted up or down depending on actual performance results.

Awards granted pursuant to the LTIP are subject to certain clawback features, and the award may not vest or settle if we determine that the recipient committed certain acts of misconduct, as more particularly described in the LTIP.

Benefit Plans and Perquisites

We provide the NEOs with certain personal benefits and perquisites, which we do not consider to be a significant component of our overall executive compensation program but which we recognize are an important factor in attracting and retaining talented executives. The NEOs are eligible under the same plans as all other employees with respect to our medical, dental, vision, disability and life insurance benefits and a defined contribution plan that is tax-qualified under Section 401(k) of the Internal Revenue Code (the “401(k) Plan”). In addition, we currently provide one or more NEOs with (i) an annual automobile allowance; (ii) additional life insurance coverage; (iii) club memberships; and (iv) personal administrative support. The Compensation Committee has determined it is appropriate to offer these perquisites in order to provide compensation opportunities competitive with those offered by similarly situated public companies. In determining the compensation payable to the NEOs, the Compensation Committee considers perquisites in the context of the total compensation the NEOs are eligible to receive. However, given the fact that perquisites represent a relatively small portion of the NEOs’ total compensation, the availability of these perquisites does not materially influence the Compensation Committee’s decision making with respect to other elements of the total compensation to which the NEOs are entitled or which they are awarded. The value of personal benefits and perquisites we provided to each of the NEOs in 2018 is set forth below in “—Summary Compensation Table.”

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Retention Phantom Unit Agreements

On November 1, 2018, the Compensation Committee approved the form of, and the Partnership entered into, a Retention Phantom Unit Agreement (collectively, the “Retention Agreements”) under the LTIP with each of Messrs. Long, Liuzzi and Manias, which provide for a grant of Standard Units (the “Retention Units”) in the following amounts: (i) 90,000 Retention Units to Mr. Long; (ii) 35,000 Retention Units to Mr. Liuzzi; and (iii) 45,000 Retention Units to Mr. Manias. The Retention Units will vest incrementally, with 60% of the Retention Units vesting on December 5, 2021 and 40% of the Retention Units vesting on December 5, 2023, subject in each case to the NEO’s continued employment with the Partnership. Each Retention Unit was granted with a corresponding DER.

The Compensation Committee approved the Retention Agreements in recognition of the importance of Messrs. Long, Liuzzi and Manias to the Partnership’s long-term success and to encourage their retention by providing additional time-based compensation. For additional information regarding the Retention Agreements, please see “—Potential Payments upon Termination or Change in Control—Retention Phantom Unit Agreements” below.

Employment Agreements

Each of Messrs. Smith and Kimble is party to an employment agreement with us (together, the “Employment Agreements”), each of which have been extended on a year-to-year basis and will be automatically extended for successive twelve month periods unless either party delivers written notice to the other at least 90 days prior to the end of the current employment term. The employment agreements with Messrs. Long, Liuzzi and Manias were terminated on November 1, 2018. Please see the description of the Employment Agreements under “Potential Payments upon Termination or Change in Control” for further details on the terms of the Employment Agreements.

Risk Assessment Related to Our Compensation Structure

We believe our compensation program for all of our employees, including the NEOs, is appropriately structured and not reasonably likely to result in material risk to us because it is structured in a manner that does not promote excessive risk-taking that could damage our reputation, negatively impact our financial results or reward poor judgment. We have also allocated our compensation among base salary and short and long-term compensation in such a way as to not encourage excessive risk-taking. Furthermore, all business groups and employees receive the same core compensation components of base pay and short-term incentives. We typically offer long-term equity incentives to employees at the director level or above, and we use phantom units rather than unit options for these equity awards because phantom units retain value even in a depressed market, so employees are less likely to take unreasonable risks to get or keep options “in-the-money.” Finally, the time-based vesting over three to five years for our long-term incentive awards ensures that our employees’ interests align with those of our unitholders with respect to our long-term performance.

Accounting and Tax Considerations

We account for the equity compensation expense for equity awards granted under our LTIP in accordance with U.S. generally accepted accounting principles, which requires us to estimate and record an expense for each equity award over the vesting period of the award. Standard Units are accounted for as a liability and are re-measured at fair value at the end of each reporting period using the market price of the Partnership’s common units. Fair value for Performance Units was determined using a Monte Carlo simulation model, which incorporated a number of factors in its valuation, including the vesting period, the expected price volatility of the Partnership’s common units, expected distributions and the risk free interest rate. Phantom units granted to independent directors do not have a cash settlement option; therefore we account for these awards as equity. During the requisite service period, compensation cost is recognized using the proportionate amount of the award’s fair value that has been earned through service to date.

Because we are a partnership and the General Partner is a limited liability company, Section 162(m) of the Internal Revenue Code (the “Code”) does not apply to the compensation paid to the NEOs and, accordingly, the Compensation Committee did not consider its impact in making the compensation recommendations discussed above.

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Compensation Committee Interlocks and Insider Participation

We do not have any Compensation Committee interlocks. Messrs. Joyce and Waldheim are the only members of the Compensation Committee, and during 2018 neither Mr. Joyce nor Mr. Waldheim was an officer or employee of Energy Transfer or any of its affiliates, or served as an officer of any company with respect to which any of our executive officers served on such company’s board of directors. In addition, neither Mr. Joyce nor Mr. Waldheim is a former employee of Energy Transfer or any of its affiliates.

Compensation Committee Report

The Compensation Committee has reviewed and discussed the section of this report entitled “Compensation Discussion and Analysis” with management of the Partnership and approved its inclusion in this Annual Report on Form 10-K.

Compensation Committee

Glenn E. Joyce (Chairman)

William S. Waldheim

The foregoing report shall not be deemed to be incorporated by reference by any general statement or reference to this Annual Report on Form 10-K into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act, as amended, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under those Acts.

Summary Compensation Table

Since our initial public offering (“IPO”) in 2013, we have been considered an “emerging growth company” (“EGC”) under the Jumpstart Our Business Startups Act. As an EGC we were only required to disclose compensation information for our three most highly compensated individuals, compared to five individuals as is required of companies that do not qualify for reduced disclosure requirements. We ceased to be an EGC on December 31, 2018. Since 2018 is the first fiscal year for which we are required to disclose compensation information for five NEOs, the following table provides a summary of the compensation paid to (i) three NEOs for the years ended December 31, 2018, 2017 and 2016 and (ii) five NEOs for the year ended December 31, 2018.

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Summary Compensation Table

|  |  |  |  |  |  |  |  |  | All Other |  |
|  |  |  |  |  |  |  | Unit Awards |  | Compensation |  |
Name and Principal Position |  | Year |  | Salary ($) |  | Bonus ($) (1) |  | ($) (2) |  | ($) |  | Total ($)
Eric D. Long |  | 2018 |  | 644,709 |  | 818,597 |  | 5,942,922 |  | 322,176 | (3) | 7,728,404
President and Chief Executive Officer |  | 2017 |  | 625,233 |  | 721,436 |  | 1,953,127 |  | 755,233 |  | 4,055,029
|  | 2016 |  | 607,109 |  | 773,419 |  | 1,892,893 |  | 742,412 |  | 4,015,833
Matthew C. Liuzzi |  | 2018 |  | 387,239 |  | 368,763 |  | 2,331,734 |  | 261,277 | (4) | 3,349,013
Vice President, Chief Financial Officer and Treasurer |  | 2017 |  | 375,538 |  | 329,496 |  | 782,050 |  | 313,209 |  | 1,800,293
|  | 2016 |  | 362,885 |  | 381,399 |  | 852,693 |  | 306,589 |  | 1,903,566
William G. Manias |  | 2018 |  | 437,092 |  | 443,986 |  | 2,682,754 |  | 323,631 | (5) | 3,887,463
Vice President and Chief Operating Officer |  | 2017 |  | 423,886 |  | 396,711 |  | 993,108 |  | 389,700 |  | 2,203,405
|  | 2016 |  | 411,538 |  | 416,353 |  | 1,069,430 |  | 380,616 |  | 2,277,937
David A. Smith |  | 2018 |  | 502,357 |  | 382,710 |  | 879,243 |  | 136,049 | (6) | 1,900,359
Vice President and President, Northeast Region |  |  |  |  |  |  |  |  |  |  |  |
Sean T. Kimble |  | 2018 |  | 307,670 |  | 273,457 |  | 1,105,336 |  | 176,784 | (7) | 1,863,247
Vice President, Human Resources |  |  |  |  |  |  |  |  |  |  |  |

| (1) |  | Represents the awards earned under the Bonus Plan for the years ended December 31, 2018, 2017 and 2016 for Messrs. Long, Liuzzi and Manias, and for the year ended December 31, 2018 for Messrs. Smith and Kimble. For a discussion of the determination of the 2018 bonus amounts, see “—Annual Cash Incentive Compensation for 2018” above.

| (2) |  | On February 12, 2018, February 13, 2017 and February 11, 2016, each of the NEOs received an award of phantom units comprised of Standard Units and Performance Units under the LTIP. Each phantom unit is the economic equivalent of one common unit, although the Performance Units were eligible to vest at up to 200% of target levels three years after grant, depending on the level of achievement of certain performance goals over the performance period. The phantom unit values reflect the grant date fair value of the awards calculated in accordance with t he Financial Accounting Standards Board’s (“FASB”) Accounting Standard Codification (“ASC”) Topic 718, disregarding the estimated likelihood of forfeitures. For a discussion of the assumptions utilized in determining the fair value of these awards, please see Note 15 to our consolidated financial statements. Fair value for the Performance Units was determined using a Monte Carlo simulation model, which incorporated a number of factors in its valuation including the vesting periods of our awards, the expected volatility of our units, expected dividends and the risk free interest rate. In connection with the closing of the Transactions, on the Transactions Date all outstanding, unvested Performance Units vested at 100% of the target level pursuant to the terms of the applicable LTIP award agreements because the Transactions constituted a Change in Control under the LTIP. The value of the Performance Units at vesting was over 25% less than the grant date fair value of the Performance Units reported in this table, as anticipated accelerated vesting in connection with a change in control was not factored into the valuation of the Performance Units under FASB ASC Topic 718. Please see the “Units Vested during the Year Ended December 31, 2018” table below for the actual value realized upon vesting of the Performance Units. In addition, all of Mr. Long’s outstanding, unvested Standard Units vested on the Transactions Date pursuant to the terms of Mr. Long’s LTIP award agreements in effect at the time.

| (3) |  | Includes: (i) $267,728 of DERs; (ii) $18,000 of automobile allowance; (iii) $13,750 of employer contributions under the 401(k) Plan; (iv) $3,897 of parking; (v) $9,623 of club membership dues; and (vi) $9,178 of personal administrative assistant support. Please see a description of the DERs under “—Long-Term Equity Incentive Awards” above.

| (4) |  | Includes: (i) $247,828 of DERs; and (ii) $13,449 of employer contributions under the 401(k) Plan.

| (5) |  | Includes: (i) $313,391 in DERs; and (ii) $10,240 of employer contributions under the 401(k) Plan.

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| (6) |  | Includes: (i) $101,654 of DERs; (ii) $9,960 of automobile allowance; (iii) $13,750 of employer contributions under the 401(k) Plan; (iv) $6,000 of club membership dues; and (v) $4,685 of life insurance premiums.

| (7) |  | Includes: (i) $160,015 of DERs; (ii) $13,716 of employer contributions under the 401(k) Plan; and (iii) $3,053 for parking.

Grants of Plan-Based Awards during the Year Ended December 31, 2018

The below reflects awards granted to our NEOs under the LTIP during 2018.

|  |  |  |  |  |  |  |  |  | Grant
|  |  |  |  |  |  |  | All Other |  | Date
|  |  |  | Approval |  | Estimated Future Payouts Under |  | Unit |  | Fair
|  |  |  | Date of |  | Equity |  | Awards: |  | Value of
|  |  |  | Equity- |  | Incentive Plan Awards (1) |  | Number of |  | Unit
|  |  |  | Based |  | Threshold |  | Target |  | Maximum |  | Units |  | Awards
Name |  | Grant Date |  | Awards |  | (#) |  | (#) |  | (#) |  | (#) (2) |  | ($) (3)
Eric D. Long |  | 2/12/2018 |  | 11/3/2017 |  | 10,787 |  | 21,574 |  | 43,148 |  | 86,296 |  | 2,036,586
|  | 11/1/2018 |  | 11/1/2018 |  | — |  | — |  | — |  | 90,000 |  | 1,327,500
|  | 12/5/2018 |  | 11/1/2018 |  | — |  | — |  | — |  | 176,874 |  | 2,578,836
Matthew C. Liuzzi |  | 2/12/2018 |  | 11/3/2017 |  | 4,319 |  | 8,639 |  | 17,278 |  | 34,554 |  | 815,484
|  | 11/1/2018 |  | 11/1/2018 |  | — |  | — |  | — |  | 35,000 |  | 516,250
|  | 12/5/2018 |  | 11/1/2018 |  | — |  | — |  | — |  | 68,587 |  | 1,000,000
William G. Manias |  | 2/12/2018 |  | 11/3/2017 |  | 5,485 |  | 10,970 |  | 21,940 |  | 43,879 |  | 1,035,549
|  | 11/1/2018 |  | 11/1/2018 |  | — |  | — |  | — |  | 45,000 |  | 663,750
|  | 12/5/2018 |  | 11/1/2018 |  | — |  | — |  | — |  | 67,452 |  | 983,455
David A. Smith |  | 2/12/2018 |  | 11/3/2017 |  | 2,008 |  | 4,017 |  | 8,034 |  | 16,070 |  | 379,243
|  | 12/5/2018 |  | 11/1/2018 |  | — |  | — |  | — |  | 34,293 |  | 500,000
Sean T. Kimble |  | 2/12/2018 |  | 11/3/2017 |  | 3,003 |  | 6,006 |  | 12,012 |  | 24,022 |  | 566,929
|  | 12/5/2018 |  | 11/1/2018 |  | — |  | — |  | — |  | 36,927 |  | 538,407

| (1) |  | The amounts in these columns show the range of potential payouts for the Performance Units at the time of grant by the Compensation Committee on February 12, 2018 pursuant to the LTIP. Fair value for the Performance Units was determined using a Monte Carlo simulation model, which incorporated a number of factors in its valuation including the vesting periods of our awards, the expected volatility of our units, expected dividends and the risk free interest rate. The Performance Units were scheduled to vest (i) on the third anniversary of the date of grant at between 0% and 200% of the granted number of Performance Units based upon our level of TUR relative to a group of peer companies; or (ii) immediately prior to a “Change in Control.” Pursuant to the terms of the applicable LTIP award agreements, the Performance Units granted on February 12, 2018 received accelerated vesting at target levels on the Transactions Date in connection with the Transactions, which constituted a Change in Control under the LTIP. The value of the Performance Units at vesting was over 25% less than the value of the Performance Units reported in this table, as anticipated accelerated vesting in connection with a change in control was not factored into the valuation of the Performance Units under FASB ASC Topic 718. Please see the “Units Vested during the Year Ended December 31, 2018” table below for the actual value realized upon vesting of the Performance Units.

| (2) |  | The Standard Units granted on February 12, 2018 will vest in three equal tranches beginning on February 15, 2019, except for the Standard Units granted to Mr. Long, which vested in full on the Transactions Date in connection with the Transactions pursuant to the terms of his LTIP award agreements in effect at the time. The Retention Units granted on November 1, 2018 to Messrs. Long, Liuzzi and Manias and the Standard Units granted on December 5, 2018 to all of the NEOs will vest incrementally, with 60% of the Retention Units and Standard Units vesting on December 5, 2021 and the remaining 40% of the Retention Units and Standard Units vesting on December 5, 2023. The Retention Units and the Standard Units granted on December 5, 2018 will also vest in full upon a Change in Control (as defined in the LTIP) or the death or Disability (as defined in the LTIP) of the NEO. If Mr. Long retires after attaining the age of 65, 60% of his then-unvested Retention Units will be forfeited, and the remainder will vest, at the time of retirement. With respect to the Standard Units granted December 5, 2018 to all of the NEOs, if the NEO retires after attaining the age of 65, 60% of his then-unvested Standard Units will be forfeited, and the remainder will vest, at the time of retirement. If the NEO is over age 68 at the time of retirement, 50% of his then-unvested Standard Units granted December 5, 2018 will be forfeited, and the remainder will vest, at the time of retirement.

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| (3) |  | The reported grant date fair value of unit awards was determined in compliance with FASB ASC Topic 718 as more fully described in Note 15 in “Item 8. Financial Statements and Supplementary Data.”

Outstanding Equity Awards as of December 31, 2018

The following table provides information regarding phantom units granted to the NEOs pursuant to the LTIP in each of the years ended December 31, 2016, 2017 and 2018 that were outstanding as of December 31, 2018. None of the NEOs held any outstanding option awards as of December 31, 2016, 2017 or 2018. Also reflected in the table are the outstanding Class B Units in USA Compression Holdings, LLC held by the NEOs as of December 31, 2018.

|  |  |  | Equity Incentive Plan Awards
|  |  |  |  |  |  |  | Number of |  | Market Value Of
|  | Number of Vested and |  | Number of |  | Market |  | Unearned |  | Unearned
|  | Outstanding Class B |  | Outstanding |  | Value of |  | Performance |  | Performance
|  | Units in USA |  | Standard |  | Outstanding |  | Units That Have |  | Units That
|  | Compression Holdings, LLC |  | Units |  | Standard Units |  | Not Vested |  | Have Not Vested
Name |  | (#) (6) |  | (#) |  | ($) (7) |  | (#) |  | ($)
Eric D. Long |  | 481,250 |  |  |  |  |  |  |  |
2018 Grants |  |  |  | 266,874 | (1) | 3,464,025 |  | — |  | N/A
Matthew C. Liuzzi |  | 62,500 |  |  |  |  |  |  |  |
2016 Grant |  |  |  | 30,290 | (2) | 393,164 |  | — |  | N/A
2017 Grant |  |  |  | 21,782 | (3) | 282,730 |  | — |  | N/A
2018 Grants |  |  |  | 138,141 | (4) (5) | 1,793,070 |  | — |  | N/A
William G. Manias |  | 125,000 |  |  |  |  |  |  |  |
2016 Grant |  |  |  | 37,989 | (2) | 493,097 |  | — |  | N/A
2017 Grant |  |  |  | 27,660 | (3) | 359,027 |  | — |  | N/A
2018 Grants |  |  |  | 156,331 | (4) (5) | 2,029,176 |  | — |  | N/A
David A. Smith |  | 125,000 |  |  |  |  |  |  |  |
2016 Grant |  |  |  | 12,522 | (2) | 162,536 |  | — |  | N/A
2017 Grant |  |  |  | 10,130 | (3) | 131,487 |  | — |  | N/A
2018 Grants |  |  |  | 50,363 | (4) (5) | 653,712 |  | — |  | N/A
Sean T. Kimble |  | — |  |  |  |  |  |  |  |
2016 Grant |  |  |  | 21,392 | (2) | 277,668 |  | — |  | N/A
2017 Grant |  |  |  | 15,142 | (3) | 196,543 |  | — |  | N/A
2018 Grants |  |  |  | 60,949 | (4) (5) | 791,118 |  | — |  | N/A

| (1) |  | On November 1, 2018, Mr. Long received a grant of 90,000 Retention Units pursuant to the LTIP and a Retention Agreement entered into by Mr. Long and the General Partner. The Retention Units will vest incrementally, with 60% of the Retention Units vesting on December 5, 2021 and 40% of the Retention Units vesting on December 5, 2023. In the event of cessation of Mr. Long’s employment without Cause or for Good Reason (each as defined in his Retention Agreement), all Retention Units that have not vested prior to or in connection with such cessation of service shall automatically vest in full. The Retention Units will also vest in full upon (i) the death or Disability (as defined in the LTIP) of Mr. Long or (ii) a Change in Control (as defined in the LTIP). On December 5, 2018, Mr. Long received a grant of 176,874 Standard Units pursuant to the LTIP with the same vesting schedule as the Retention Units. All of the Standard Units granted on December 5, 2018 will vest in full upon (i) the death or Disability (as defined in the LTIP) of Mr. Long or (ii) a Change in Control (as defined in the LTIP). In the event of the cessation of Mr. Long’s employment for any reason (other than death or Disability), all Standard Units that have not vested prior to or in connection with such cessation of service shall automatically be forfeited. Notwithstanding the foregoing, if Mr. Long retires after attaining the age of 65, 60% of his then-unvested Standard Units and Retention Units will be forfeited, and the remainder will vest, at the time of retirement. If Mr. Long is over age 68 at the time of retirement, 50% of his then-unvested Standard Units will be forfeited, and the remainder will vest, at the time of retirement.

| (2) |  | Represents the number of Standard Units granted on February 11, 2016 pursuant to the LTIP that had not vested as of December 31, 2018. Each Standard Unit is the economic equivalent of one common unit. The Standard Units vest in three equal annual installments on each subsequent February 15th, beginning with the first installment that vested on February 15, 2017. In the event of cessation of the NEO’s service for any reason, all Standard Units that have not vested prior to or in connection with such cessation of service shall automatically be forfeited. In the event of a Change in Control (as defined in the LTIP) followed by a

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termination of the NEO’s employment without Cause or for Good Reason (each as defined in the applicable LTIP award agreement), all of the NEO’s unvested Standard Units will vest in connection with the NEO’s cessation of service.

| (3) |  | Represents the number of Standard Units granted on February 13, 2017 pursuant to the LTIP that had not vested as of December 31, 2018. Each Standard Unit is the economic equivalent of one common unit. The Standard Units vest in three equal annual installments on each subsequent February 15th, beginning with the first installment that vested on February 15, 2018. In the event of cessation of the NEO’s service for any reason, all Standard Units that have not vested prior to or in connection with such cessation of service shall automatically be forfeited. In the event of a Change in Control (as defined in the LTIP) followed by a termination of the NEO’s employment without Cause or for Good Reason (each as defined in the applicable LTIP award agreement), all of the NEO’s unvested Standard Units will vest in connection with the NEO’s cessation of service.

| (4) |  | Includes Standard Units granted pursuant to the LTIP on February 12, 2018 (34,554 for Mr. Liuzzi; 43,879 for Mr. Manias; 16,070 for Mr. Smith and 24,022 for Mr. Kimble) that had not vested as of December 31, 2018. Each Standard Unit is the economic equivalent of one common unit. The Standard Units granted on February 12, 2018 vest in three equal annual installments on each subsequent February 15th, with the first installment vesting on February 15, 2019. In the event of cessation of the NEO’s service for any reason, all Standard Units that have not vested prior to or in connection with such cessation of service shall automatically be forfeited. In the event of a Change in Control (as defined in the LTIP) followed by a termination of the NEO’s employment without Cause or for Good Reason (each as defined in the applicable LTIP award agreement), all of the NEO’s unvested Standard Units will vest in connection with the NEO’s cessation of service. Amounts shown also include the following number of Standard Units granted on December 5, 2018 to each of the NEOs: 176,874 to Mr. Long; 68,587 to Mr. Liuzzi; 67,452 to Mr. Manias; 34,293 to Mr. Smith and 36,927 to Mr. Kimble. The Standard Units granted on December 5, 2018 vest incrementally, with 60% of the Standard Units vesting on December 5, 2021 and 40% of the Standard Units vesting on December 5, 2023. All of the Standard Units granted on December 5, 2018 will vest in full upon (i) the death or Disability (as defined in the LTIP) of the NEO or (ii) a Change in Control (as defined in the LTIP). In the event of the cessation of the NEO’s service for any reason (other than death or Disability), all Standard Units granted on December 5, 2018 that have not vested prior to or in connection with such cessation of service shall automatically be forfeited. Notwithstanding the foregoing, with respect to the Standard Units granted on December 5, 2018 if the NEO retires after attaining the age of 65, 60% of his then-unvested Standard Units will be forfeited, and the remainder will vest, at the time of retirement. If the NEO is over age 68 at the time of retirement, 50% of his then-unvested Standard Units will be forfeited, and the remainder will vest, at the time of retirement.

| (5) |  | Includes Retention Units granted on November 1, 2018 (35,000 for Mr. Liuzzi and 45,000 for Mr. Manias) pursuant to the LTIP and the Retention Agreement entered into by the applicable NEO and the General Partner that had not vested as of December 31, 2018. Each Retention Unit is the economic equivalent of one common unit. The Retention Units vest incrementally, with 60% of the Retention Units vesting on December 5, 2021 and the remaining 40% of the Retention Units vesting on December 5, 2023. In the event of cessation of the NEO’s service without Cause or for Good Reason (each as defined in the Retention Agreements), all Retention Units that have not vested prior to or in connection with such cessation of service shall automatically vest in full. The Retention Units will also vest in full upon (i) the death or Disability (as defined in the LTIP) of the NEO or (ii) a Change in Control (as defined in the LTIP).

| (6) |  | Represents the number of Class B Units in USA Compression Holdings (“USAC Holdings”) that became vested but had not been settled as of December 31, 2018. These Class B Units vested 25% on the one-year anniversary of the date of grant and 1/36 monthly thereafter; provided that with respect to Mr. Long 50% of the then-unvested portion of Class B Units vested at the time of our initial public offering, which occurred on January 18, 2013. There are no distributions or payouts contemplated with respect to the Class B Units in USAC Holdings.

| (7) |  | The market value of Standard Units is calculated by multiplying $12.98, the closing price of the Partnership’s common units on December 31, 2018, by the number of Standard Units outstanding.

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Units Vested During the Year Ended December 31, 2018

The following table provides information regarding the vesting of Performance Units and Standard Units held by the NEOs during 2018. There are no options outstanding on the Partnership’s common units.

|  | Standard Unit Awards |  | Performance Unit Awards
|  | Number of |  | Value |  | Number of |  | Value
|  | Phantom |  | Realized on |  | Phantom |  | Realized on
|  | Units Vested |  | Vesting |  | Units Vested |  | Vesting
Name |  | (#) |  | ($) (5) |  | (#) (6) |  | ($) (7)
Eric D. Long |  | 327,554 | (1) | 5,657,930 |  | 92,405 | (8) | 1,564,417
Matthew C. Liuzzi |  | 51,024 | (2) | 911,799 |  | 39,525 | (9) | 669,158
William G. Manias |  | 63,988 | (3) | 1,143,466 |  | 49,835 | (10) | 843,707
David A. Smith |  | 21,531 |  | 384,759 |  | 17,207 |  | 291,315
Sean T. Kimble |  | 34,838 | (4) | 622,555 |  | 27,729 | (11) | 469,452

| (1) |  | This number includes 119,618 Standard Units that vested on February 15, 2018 and 207,936 Standard Units that vested on the Transactions Date in connection with the Transactions. Mr. Long settled approximately 50% of his newly vested Standard Units in cash in the amount of $2,828,965 (before taxes), which cash settlement was reported as a disposition of those Standard Units. The remaining 163,777 Standard Units vested following such cash settlement.

| (2) |  | Mr. Liuzzi settled approximately 50% of his newly vested Standard Units in cash in the amount of $455,900 (before taxes), which cash settlement was reported as a disposition of those Standard Units. The remaining 25,512 Standard Units vested following such cash settlement.

| (3) |  | Mr. Manias settled approximately 50% of his newly vested Standard Units in cash in the amount of $571,733 (before taxes), which cash settlement was reported as a disposition of those Standard Units. The remaining 31,994 Standard Units vested following such cash settlement.

| (4) |  | Mr. Kimble settled approximately 50% of his newly vested Standard Units in cash in the amount of $311,278 (before taxes), which cash settlement was reported as a disposition of those Standard Units. The remaining 17,419 Standard Units vested following such cash settlement.

| (5) |  | The value realized on vesting of Standard Units was calculated by multiplying $17.87, the closing price of the Partnership’s common units on the date of vesting (February 15, 2018) by the number of Standard Units vesting. For Mr. Long, whose outstanding Standard Units vested on the Transactions Date, the value realized on vesting for those units was calculated by multiplying $16.93, the closing price of the Partnership’s common units on March 29, 2018 (the last business day before the Transactions Date) by the number of Standard Units vesting.

| (6) |  | The Performance Units were scheduled to vest, if at all, (i) on the third anniversary of the date of grant at between 0% and 200% of the granted number of Performance Units based upon our level of TUR relative to a group of peer companies; or (ii) immediately prior to a “Change in Control”. In accordance with the applicable LTIP award agreements, the Performance Units received accelerated vesting at target levels in connection with the Transactions on the Transactions Date.

| (7) |  | The value realized on vesting was calculated by multiplying $16.93, the closing price of the Partnership’s common units on March 29, 2018, by the number of Performance Units vesting.

| (8) |  | Mr. Long settled approximately 50% of his newly vested Performance Units for cash in the amount of $782,209 (before taxes), which cash settlement was reported as a disposition of those Performance Units. The remaining 46,202 Performance Units vested following such cash settlement.

| (9) |  | Mr. Liuzzi settled approximately 50% of his newly vested Performance Units for cash in the amount of $334,579 (before taxes), which cash settlement was reported as a disposition of those Performance Units. The remaining 19,762 Performance Units vested following such cash settlement.

| (10) |  | Mr. Manias settled approximately 50% of his newly vested Performance Units for cash in the amount of $421,854 (before taxes), which cash settlement was reported as a disposition of those Performance Units. The remaining 24,917 Performance Units vested following such cash settlement.

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| (11) |  | Mr. Kimble settled approximately 50% of his newly vested Performance Units for cash in the amount of $234,726 (before taxes), which cash settlement was reported as a disposition of those Performance Units. The remaining 13,864 Performance Units vested following such cash settlement.

Potential Payments upon Termination or Change in Control

The NEOs are entitled to severance payments and/or other benefits upon certain terminations of employment and, in certain cases, in connection with a Change in Control (as defined below) of the General Partner. All capitalized terms used in the following description but not defined therein shall have the definitions set forth in the referenced document.

Retention Phantom Unit Agreements

As previously noted, each of Messrs. Long, Liuzzi and Manias entered into a Termination Agreement and Mutual Release (collectively, the “Termination Agreements”) with USAC Management (and, with respect to Mr. Long, the USA Compression Partners, LLC) providing for (i) the termination, effective as of November 1, 2018, of the employment agreements that each of Messrs. Long, Liuzzi and Manias had been party to and (ii) a mutual release by each party to the other(s) of all obligations, claims and causes of action arising under the applicable employment agreement.

On November 1, 2018, each of Messrs. Long, Liuzzi and Manias entered into a Retention Agreement providing for a grant of Retention Units that will vest incrementally, with 60% of the Retention Units vesting on December 5, 2021 and the remaining 40% of the Retention Units vesting on December 5, 2023. The Retention Agreements provide for the vesting of 100% of the then-unvested Retention Units upon (i) the NEO’s termination of employment without Cause or for Good Reason (ii) a Change in Control or (iii) the death or Disability (as defined under the LTIP) of the NEO. In the event of the NEO’s termination of employment without Cause or for Good Reason, provided that the NEO executes and does not revoke a general release and waiver of claims, the NEO will also be entitled to a severance payment intended to capture the value of future distributions associated with Retention Units forfeited for tax withholding purposes upon vesting. Upon Mr. Long’s termination of employment due to retirement, provided that Mr. Long is at least 65 years of age at the time of such retirement, 40% of his then-outstanding, unvested Retention Units will receive accelerated vesting and 60% of his then-outstanding, unvested Retention Units will automatically be forfeited at the time of his retirement pursuant to the terms of Mr. Long’s Retention Agreement.

As used in the Retention Agreements, “Cause” means (1) the commission by the NEO of a criminal or other act that involves dishonesty, misrepresentation or moral turpitude; (2) engagement by the NEO in any willful or deliberate misconduct which causes or is reasonably likely to cause economic damage to the Company, the Partnership or any of its and their subsidiaries or injury to the business reputation of the Company, the Partnership or its or their subsidiaries; (3) engagement in any dishonest or fraudulent conduct by the NEO in the performance of the NEO’s duties on behalf of the Company, the Partnership or its or their subsidiaries, including, without limitation, the theft or misappropriation of funds or the disclosure of confidential or proprietary information; (4) a knowing breach by the NEO of any fiduciary duty applicable to the NEO in performance of the NEO’s duties as contained in the organizational documents of the Company, the Partnership or any of its or their subsidiaries; (5) the continuing failure or refusal of the NEO to satisfactorily perform the essential duties of the NEO for the Company; (6) improper conduct materially prejudicial to the business of the Company, the Partnership or any of its or their subsidiaries; (7) the material disregard or violation by the NEO of any policy or procedure of the Company; or (8) any other conduct materially detrimental (as determined in the sole reasonable judgment of the Company) to the Company’s, the Partnership’s or its or their subsidiaries’ business. With respect to a termination for Cause pursuant to clauses (5), (6), (7) and (8) above, such termination will not be considered for Cause unless the NEO has been given written notice specifying in detail the conduct that allegedly constitutes grounds to terminate for Cause and an opportunity for thirty (30) days after receipt of such notice to cure such grounds, if curable. Termination for Cause under clauses (1), (2), (3) or (4) above cannot be cured by the individual and no such notice to cure will be delivered.

“Good Reason” is defined under the Retention Agreements as the occurrence, during the Restricted Period and without the NEO’s prior written consent, of any one or more of the following: (1) a material reduction in the NEO’s current title; (2) a more than 10% reduction by the Company in the NEO’s rate of annual base salary, annual bonus target or annual long-term incentive target, each determined as of the Grant Date; (3) a material diminution in the NEO’s authority, duties, reporting relationship or responsibilities that is inconsistent in a material and adverse respect with the

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NEO’s authority, duties, reporting relationship or responsibilities with the Partnership on the date of the Grant Date, provided that such material diminution is also accompanied with any associated reduction in the NEO’s annual base salary, annual bonus target or annual long-term incentive target, determined based on the NEO’s highest annual base salary, annual bonus target or annual long-term incentive target during the most recent 365-day period prior to the date the change described in this clause (3) occurs; or (4) a change of 50 miles or more in the geographic location of the NEO’s principal place of employment as of the Grant Date. For any resignation to be treated as based on “Good Reason” under the Retention Agreement, the following must occur: (x) the NEO must provide written notice to the Company of the existence of the Good Reason condition within a period not to exceed thirty (30) days of the initial existence of the condition; (y) the Company shall have not less than thirty (30) days following its receipt of such during which it may remedy the condition; and (z) the NEO’s termination of employment must occur within the ninety (90)-day period after the initial existence of the condition specified in such notice. Further, no act or omission shall be “Good Reason” if the NEO has consented in writing to such act or omission.

“Disability” as defined under the LTIP means, as determined by the Compensation Committee in its discretion exercised in good faith, a physical or mental condition of the NEO that would entitle him or her to payment of disability income payments under the Company’s or the Partnership’s or one of its subsidiaries’ long-term disability insurance policy or plan for employees as then in effect; or in the event that an NEO is not covered, for whatever reason, under the Company’s or the Partnership’s or one of its subsidiaries’ long-term disability insurance policy or plan for employees or the Company’s or the Partnership’s or one of its subsidiaries’ does not maintain such a long-term disability insurance policy, “Disability” means a total and permanent disability within the meaning of Section 22(e)(3) of the Code; provided, however, that if a Disability constitutes a payment event with respect to any Award which provides for the deferral of compensation and is subject to Section 409A of the Code, then, to the extent required to comply with Section 409A of the Code, the NEO must also be considered “disabled” within the meaning of Section 409A(a)(2)(C) of the Code. A determination of Disability may be made by a physician selected or approved by the Compensation Committee and, in this respect, NEOs shall submit to an examination by such physician upon request by the Compensation Committee.

Accelerated Vestings in 2018

Pursuant to the terms of Mr. Long’s LTIP grant agreements in effect at the time of the Transactions, 100% of his outstanding, unvested Standard Units received accelerated vesting on the Transactions Date because the Transactions constituted a Change in Control under the LTIP. All unvested Performance Units for all of the NEOs received accelerated vesting at target levels on the Transactions Date in connection with the Transactions pursuant to the terms of the applicable LTIP grant agreements because the Transactions constituted a Change in Control under the LTIP. The potential payments calculated in the “Potential Payments upon Termination or Change in Control” table below only reflect the value of the potential acceleration of LTIP awards that were still outstanding as of December 31, 2018.

Employment Agreements

As previously noted, each of Messrs. Smith and Kimble is party to an Employment Agreement providing for certain payments and benefits upon certain terminations of employment. For the purposes of the following description, the “Company” means USAC Management with respect to Messrs. Smith and Kimble. All capitalized terms used in the following description but not defined therein shall have the definitions set forth in the referenced document.

The Employment Agreements provide for the following in the event of a termination of the NEO without Cause or by the NEO with Good Reason: (i) semi-monthly severance payments for the one year period following the NEO’s Separation from Service in an amount totaling the higher of the NEO’s Base Salary for (a) the current year and (b) the previous year (the “Severance Payment”); (ii) the entire amount of any earned Annual Bonus for the year preceding the year in which the NEO is terminated by the Company for convenience or resigns for Good Reason; (iii) a pro rata portion (based on the number of days the NEO was employed during the year) of any earned Annual Bonus for the year in which the NEO is terminated without Cause or resigns for Good Reason; (iv) continued health insurance benefits for the NEO and his eligible dependents for a period of 24 months, as follows: (a) for the first 12 months of the Coverage Period, the Company will provide such health insurance coverage at its own expense (other than the NEO’s monthly cost-sharing contribution under the Company’s group health plan, as in effect at the time of the NEO’s Separation from Service); (b) for the following six months of the Coverage Period, such health insurance coverage will be at the NEO’s

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sole expense; and (c) for the final six months of the Coverage Period, the Company will be responsible for the proportion of the cost of such health insurance coverage that the NEO covered in the first 12 months of the Coverage Period; and the NEO will be responsible for the proportion that the Company covered during the first 12 months of the Coverage Period; and (v) within 30 days of the NEO’s Separation from Service, all earned but unpaid base salary and paid time off.

In the event of the termination of Mr. Smith’s or Mr. Kimble’s employment by the Company without Cause or by the NEO with Good Reason within two years of a “change in control event” within the meaning of Treasury Regulation 1.409A-3(i)(5), the Severance Payment will be paid in a lump sum on the Company’s first regular payroll date that occurs on or before 30 days after the date of the NEO’s Separation from Service.

In the event of a termination of Mr. Smith’s or Mr. Kimble’s employment due to death or Disability (as defined in the Employment Agreements), the Company shall pay the following to the NEO or the NEO’s estate: (i) the Severance Payment and (ii) the entire amount of any earned but unpaid Annual Bonus for the year preceding the year in which the NEO dies or becomes Disabled; (iii) a pro rata portion (based on the number of days employed during the year) of any earned Annual Bonus for the year in which the NEO dies or becomes Disabled; and (iv) all earned but unpaid base salary and paid time off. In the event of the NEO’s death during the Severance Period, the Severance Payment will be paid in a lump sum within 30 days of his death.

As used in the Employment Agreements, a termination for “convenience” means an involuntary termination for any reason, including a failure to renew the employment agreement at the end of an initial term or any renewal term, other than a termination for “Cause.” “Cause” is defined in the Employment Agreements to mean (i) any material breach of the Employment Agreement, including the material breach of any representation, warranty or covenant made under the Employment Agreement by the NEO, (ii) the NEO’s breach of any applicable duties of loyalty to the Company or any of its affiliates, gross negligence or misconduct, or a significant act or acts of personal dishonesty or deceit, taken by the NEO, in the performance of the duties and services required of the NEO that is demonstrably and significantly injurious to the Company or any of its affiliates, (iii) conviction of a felony or crime involving moral turpitude, (iv) the NEO’s willful and continued failure or refusal to perform substantially the NEO’s material obligations pursuant to the Employment Agreement or follow any lawful and reasonable directive from the CEO or the Board, other than as a result of the NEO’s incapacity, or (v) a violation of federal, state or local law or regulation applicable to the business of the Company that is demonstrably and significantly injurious to the Company.

“Good Reason” is defined in Employment Agreements to mean (i) a material breach by the Company of the Employment Agreement or any other material agreement with the NEO, (ii) a material reduction in the NEO’s base salary, other than a reduction that is generally applicable to all similarly situated employees of the Company, (iii) a material reduction in the NEO’s duties, authority, responsibilities, job title or reporting relationships, (iv) a material reduction by the Company in the facilities or perquisites available to the NEO, other than a reduction that is generally applicable to all similarly situated employees, or (v) the relocation of the geographic location of the NEO’s current principal place of employment by more than fifty miles from the location of the NEO’s principal place of employment as of the Effective Date of the Employment Agreement.

On January 1, 2013, we entered into a services agreement with USAC Management (as amended, the “Services Agreement”), pursuant to which USAC Management provides to us and the General Partner management, administrative and operating services and personnel to manage and operate our business. Pursuant to the Services Agreement, we will reimburse USAC Management for the allocable expenses for the services performed, including the salary, bonus, cash incentive compensation and other amounts paid to our NEOs. See Part III, Item 13 (“Certain Relationships and Related Party Transactions, and Director Independence”).

Change in Control Benefits—LTIP

We have historically included double-trigger change in control provisions for our outstanding LTIP awards, such that in order for accelerated vesting of phantom units to occur in connection with a change in control, such change in control must be followed by a termination of employment by the Company without Cause or by the NEO with Good Reason (each as defined in the applicable phantom unit award agreement). However, in 2018, 2017 and 2016 we granted

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awards of Performance Units that received accelerated vesting at target levels upon the Change in Control (as defined under the LTIP and as set forth below) triggered by the Transactions. The following number of Performance Units vested upon the Change in Control in connection with the Transactions: 92,405 for Mr. Long, 39,525 for Mr. Liuzzi, 49,835 for Mr. Manias, 17,207 for Mr. Smith and 27,729 for Mr. Kimble. Mr. Long also received immediate vesting of all of his then-outstanding Standard Units in connection with the Transactions pursuant to the terms of his LTIP award agreements in effect at the time.

Under the LTIP award agreements entered into prior to the Transactions, in the event of cessation of the NEO’s service for any reason, all Standard Units that have not vested prior to or in connection with such cessation of service shall automatically be forfeited. With respect to unvested Standard Units held by the NEOs, those Standard Units will receive accelerated vesting in the event that that the NEO is terminated by the Company without Cause or by the NEO for Good Reason (as each term is defined in the applicable LTIP award agreement) in connection with a change in control event.

If a termination occurred immediately following the Transactions, the following number of incremental Standard Units would have vested for each of the NEOs (other than Mr. Long): 86,626 for Mr. Liuzzi; 109,528 for Mr. Manias; 38,722 for Mr. Smith; and 60,556 for Mr. Kimble. If a termination were to occur on December 31, 2018 following a Change in Control, the following number of Standard Units would vest: 176,874 for Mr. Long, 155,213 for Mr. Liuzzi, 176,980 for Mr. Manias, 73,015 for Mr. Smith and 97,483 for Mr. Kimble. Additionally, the following number of Retention Units would vest in the event of a termination following a Change in Control on December 31, 2018: 90,000 for Mr. Long, 35,000 for Mr. Liuzzi and 45,000 for Mr. Manias.

On November 1, 2018, the Board approved and adopted the First Amendment to the LTIP which, among other things, (i) updated the definition of Change in Control to refer to Energy Transfer with respect to awards granted on or after April 3, 2018; (ii) increased the number of common units of the Partnership available to be awarded under the LTIP by 8,590,000 common units (which brings the total number of common units available to be awarded under the LTIP to 10,000,000 common units); and (iii) extended the term of the LTIP until November 1, 2028.

A “Change in Control” is defined under the LTIP as follows:

| (a) with respect to Awards granted before April 3, 2018, the occurrence of any of the following events: (i) any “person” or “group” within the meaning of Sections 13(d) and 14(d)(2) of the Exchange Act, other than the Company, Riverstone Holdings LLC or an Affiliate of the Company (as determined immediately prior to such event) or Riverstone Holdings LLC, shall become the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the combined voting power of the equity interests in the Company or the Partnership; (ii) the limited partners of the Partnership approve, in one or a series of transactions, a plan of complete liquidation of the Partnership; (iii) the sale or other disposition by either the Company or the Partnership of all or substantially all of its assets in one or more transactions to any Person other than the Company, the Partnership, Riverstone Holdings LLC or an Affiliate of the Company, the Partnership or Riverstone Holdings LLC; or (iv) a transaction resulting in a Person other than the Company, Riverstone Holdings LLC or an Affiliate of the Company (as determined immediately prior to such event) or Riverstone Holdings LLC being the sole general partner of the Partnership; and

| (b) with respect to Awards granted on or after April 3, 2018, means the occurrence of any of the following events: (i) any “person” or “group” within the meaning of Sections 13(d) and 14(d)(2) of the Exchange Act, other than the Company, Energy Transfer LP, a Delaware limited partnership (“ET”), Energy Transfer Operating, L.P., a Delaware limited partnership (“ETO”), an Affiliate of the Company (as determined immediately prior to such event), or an Affiliate of, or successor to, ET or ETO, shall become the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the combined voting power of the equity interests in the Company or the Partnership; (ii) the limited partners of the Partnership approve, in one or a series of transactions, a plan of complete liquidation of the Partnership; (iii) the sale or other disposition by either the Company or the Partnership of all or substantially all of its assets in one or more transactions to any Person other than the Company, the Partnership, ET, ETO, an Affiliate of the Company (as determined immediately prior to such event), the Partnership, or an Affiliate of, or successor to, ET or ETO; or (iv) a transaction resulting in a Person other than the Company, ET, ETO, an

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Affiliate of the Company (as determined immediately prior to such event), or an Affiliate of, or successor to, ET or ETO being the sole general partner of the Partnership.

However, if an LTIP award is subject to section 409A of the Internal Revenue Code, a “Change in Control” will be defined in accordance with section 409A of the Internal Revenue Code and the regulations promulgated thereunder.

Also on November 1, 2018, the Board adopted the New Award Agreement, which (i) provides for incremental vesting of Standard Units over five years (60% on the third December 5 following the grant and 40% on the fifth December 5 following the grant) and (ii) provides for vesting of 100% of the outstanding, unvested Standard Units in the event of (a) a Change in Control (as defined under the LTIP and set forth above) or (b) the death or Disability of the NEO. Also, under the New Award Agreement, if the NEO is at least 65 at the time of his voluntary retirement, 60% of his then-unvested Standard Units will be forfeited, and the remainder will vest, at the time of retirement. If the NEO is over age 68 at the time of his retirement, 50% of his then-unvested Standard units will be forfeited, and the remainder will vest, at the time of retirement.

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Potential Payments upon Termination or Change in Control

Except as otherwise noted, the values in the table below assume that a Change in Control occurred on December 31, 2018 and/or that the NEO’s employment terminated on that date, as applicable. The amounts actually payable to any NEO can only be calculated with certainty upon actual termination or a Change in Control. The value of the acceleration of the LTIP awards was calculated using the value of $12.98, which was the closing price of the Partnership’s common units on December 31, 2018.

|  | Change in |  |  |  |  |  |  |  |
|  | Control |  |  |  |  |  |  |  |
|  | followed by |  | Termination of |  |  |  |  |  |
|  | termination |  | Employment |  | Termination of |  | Termination by the |  | Continued
|  | without |  | without “Cause” |  | Employment |  | Executive Other |  | Employment
|  | “Cause” or for |  | or for |  | because of Death |  | Than for |  | Following Change
Executive Benefits and |  | “Good Reason” |  | “Good Reason” |  | or Disability |  | “Good Reason” |  | of Control
Payments |  | ($) (2) |  | ($) (2) |  | ($) (3) |  | ($) (4) |  | ($) (5)
Eric D. Long |  |  |  |  |  |  |  |  |  |
Salary (1) |  | 17,663 |  | 17,663 |  | 17,663 |  | 17,663 |  | —
Bonus (1) |  | — |  | — |  | — |  | — |  | —
Accelerated Vesting of Standard Units (7) |  | — |  | — |  | 2,295,825 |  | — |  | 2,295,825
Accelerated Vesting of Retention Units (8) |  | 1,168,200 |  | 1,168,200 |  | 1,168,200 |  | — |  | 1,168,200
Severance Payment under Retention Agreements (9) |  | 359,100 |  | 359,100 |  | — |  | — |  | —
Totals |  | 1,544,963 |  | 1,544,963 |  | 3,481,688 |  | 17,663 |  | 3,464,025
Matthew C. Liuzzi |  |  |  |  |  |  |  |  |  |
Salary (1) |  | 10,609 |  | 10,609 |  | 10,609 |  | 10,609 |  | —
Bonus (1) |  | — |  | — |  | — |  | — |  | —
Accelerated Vesting of Standard Units (7) |  | 2,014,664 |  | 1,124,405 |  | 890,259 |  | — |  | 890,259
Accelerated Vesting of Retention Units (8) |  | 454,300 |  | 454,300 |  | 454,300 |  | — |  | 454,300
Severance Payment under Retention Agreements (9) |  | 139,650 |  | 139,650 |  | — |  | — |  | —
Totals |  | 2,619,223 |  | 1,728,964 |  | 1,355,168 |  | 10,609 |  | 1,344,559
William G. Manias |  |  |  |  |  |  |  |  |  |
Salary (1) |  | 11,975 |  | 11,975 |  | 11,975 |  | 11,975 |  | —
Bonus (1) |  | — |  | — |  | — |  | — |  | —
Accelerated Vesting of Standard Units (7) |  | 2,297,200 |  | 1,421,673 |  | 875,527 |  | — |  | 875,527
Accelerated Vesting of Retention Units (8) |  | 584,100 |  | 584,100 |  | 584,100 |  | — |  | 584,100
Severance Payment under Retention Agreements (9) |  | 179,550 |  | 179,550 |  | — |  | — |  | —
Totals |  | 3,072,825 |  | 2,197,298 |  | 1,471,602 |  | 11,975 |  | 1,459,627
David A. Smith |  |  |  |  |  |  |  |  |  |
Salary (1) |  | 554,763 |  | 554,763 |  | 554,763 |  | 13,763 |  | —
Bonus (1) |  | 382,710 |  | 382,710 |  | 382,710 |  | — |  | —
Accelerated Vesting of Standard Units (7) |  | 947,735 |  | 502,612 |  | 445,123 |  | — |  | 445,123
Health and Welfare Plan Benefits (6) |  | 24,102 |  | 24,102 |  | — |  | — |  | —
Totals |  | 1,909,310 |  | 1,464,187 |  | 1,382,596 |  | 13,763 |  | 445,123
Sean T. Kimble |  |  |  |  |  |  |  |  |  |
Salary (1) |  | 330,950 |  | 330,950 |  | 330,950 |  | 8,429 |  | —
Bonus (1) |  | 273,457 |  | 273,457 |  | 273,457 |  | — |  | —
Accelerated Vesting of Standard Units (7) |  | 1,265,329 |  | 786,017 |  | 479,312 |  | — |  | 479,312
Health and Welfare Plan Benefits (6) |  | 24,102 |  | 24,102 |  | — |  | — |  | —
Totals |  | 1,893,838 |  | 1,414,526 |  | 1,083,719 |  | 8,429 |  | 479,312

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| (1) |  | The listed salary for each of Messrs. Smith and Kimble represents his annualized rate of pay as of December 31, 2018, plus, with respect to the first three columns of the table, his accrued but unused paid time off as of December 31, 2018. The listed bonus amount for each of Messrs. Smith and Kimble is his bonus awarded with respect to the year ended December 31, 2018. Because the assumed termination date for each NEO is December 31, 2018, no pro rata bonus amounts based on a partial year of continued employment prior to termination are included. The amount shown for each of Messrs. Long, Liuzzi and Manias represents the amount of earned but unpaid base salary he would be entitled to receive.

| (2) |  | The Employment Agreements for each of Messrs. Smith and Kimble provide that upon termination by the Company without Cause or by the NEO for Good Reason, the NEO is entitled to receive one times his base salary, payable in equal semimonthly installments over the course of one year (or, if such termination occurs within two years after a “change in control event” within the meaning of Treasury Regulation 1.409A-3(i)(5), in a lump sum within 30 days of termination of employment).

| (3) |  | Upon the death or Disability of Mr. Kimble or Mr. Smith during the Severance Period (as defined in the Employment Agreements), his salary payment will be accelerated and he (or his estate) will be entitled to the same bonus payment as if the death or Disability had not occurred.

| (4) |  | In the event of the termination of employment by any of the NEOs without Good Reason, the NEO will be entitled to all earned but unpaid annual base salary.

| (5) |  | The NEOs are not entitled to a certain level of compensation in the event of continued employment following a Change in Control, but for purposes of this table it is assumed that the NEO would continue to receive a level of base salary, bonus, benefits and other compensation in the event of continued employment following a Change in Control that is the same as, or similar to, the amounts shown in the Summary Compensation Table. Ac cordingly, no additional amounts are shown for salary, bonus or health and welfare plan benefits because those amounts would remain as in effect at the time of the Change in Control.

| (6) |  | In the event of Mr. Smith’s or Mr. Kimble’s termination by the Company without Cause or by the NEO with Good Reason, he and his eligible dependents will be entitled to continued health insurance benefits for a period of 24 months following his Separation from Service (the “Coverage Period”), as follows: (i) for the first twelve months of the Coverage Period, the Company will provide such health insurance coverage at its own expense (other than the NEO’s monthly cost-sharing contribution under the Company’s group health plan, as in effect at the time of the NEO’s Separation from Service) (ii) for the following six months of the Coverage Period, such health insurance coverage will be at the NEO’s sole expense; and (iii) for the final six months of the Coverage Period, the Company will be responsible for the proportion of the cost of such health insurance coverage that the NEO covered in the first 12 months of the Coverage Period; and the NEO will be responsible for the proportion that the Company covered during the first 12 months of the Coverage Period. The amount shown represents the Company’s contribution to the NEO’s health insurance benefits during the first half of the Coverage Period. Messrs. Long, Liuzzi and Manias are not currently party to any contractual arrangements providing for continued health insurance coverage by the Company following a termination of employment.

| (7) |  | In the event of the NEO’s cessation of service for any reason (other than death or Disability), 100% of the NEO’s Standard Units that have not vested prior to or in connection with such cessation of service shall be automatically forfeited. Notwithstanding the foregoing, with respect to the Standard Units granted on December 5, 2018, if the NEO retires after attaining the age of 65, 60% of his then-unvested Standard Units will be forfeited, and the remainder will vest, at the time of retirement. For the Standard Units granted on December 5, 2018, if the NEO is over age 68 at the time of retirement, 50% of his then-unvested Standard Units will be forfeited, and the remainder will vest, at the time of retirement. For the Standard Units granted on December 5, 2018, in the event of the death or Disability of the NEO, 100% of the then-unvested Standard Units shall vest in full immediately prior to such cessation of service due to death or Disability. In the event of a Change in Control (as defined under the LTIP), 100% of the NEO’s outstanding, unvested Standard Units granted on December 5, 2018 would vest.

| (8) |  | The Retention Agreements for Messrs. Long, Liuzzi and Manias provide that 100% of the outstanding, unvested Retention Units held by the applicable NEO will vest immediately prior to the NEO’s Separation from Service for the following reasons: (i) termination of the NEO by the Company without Cause or by the NEO with Good Reason, (ii) upon a Change in Control, and (iii) upon the death or Disability of the NEO. Also, if Mr. Long terminates his employment due to retirement, if he is at the time of retirement 65 years of age or older, 40% of his then-unvested Retention Units will vest and the remaining 60% of his then-unvested Retention Units will be forfeited.

| (9) |  | For Messrs. Long, Liuzzi and Manias, provided that the NEO executes and does not revoke a general release and waiver of claims, the NEO will be entitled to a severance payment intended to capture the value of future distributions associated with Retention Units forfeited for tax withholding purposes.

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Director Compensation

For the year ended December 31, 2018, our CEO was the only NEO who also served as a director, and he did not receive additional compensation for his service on the Board. Mr. Long’s compensation as an NEO is reflected in the Summary Compensation Table above. Other than Mr. Hartman, all of the independent members of the Board receive cash and equity compensation for their service as directors.

The following table shows the total fees earned and other compensation paid in cash to each independent director during 2018.

|  | Fees Earned or |  |  |  | All Other |  |
|  | Paid in Cash |  | Unit Awards |  | Compensation |  | Total
Name |  | ($) |  | ($) (1) |  | ($) (2) |  | ($)
Robert F. End (3) (4) |  | 55,250 |  | — |  | 10,692 |  | 65,942
Jerry L. Peters (3) (5) |  | 55,250 |  | — |  | — |  | 55,250
Forrest E. Wylie (3) (6) |  | 51,500 |  | — |  | 21,386 |  | 72,886
Matthew S. Hartman (7) (8) |  | — |  | — |  | — |  | —
Glenn E. Joyce (7) |  | 122,500 |  | 140,350 |  | 9,130 |  | 271,980
William S. Waldheim (7) |  | 124,375 |  | 140,350 |  | 9,130 |  | 273,855

| (1) |  | Represents the grant date fair value of our Standard Units, calculated in accordance with ASC 718. For a detailed discussion of the assumptions utilized in coming to these values, please see Note 15 to our consolidated financial statements. As of December 31, 2018, the independent members of the Board who receive equity awards held the following number of outstanding equity awards under the LTIP: Mr. Joyce: 8,695 Standard Units; and Mr. Waldheim: 8,695 Standard Units. Mr. Joyce’s and Mr. Waldheim’s respective totals include the following grants made on July 30, 2018: (i) a one-time director onboarding grant of 2,500 Standard Units and (ii) an annual grant of Standard Units with a value of $100,000, based on the closing price of the Partnership’s common units on the date of grant. The Standard Units held by Messrs. Joyce and Waldheim vest incrementally, with 60% of the Standard Units vesting on December 5, 2020 and the remaining 40% of the Standard Units vesting on December 5, 2022. In the event of the director’s cessation of service to due death, Disability or a Change in Control, 100% of his outstanding, unvested Standard Units will vest immediately prior to such event.

| (2) |  | Amounts in this column reflect the value of DERs, received by the directors with respect to their outstanding phantom unit awards. For Messrs. Joyce and Waldheim, the amount shown includes DERs paid with respect to the Partnership’s quarterly distribution on its common units with respect to the second and third quarters of 2018.

| (3) |  | Effective as of the Transactions Date, Messrs. End, Peters and Wylie resigned from the Board in connection with the Transactions; therefore this table reflects their compensation for the period from January 1, 2018 to the Transactions Date.

| (4) |  | Consists of (i) $36,500 in cash retainer and meeting attendance fees (a) for the fourth quarter of 2017 (which were paid in the first quarter of 2018) and (b) earned in the first quarter of 2018; (ii) $18,750 in cash in lieu of a grant of the annual grant of phantom units under the LTIP, which payment was approved by the Board on March 29, 2018 and the amount of which represents one quarter of the value of the annual grant of phantom units that the director would have otherwise received; and (iii) $10,692 of DERs.

| (5) |  | Consists of (i) $36,500 in cash retainer and meeting attendance fees (a) for the fourth quarter of 2017 (which were paid in the first quarter of 2018) and (b) earned in the first quarter of 2018; and (ii) $18,750 in cash in lieu of a grant of the annual grant of phantom units under the LTIP, which payment was approved by the Board on March 29, 2018 and the amount of which represents one quarter of the value of the annual grant of phantom units that the director would have otherwise received.

| (6) |  | Consists of (i) a $32,750 in cash retainer and meeting attendance fees (a) for the fourth quarter of 2017 (which were paid in the first quarter of 2018) and (b) earned in the first quarter of 2018; (ii) $18,750 in cash in lieu of a grant of the annual grant of phantom units under the LTIP, which payment was approved by the Board on March 29, 2018 and the amount of which represents one quarter of the value of the annual grant of phantom units that the director would have otherwise received; (iii) $21,386 of DERs.

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| (7) |  | Messrs. Hartman, Joyce and Waldheim were appointed to the Board on the Transactions Date in connection with the Transactions; therefore, this table reflects their compensation for the period from the Transactions Date through December 31, 2018. For Mr. Joyce, the amount shown consists of (i) $122,500 in cash retainer for service on the Board, as Chair of the Compensation Committee and as a member of the Audit Committee; (ii) $140,350 in Standard Units awarded; and (iii) $9,130 of DERs. For Mr. Waldheim, the amount shown consists of (i) $124,375 in cash retainer for service on the Board, as Chair of the Audit Committee and as a member of the Compensation Committee; (ii) $140,350 in Standard Units awarded; and (iii) $9,130 of DERs.

| (8) |  | Mr. Hartman was appointed to the Board pursuant to that certain Board Representation Agreement entered to among us, the General Partner, ETE and EIG on the Transactions Date in connection with our private placement to EIG of Preferred Units and Warrants. Mr. Hartman does not receive compensation for his service on the Board.

Officers, employees or paid consultants or advisors of us or the General Partner or its affiliates who also serve as directors do not receive additional compensation for their service as directors. Other than Mr. Hartman, our directors who are not officers, employees or paid consultants or advisors of us or the General Partner or its affiliates receive cash and equity based compensation for their services as directors. Our director compensation program is subject to revision by the Board from time to time.

On July 30, 2018 the Board adopted the Amended and Restated Outside Director Compensation Policy (the “New Director Compensation Policy”) effective on the Transactions Date. The New Director Compensation Policy differs from the previous director compensation plan (the “Previous Director Compensation Policy”) in several ways. The New Director Compensation Policy makes the following changes to bring our director compensation program more in line with Energy Transfer’s director compensation program and consistent with the levels of director compensation at similarly situated companies: (i) increases the annual cash retainer for the independent directors from $75,000 to $100,000 and removes the option for the director to elect to receive such retainer in common units rather than cash; (ii) increases the cash retainer for acting as Chairman of a standing committee; (iii) awards different levels of annual cash retainer for acting as the Chairman of the Audit Committee and acting as Chairman of the Compensation Committee; (iv) adds a retainer for membership on a standing committee; (v) discontinues per meeting attendance fees; (vi) increases the value of the annual equity grant from $75,000 to $100,000; (vii) provides for a one-time director onboarding equity of 2,500 Standard Units; (viii) alters the vesting schedule for the Standard Units from vesting in full on the one year anniversary of the grant to incremental vesting over five years; and (ix) provides for vesting in full of all outstanding, unvested Standard Units in the event of the director’s death, Disability or upon a Change in Control.

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The following chart summarizes the key differences between the Previous Director Compensation Policy and the New Director Compensation Policy.

Compensation Element | Previous Director Compensation Policy |  | New Director Compensation Policy
Annual Cash Retainer | $75,000 (or in common units at director’s election) |  | $100,000
Committee Chair Cash Retainer | Any Standing Committee: $15,000 |  | Audit Committee: $25,000 Compensation Committee: $15,000
Committee Membership Retainer (if not Committee Chair) | None |  | Audit Committee: $15,000 Compensation Committee: $7,500
Initial Phantom Unit Award | None |  | 2,500 Standard Units
Annual Phantom Unit Award | $75,000 value |  | $100,000 value
DERs on Unvested Phantom Units | Yes (paid on a current or deferred basis as determined at the time of grant) |  | Yes (paid on a current basis)
Phantom Unit Vesting Schedule | Vest in full 1 year from grant date |  | 60% vest on third December 5 following grant 40% vest on fifth December 5 following grant
Change-in-Control | Unvested phantom units vest in full, but if director ceases service, all unvested phantom units forfeited |  | Unvested phantom units vest in full
Cessation of Service due to Death or Disability | All unvested phantom units forfeited |  | Unvested phantom units vest in full
Attendance Fee Per Meeting | $2,000 |  | None
Reimbursement of Out-of-Pocket Expenses | Yes |  | Yes
Indemnification | Yes, to fullest extent permitted under Delaware law |  | Yes, to fullest extent permitted under Delaware law

ITEM 12.Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

Pursuant to the terms of the Equity Restructuring Agreement the Partnership entered into on January 15, 2018, at any time after the first anniversary of the Transactions Date, ETO has the right to contribute (or cause any of its subsidiaries to contribute) to the Partnership all of the outstanding equity interests in any of its subsidiaries that owns the General Partner Interest (as defined in the Equity Restructuring Agreement) in exchange for $10,000,000 (the “GP Contribution”); provided that the GP Contribution will occur automatically if at any time following the Transactions Date (i) ETO or one of its affiliates (including ET LP) owns, directly or indirectly, the General Partner Interest and (ii) ETO and its affiliates (including ET LP) collectively own less than 12,500,000 of the Partnership’s common units.

Security Ownership of Certain Beneficial Owners and Management

The following table sets forth the beneficial ownership of the Partnership’s common units and Series A Preferred Units as of February 14, 2019 held by:

| · |  | each person who beneficially owns 5% or more of the Partnership’s outstanding common units;

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| · |  | all of the directors of the General Partner;

| · |  | each NEO of the General Partner; and

| · |  | all directors and NEOs of the General Partner as a group.

As of February 14, 2019, there were 90,000,504 common units outstanding. Except as indicated by footnote, the persons named in the table below have sole voting and investment power with respect to all common units shown as beneficially owned by them and their address is 100 Congress Avenue, Suite 450, Austin, Texas 78701.

|  | Common Units |  | Percentage of |
Name of Beneficial Owner |  | Beneficially Owned |  | Common Units |
Energy Transfer Operating, L.P. (1) (2) |  | 39,658,263 |  | 44.07 | %
Oppenheimer Funds, Inc. (3) |  | 18,084,216 |  | 20.10 | %
EIG Veteran Equity Aggregator, L.P. (4) |  | 12,619,921 |  | 14.02 | %
Eric D. Long (5) |  | 489,940 |  | * |
Matthew C. Liuzzi (6) |  | 175,289 |  | * |
William G. Manias (7) |  | 225,989 |  | * |
David A. Smith (8) |  | 106,545 |  | * |
Sean T. Kimble (9) |  | 93,877 |  | * |
Michael Bradley |  | — |  | * |
Christopher R. Curia |  | — |  | * |
Matthew S. Hartman |  | — |  | * |
Glenn E. Joyce |  | — |  | * |
Thomas E. Long |  | — |  | * |
Thomas P. Mason |  | — |  | * |
Matthew S. Ramsey |  | — |  | * |
William S. Waldheim |  | — |  | * |
All directors and officers as a group (14 persons) (10) |  | 1,110,203 |  | 1.23 | %

*Less than 1%.

| (1) |  | Energy Transfer Operating, L.P. has sole voting and dispositive power over 39,658,263 common units based on a Schedule 13D filed on April 11, 2018 with the SEC. The principal business address of Energy Transfer Operating, L.P. is 8111 Westchester Drive, Suite 600, Dallas, Texas 75225.

| (2) |  | Includes 8,000,000 common units held by USA Compression GP, LLC.

| (3) |  | Oppenheimer Funds, Inc. has the shared power to dispose or to direct the disposition of 18,084,216 common units based on Amendment No. 10 to Schedule 13G filed on January 14, 2019 with the SEC. Pursuant to the provisions of the Partnership Agreement providing that the holder of 20% or more of any class of the Partnership’s securities may not, subject to certain exceptions, vote any of those securities, Oppenheimer Funds, Inc. does not have the shared power to vote or direct the vote with respect to any of the common units it owns. The principal business address of Oppenheimer Funds, Inc. is Two World Financial Center, 225 Liberty Street, New York, New York 10281.

| (4) |  | EIG Veteran Equity Aggregator, L.P. holds Warrants to acquire (i) 4,206,240 common units of the Partnership at an exercise price of $17.03 per common unit and (ii) 8,413,281 common units of the Partnership at an exercise price of $19.59 per common unit. The Warrants become exercisable on April 2, 2019 and will expire on April 2, 2028. Upon exercise of the Warrants in full and assuming the Partnership does not elect to settle the Warrants in common units on a net basis, EIG would have sole voting and dispositive power over 12,619,921 common units of the Partnership based on the Schedule 13D filed on February 4, 2019 with the SEC. The principal business address of EIG Veteran Equity Aggregator, L.P. is 333 Clay Street, Suite 3500, Houston, Texas 77002.

| (5) |  | Includes 414,926 common units held directly by Mr. Long, 17,592 common units held by Aladdin Partners, L.P., a limited partnership affiliated with Mr. Long, 55,248 common units held by certain trusts of which Mr. Long is the trustee and 2,174

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common units held by Mr. Long’s spouse. Mr. Long disclaims any beneficial ownership of the units held by Mr. Long’s spouse, except to the extent of his pecuniary interest therein.

| (6) |  | Includes 52,699 common units that Mr. Liuzzi has the right to acquire within 60 days upon the vesting and/or settlement of his Standard Units and Retention Units, subject to Compensation Committee discretion.

| (7) |  | Includes 66,446 common units that Mr. Manias has the right to acquire within 60 days upon the vesting and/or settlement of his Standard Units and Retention Units, subject to Compensation Committee discretion.

| (8) |  | Includes 22,944 common units that Mr. Smith has the right to acquire within 60 days upon the vesting and/or settlement of his Standard Units, subject to Compensation Committee discretion.

| (9) |  | Includes 36,971common units that Mr. Kimble has the right to acquire within 60 days upon the vesting and/or settlement of his Standard Units, subject to Compensation Committee discretion.

| (10) |  | Includes 186,509 common units that certain of our directors and executive officers have the right to receive within 60 days upon the vesting and/or settlement of phantom units held by such directors and executive officers.

Securities Authorized for Issuance Under Equity Compensation Plans

In connection with our IPO on January 18, 2013, the Board adopted the LTIP. On November 1, 2018, the Board approved and adopted the First Amendment to the LTIP (the “First Amendment”) with immediate effectiveness. The First Amendment (i) increased the number of common units available to be awarded under the LTIP by 8,590,000 common units (which brings the total number of common units available to be awarded under the LTIP to 10,000,000 common units); (ii) provided that common units withheld to satisfy the exercise price or tax withholding obligations with respect to an award will not be considered to be common units that have been delivered under the LTIP; (iii) for awards granted on or after April 3, 2018, modifies the definition of “Change in Control” under the LTIP to refer to Energy Transfer Operating, L.P., Energy Transfer LP and their Affiliates (as defined under the LTIP) and successors; (iv) updated the tax withholding provision of the LTIP and (v) extended the term of the LTIP until November 1, 2028.

The following table provides certain information with respect to the LTIP as of December 31, 2018:

|  |  |  |  |  | Number of securities |
|  |  |  |  |  | remaining available for |
|  |  |  |  |  | future issuance under |
|  | Number of securities to |  | Weighted-average |  | equity compensation |
|  | be issued upon exercise |  | exercise price of |  | plan (excluding securities |
|  | of outstanding options, |  | outstanding options, |  | reflected in the first |
Plan Category |  | warrants and rights |  | warrants and rights |  | column) |
Equity compensation plans approved by security holders |  | — |  | N/A |  | — |
Equity compensation plans not approved by security holders |  | 1,429,078 |  | N/A |  | 10,000,000 | (1)

| (1) |  | As of December 31, 2018, the number of common units that may be delivered pursuant to awards under the LTIP was 10,000,000 common units before giving effect to any outstanding awards. Phantom units withheld to satisfy the exercise price or tax withholdings of an award and phantom units that are forfeited, cancelled, paid or otherwise terminate or expire without the actual delivery of common units will be available for delivery pursuant to other awards. Currently, only phantom unit awards are outstanding under the LTIP. Pursuant to the terms of the LTIP, each phantom unit is the economic equivalent of one common unit and, other than director phantom unit awards, may be settled in cash or common units at the discretion of the Board or a committee thereof. Any phantom unit settled in cash will not result in the actual delivery of a common unit.

For more information about the LTIP, please see Note 15 to our consolidated financial statements.

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ITEM 13.Certain Relationships and Related Party Transactions, and Director Independence

Certain Relationships and Related Party Transactions

Services Agreement

In connection with our formation and IPO, we and other parties have entered into the agreements described below. These agreements were not the result of arm’s length negotiations, and they, or any of the transactions that they provide for, may not be effected on terms as favorable to the parties to these agreements as could have been obtained from unaffiliated third parties.

We entered into that certain Services Agreement with USAC Management, a wholly owned subsidiary of the General Partner, effective on January 1, 2013 (the “Services Agreement”), pursuant to which USAC Management provides to us and the General Partner management, administrative and operating services and personnel to manage and operate our business. We or one of our subsidiaries pays USAC Management for the allocable expenses it incurs in its performance under the Services Agreement. These expenses include, among other things, salary, bonus, cash incentive compensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated by USAC Management to us. USAC Management has substantial discretion to determine in good faith which expenses to incur on our behalf and what portion to allocate to us.

On November 3, 2017, the Services Agreement was amended to extend its term to December 31, 2022. The Services Agreement may be terminated at any time by (i) the Board 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 the General Partner experience a Change of Control (as defined in the Services Agreement); (b) we or the General Partner breach the terms of the Services Agreement in any material respect following 30 days’ written notice detailing the breach (which breach remains uncured after such period); (c) a receiver is appointed for all or substantially all of our or the General Partner’s property or an order is made to wind up our or the General Partner’s business; (d) a final judgment, order or decree that materially and adversely affects the ability of us or the General Partner to perform under the Services Agreement is obtained or entered against us or the 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 the General Partner occur. USAC Management will not be liable to us for their performance of, or failure to perform, services under the Services Agreement unless its acts or omissions constitute gross negligence or willful misconduct.

Transactions with Energy Transfer

We provide compression services to entities affiliated with Energy Transfer, which became a related party of ours on the Transactions Date as a result of the Transactions and its resultant ownership and control of the General Partner and ownership of approximately 44% of our limited partner interests as of December 31, 2018 (including the 8,000,000 common units owned by the General Partner and before giving effect to the conversion of the 6,397,965 Class B Units to common units that will occur in 2019). We recognized $17.1 million in revenue from compression services from entities affiliated with Energy Transfer for the year ended December 31, 2018. We may provide compression services to entities affiliated with Energy Transfer in the future, and any significant transactions will be disclosed.

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The following table summarizes payments and accounts receivable and payable between us and Energy Transfer during 2018.

Transaction | Explanation | Amount/Value
2018 quarterly distributions on limited partner interests (three quarters) | Represents the aggregate amount of distributions made to Energy Transfer in respect of the Partnership’s common units during 2018. | $62.5 million
Revenue for compression services | Represents the aggregate amount of revenue recognized for providing compression services to entities affiliated with Energy Transfer for the full year 2018. | $17.1 million
Sales Tax Contingency | Receivable from ETP as of December 31, 2018 related to indemnification for sales tax contingencies incurred by the USA Compression Predecessor. | $44.9 million
Accounts receivable | Receivables for compression services provided to entities affiliated with Energy Transfer as of December 31, 2018. | $2.7 million
Accounts payable | Payables to entities affiliated with Energy Transfer as of December 31, 2018. | $0.4 million

Other Related Party Transactions

We provide compression services to entities affiliated with Riverstone/Carlyle Global Energy and Power Fund IV, L.P. (“Riverstone”), which owned a majority of the membership interests in USA Compression Holdings, LLC, (“USAC Holdings”), which owned and controlled the General Partner and owned approximately 40% of our limited partner interests before the Transactions. We recognized $0.3 million and $0.7 million in revenue from compression services from such affiliated entities for the years ended December 31, 2018 and 2017.

On the Transactions Date and in connection with the Transactions, three NEOs who held Class A Units in USAC Holdings received cash distributions from USAC Holdings in the following amounts pursuant to the terms of the Amended and Restated Limited Liability Company Agreement of USA Compression Holdings, LLC (the “Holdings LLC Agreement”): Eric D. Long, approximately $1.1 million; William G. Manias, approximately $374,000; and David A. Smith, approximately $374,000. On June 15, 2018, USAC Holdings sold 5,000,000 common units of the Partnership in a secondary offering (the “Secondary Offering”). In connection with the Secondary Offering, in June 2018 two NEOs who held Class A Units in USAC Holdings received cash distributions from USAC Holdings in the following amounts pursuant to the terms of the Holdings LLC Agreement: Eric D. Long, approximately $420,000; and David A. Smith, approximately $140,000.

As of August 30, 2018, Riverstone was no longer a related party due to its sale of the General Partner to Energy Transfer in connection with the Transactions and its divestiture of all of its remaining common units in a privately negotiated block trade (the “August Trade”), as reported on Amendment No. 15 to Schedule 13D Riverstone filed with the SEC on August 30, 2018. In connection with the August Trade, in September 2018 two NEOs who held Class A Units in USAC Holdings received cash distributions from USAC Holdings in the following amounts pursuant to the terms of the Holdings LLC Agreement: Eric D. Long, approximately $537,000; and David A. Smith, approximately $179,000.

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between the General Partner and its affiliates, including Energy Transfer, on the one hand, and the Partnership and its limited partners, on the other hand. The directors and officers of the General Partner have fiduciary duties to manage the General Partner in a manner beneficial to its owners. At the same time, the General Partner has a fiduciary duty to manage the Partnership in a manner beneficial to us and our unitholders.

Whenever a conflict arises between the General Partner or its affiliates, on the one hand, and the Partnership and its limited partners, on the other hand, the General Partner will resolve that conflict. The Partnership Agreement contains provisions that modify and limit the General Partner’s fiduciary duties to the Partnership’s unitholders. The Partnership

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Agreement also restricts the remedies available to the Partnership’s unitholders for actions taken by the General Partner that, without those limitations, might constitute breaches of its fiduciary duty.

The Partnership Agreement provides that the General Partner will not be in breach of its obligations under the Partnership Agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is (a) approved by the conflicts committee of the Board, although the General Partner is not obligated to seek such approval; (b) approved by the vote of a majority of our outstanding common units, excluding any common units owned by the General Partner and its affiliates; (c) on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or (d) fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

The General Partner may, but is not required to, seek the approval of such resolution from the conflicts committee of the Board. In connection with a situation involving a conflict of interest, any determination by the General Partner must be made in good faith, provided that, if the General Partner does not seek approval from the conflicts committee and the Board determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in subclauses (c) or (d) above, then it will conclusively be deemed that, in making its decision, the Board acted in good faith. Unless the resolution of a conflict is specifically provided for in the Partnership Agreement, the General Partner or the conflicts committee may consider any factors that it determines in good faith to be appropriate when resolving a conflict. When the Partnership Agreement provides that someone act in good faith, it requires that person to reasonably believe he is acting in the best interests of the Partnership. Please read Part I, Item 1A (“Risk Factors—Risks Inherent in an Investment in Us”).

Procedures for Review, Approval and Ratification of Related Person Transactions

If a conflict or potential conflict of interest arises between the General Partner and its affiliates, including Energy Transfer, on the one hand and the Partnership and its limited partners, on the other hand, the resolution of any such conflict or potential conflict is addressed as described under “−Conflicts of Interest.”

Pursuant to the Partnership’s Code of Business Conduct and Ethics and Corporate Governance Guidelines, directors, officers and employees are required to disclose any situations that reasonably would be expected to give rise to a conflict of interest and report it to their supervisor, the Partnership’s general counsel or the Board, as appropriate.

Director Independence

Please see Part III, Item 10 (“Directors, Executive Officers and Corporate Governance—Board of Directors”) for a discussion of director independence matters.

ITEM 14.Principal Accountant Fees and Services

The following table sets forth fees paid for professional services rendered by KPMG LLP, our independent registered public accounting firm until April 5, 2018, during the year ended December 31, 2017:

|  | Year Ended December 31,
|  | 2017
|  | (in millions)
Audit Fees (1) |  | $ | 0.6
Audit-Related Fees |  |  | —
Tax Fees |  |  | —
All Other Fees |  |  | —
Total |  | $ | 0.6

| (1) |  | Expenditures classified as “Audit Fees” above were billed to the Partnership and include the audits of our annual financial statements, work related to the registration statements, reviews of our quarterly financial statements, and fees associated with comfort letters and consents related to securities offerings and registration statements.

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The following table sets forth fees paid for professional services rendered by Grant Thornton LLP (“Grant Thornton”), our independent registered public accounting firm since April 5, 2018, during the year ended December 31, 2018:

|  | Year Ended December 31,
|  | 2018 (1)
|  | (in millions)
Audit Fees (2) |  | $ | 1.5
Audit-Related Fees |  |  | —
Tax Fees |  |  | —
All Other Fees |  |  | —
Total |  | $ | 1.5

| (1) |  | In connection with the Transactions, we appointed Grant Thornton as our independent registered public accounting firm on April 5, 2018.

| (2) |  | Expenditures classified as “Audit Fees” above were billed to the Partnership and include the audits of our annual financial statements and internal control over financial reporting, reviews of our quarterly financial statements, and fees associated with comfort letters and consents related to securities offerings and registration statements.

The Audit Committee has adopted the Audit Committee Charter, which is available on our website and which requires the Audit Committee to pre-approve all audit and non-audit services to be provided by our independent registered public accounting firm. The Audit Committee does not delegate its pre-approval responsibilities to management or to an individual member of the Audit Committee. The Audit Committee approved 100% of the services described above.

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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:

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Exhibit Number |  | Description
2.1 |  | 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 for certain purposes therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 to the Partnership’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 to Exhibit 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 Exhibit 3.1 to Amendment No. 3 of the Partnership’s registration statement on Form S-1 (Registration No. 333-174803) filed on December 21, 2011)
3.2 |  | Second Amended and Restated Agreement of Limited Partnership of USA Compression Partners, LP (incorporated by reference to Exhibit 3.1 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on April 6, 2018)
4.1 |  | Indenture, dated as of March 23, 2018 by and among USA Compression Partners, LP, USA Compression Finance Corp., the subsidiary guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on March 26, 2018)
4.2 |  | First Supplemental Indenture, dated as of April 2, 2018, among USA Compression Partners, LP, USA Compression Finance Corp., the guarantors named on the signature pages thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on April 6, 2018)
4.3 |  | Form of 6.875% Senior Note due 2026 (incorporated by reference to Exhibit 4.2 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on March 26, 2018)
4.4 |  | Registration Rights Agreement, dated as of March 23, 2018, by and among USA Compression Partners, LP, USA Compression Finance Corp., the subsidiary guarantors named therein and J.P. Morgan Securities LLC and Barclays Capital Inc., as representatives of the initial purchasers named therein (incorporated by reference to Exhibit 4.3 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on March 26, 2016).
4.5 |  | Registration Rights Agreement, dated as of April 2, 2018, by and among USA Compression Partners, LP, ETE, ETP and USA Compression Holdings, LLC (incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on April 6, 2018)
4.6 |  | Registration Rights Agreement, dated as of April 2, 2018, by and between USA Compression Partners, LP and the Purchasers party thereto (incorporated by reference to Exhibit 4.2 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on April 6, 2018)
4.7 |  | Board Representation Agreement, dated as of April 2, 2018, by and among USA Compression Partners, LP, USA Compression GP, LLC, Energy Transfer Equity, L.P. and the Purchasers party thereto (incorporated by reference to Exhibit 4.3 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on April 6, 2018)
10.1 |  | Fifth Amended and Restated Credit Agreement dated as of December 13, 2013, by and among USA Compression Partners, LP, USAC OpCo 2, LLC and USAC Leasing 2, LLC, as guarantors, USA Compression Partners, LLC and USAC Leasing, LLC, as borrowers, the lenders party thereto from time to time, JPMorgan Chase Bank, N.A., as agent and LC issuer, J.P. Morgan Securities LLC, as lead arranger and sole book runner, Wells Fargo Bank, N.A., as documentation agent, and Regions Bank, as syndication agent (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on December 17, 2013)

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10.2 |  | Letter Agreement by and among USA Compression Partners, LLC, USAC Leasing, LLC, USA Compression Partners, LP, USAC Leasing 2, LLC, USAC OpCo 2, LLC, the Lenders party thereto and JPMorgan 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, USAC Leasing, LLC, USAC OpCo 2, LLC and USAC Leasing 2, LLC, as borrowers, the lenders party thereto and JPMorgan Chase Bank, N.A., as agent and LC issuer (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on January 9, 2015)
10.4 |  | Third Amendment to the Fifth Amended and Restated Credit Agreement, dated as of March 18, 2016, by and among USA Compression Partners, LP, as guarantor, USA Compression Partners, LLC, USAC Leasing, LLC, USAC OpCo2, LLC and USAC Leasing 2, LLC, as borrowers, the lenders party thereto and JP Morgan Chase Bank, N.A., as agent and LC issuer (incorporated by reference to Exhibit 10.1 to the Partnership’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, USAC Leasing, LLC, USAC OpCo2, LLC and USAC Leasing 2, LLC, as borrowers, the lenders party thereto and JP Morgan Chase Bank, N.A., as agent and LC issuer and Swingline Lender (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on February 2, 2018)
10.6 |  | Sixth Amended and Restated Credit Agreement, dated as of April 2, 2018, by and among the Partnership, as borrower, USAC OpCo 2, LLC, USAC Leasing 2, LLC, USA Compression Partners, LLC, USAC Leasing, LLC, CDM Resource Management LLC and CDM Environmental & Technical Services LLC and USA Compression Finance Corp., the lenders party thereto from time to time, JPMorgan Chase Bank, N.A., as agent and an LC issuer, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Regions Capital Markets, a division of Regions Bank, RBC Capital Markets and Wells Fargo Bank, N.A., as joint lead arrangers and joint book runners, Barclays Bank PLC, Regions Bank, RBC Capital Markets and Wells Fargo Bank, N.A., as syndication agents, and MUFG Union Bank, N.A., SunTrust Bank and The Bank of Nova Scotia, as senior managing agents (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on April 6, 2018)
10.7† |  | Long-Term Incentive Plan of USA Compression Partners, LP (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on January 18, 2013)
10.8† |  | First Amendment to the USA Compression Partners, LP 2013 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q (File No. 001-35779) filed on November 6, 2018)
10.9† |  | Employment Agreement, dated December 23, 2010, between USA Compression Partners, LLC and Eric D. Long (incorporated by reference to Exhibit 10.5 to Amendment No. 4 of the Partnership’s registration statement on Form S-1 (Registration No. 333-174803) filed on February 13, 2012)
10.10† |  | Employment Agreement, dated April 17, 2013, between USA Compression Management Services, LLC and Matthew C. Liuzzi (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on January 15, 2015)
10.11† |  | Employment Agreement, dated July 15, 2013, between USA Compression Management Services, LLC and William G. Manias (incorporated by reference to Exhibit 10.7 to the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015 (File No. 001-35779) filed on February 11, 2016)
10.12† |  | Employment Agreement, dated December 23, 2010, between USA Compression Partners, LLC and David A. Smith (incorporated by reference to Exhibit 10.8 to Amendment No. 4 of the Partnership’s registration statement on Form S-1 (Registration No. 333-174803) filed on February 13, 2012)

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10.13†* |  | Employment Agreement, dated July 1, 2016, between USA Compression Management Services, LLC and Sean T. Kimble
10.14 |  | Services Agreement, dated effective January 1, 2013, by and among USA Compression Partners, LP, USA Compression GP, LLC and USA Compression Management Services, LLC (incorporated by reference to Exhibit 10.11 to Amendment No. 10 of the Partnership’s registration statement on Form S-1 (Registration No. 333-174803) filed on January 7, 2013)
10.15 |  | Amendment No. 1 to Services Agreement, dated effective November 3, 2017, by and among USA Compression 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 (File No. 001-35779) filed on November 7, 2017)
10.16† |  | USA Compression Partners, LP 2013 Long-Term Incentive Plan—Form of Director Phantom Unit Agreement (incorporated by reference to Exhibit 10.8 to the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2012 (File No. 001-35779) filed on March 28, 2013)
10.17† |  | USA Compression Partners, LP 2013 Long-Term Incentive Plan—Form of Employee Phantom Unit Agreement (incorporated by reference to Exhibit 10.10 to the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013 (File No. 001-35779) filed on February 20, 2014)
10.18† |  | USA Compression Partners, LP 2013 Long-Term Incentive Plan—Form of Director Phantom Unit Agreement (in lieu of Annual Cash Retainer) (incorporated by reference to Exhibit 10.10 to the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2012 (File No. 001-35779) filed on March 28, 2013)
10.19† |  | USA Compression Partners, LP 2013 Long-Term Incentive Plan—Form of Director Phantom Unit Agreement (incorporated by reference to Exhibit 10.5 to the Partnership’s Quarterly Report on form 10-Q (File No. 001-35779) filed on November 6, 2018)
10.20† |  | USA Compression Partners, LP Annual Cash Incentive Program (incorporated by reference to Exhibit 10.12 to the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2013 (File No. 001-35779) filed on February 20, 2014)
10.21†* |  | USA Compression Partners, LP Amended and Restated Annual Cash Incentive Plan
10.22† |  | USA Compression Partners, LP 2013 Long-Term Incentive Plan—Form of Employee Phantom Unit Agreement (with updated performance metrics) (incorporated by reference to Exhibit 10.13 to the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015 (File No. 001-35779) filed on February 11, 2016)
10.23† |  | USA Compression Partners, LP 2013 Long-Term Incentive Plan – Form of Employee Phantom Unit Agreement (incorporated by reference to Exhibit 10.6 to the Partnership’s Quarterly Report on Form 10-Q (File No. 001-35779) filed on November 6, 2018)
10.24† |  | USA Compression Partners, LP 2018 Long-Term Incentive Plan – Form of Retention Phantom Unit Agreement (incorporated by reference to Exhibit 10.2 to the Partnership’s Quarterly Report on Form 10-Q (File No. 001-35779) filed on November 6, 2018)
10.25 |  | Form of Termination Agreement and Mutual Release (incorporated by reference to Exhibit 10.3 to the Partnership’s Quarterly Report on Form 10-Q (File No. 001-35779) filed on November 6, 2018)
10.26† |  | USA Compression GP, LLC Amended and Restated Outside Director Compensation Policy (incorporated by reference to Exhibit 10.4 to the Partnership’s Quarterly Report on Form 10-Q (File No. 001-35779) filed on November 6, 2018)
10.27 |  | Series A Preferred Unit and Warrant Purchase Agreement, dated January 15, 2018, among USA Compression Partners, LP and the purchasers party thereto (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on January 16, 2018)

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16.1 |  | Letter of KPMG LLP, dated April 9, 2018, regarding change in independent registered accounting firm (incorporated by reference to Exhibit 16.1 to the Partnership’s Current Report on Form 8-K/A (File No. 001-35779) filed on April 9, 2018)
21.1* |  | List of subsidiaries of USA Compression Partners, LP
23.1* |  | Consent of Grant Thornton LLP
31.1* |  | Certification of Chief Executive Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934
31.2* |  | Certification of Chief Financial Officer pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934
32.1# |  | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2# |  | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1* |  | Unaudited pro forma condensed consolidated statement of operations of USA Compression Partners, LP and the CDM Compression Business for the year ended December 31, 2018
101.INS* |  | XBRL Instance Document
101.SCH* |  | XBRL Extension Schema Document
101.CAL* |  | XBRL Calculation Linkbase Document
101.DEF* |  | XBRL Definition Linkbase Document
101.LAB* |  | XBRL Label Linkbase Document
101.PRE* |  | XBRL Presentation Linkbase Document

.

*Filed Herewith.

#Furnished herewith; not considered to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section.

†Management contract or compensatory plan or arrangement.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

| USA COMPRESSION PARTNERS, LP
| By: | USA Compression GP, LLC,
|  | its General Partner
| By: | /s/ Eric D. Long
|  | Eric D. Long
|  | President and Chief Executive Officer
|  | (Principal Executive Officer)
| Date: | February 19, 2019

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 19, 2019.

Name |  | Title
/s/ Eric D. Long |  | President and Chief Executive Officer and Director
Eric D. Long |  | (Principal Executive Officer)
/s/ Matthew C. Liuzzi |  | Vice President, Chief Financial Officer and Treasurer
Matthew C. Liuzzi |  | (Principal Financial Officer)
/s/ G. Tracy Owens |  | Vice President, Finance and Chief Accounting Officer
G. Tracy Owens |  | (Principal Accounting Officer)
/s/ Michael Bradley |  |
Michael Bradley |  | Director
/s/ Christopher R. Curia |  |
Christopher R. Curia |  | Director
/s/ Matthew S. Hartman |  |
Matthew S. Hartman |  | Director
/s/ Glenn E. Joyce |  |
Glenn E. Joyce |  | Director
/s/ Thomas E. Long |  |
Thomas E. Long |  | Director
/s/ Thomas P. Mason |  |
Thomas P. Mason |  | Director
/s/ Matthew S. Ramsey |  |
Matthew S. Ramsey |  | Director
/s/ William S. Waldheim |  |
William S. Waldheim |  | Director

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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm | F-2
Consolidated Balance Sheets as of December 31, 2018 and 2017 | F-3
Consolidated Statements of Operations for the years ended December 31, 2018, 2017 and 2016 | F-4
Consolidated Statements of Changes in Partners’ Capital and Predecessor Parent Company Net Investment for the years ended December 31, 2018, 2017 and 2016 | F-5
Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016 | F-6
Notes to Consolidated Financial Statements | F-7
Supplemental Selected Quarterly Financial Data | S-1

F-1

Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of USA Compression GP, LLC and

Unitholders of USA Compression Partners, LP

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of USA Compression Partners, LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2018 and 2017, the related consolidated statements of operations, changes in partners’ capital and predecessor parent company net investment, and cash flows for each of the three years in the period ended December 31, 2018, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of December 31, 2018, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 19, 2019 expressed an unqualified opinion thereon.

Basis for opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ GRANT THORNTON LLP

We have served as the Partnership’s auditor since 2017.

Houston, Texas

February 19, 2019

F-2

Table of Contents

USA COMPRESSION PARTNERS, LP

Consolidated Balance Sheets

(in thousands)

|  | December 31, |
|  | 2018 |  | 2017 |
Assets |  |  |  |  |  |  |
Current assets: |  |  |  |  |  |  |
Cash and cash equivalents |  | $ | 99 |  | $ | 4,013 |
Accounts receivable, net: |  |  |  |  |  |  |
Trade, net |  |  | 75,572 |  |  | 32,696 |
Other |  |  | 3,809 |  |  | — |
Related party receivables |  |  | 47,661 |  |  | 45 |
Inventory, net |  |  | 89,007 |  |  | 33,221 |
Prepaid expenses and other assets |  |  | 1,592 |  |  | 4,209 |
Total current assets |  |  | 217,740 |  |  | 74,184 |
Installment receivable |  |  | 6,924 |  |  | — |
Property and equipment, net |  |  | 2,521,488 |  |  | 1,192,921 |
Identifiable intangible assets, net |  |  | 392,550 |  |  | 198,215 |
Goodwill |  |  | 619,411 |  |  | 253,428 |
Other assets |  |  | 16,536 |  |  | 205 |
Total assets |  | $ | 3,774,649 |  | $ | 1,718,953 |
Liabilities, Partners’ Capital and Predecessor Parent Company Net Investment |  |  |  |  |  |  |
Current liabilities: |  |  |  |  |  |  |
Accounts payable |  | $ | 23,804 |  | $ | 1,383 |
Related party payables |  |  | 395 |  |  | 1,977 |
Accrued liabilities |  |  | 94,028 |  |  | 41,513 |
Deferred revenue |  |  | 31,372 |  |  | 2,220 |
Total current liabilities |  |  | 149,599 |  |  | 47,093 |
Long-term debt, net |  |  | 1,759,058 |  |  | — |
Other liabilities |  |  | 9,827 |  |  | 6,990 |
Total liabilities |  |  | 1,918,484 |  |  | 54,083 |
Preferred Units |  |  | 477,309 |  |  | — |
Commitments and contingencies |  |  |  |  |  |  |
Partners’ capital: |  |  |  |  |  |  |
Limited partner interest: |  |  |  |  |  |  |
Common units, 89,984 units issued and outstanding as of December 31, 2018 |  |  | 1,289,731 |  |  | — |
Class B Units, 6,398 units issued and outstanding as of December 31, 2018 |  |  | 75,146 |  |  | — |
Warrants |  |  | 13,979 |  |  | — |
Predecessor parent company net investment |  |  | — |  |  | 1,664,870 |
Total partners’ capital and predecessor parent company net investment |  |  | 1,378,856 |  |  | 1,664,870 |
Total liabilities, partners’ capital and predecessor parent company net investment |  | $ | 3,774,649 |  | $ | 1,718,953 |

See accompanying notes to consolidated financial statements.

F-3

Table of Contents

USA COMPRESSION PARTNERS, LP

Consolidated Statements of Operations

(in thousands, except per unit amounts)

|  | Year Ended December 31, |
|  | 2018 |  | 2017 |  | 2016 |
Revenues: |  |  |  |  |  |  |  |  |  |
Contract operations |  | $ | 546,896 |  | $ | 249,346 |  | $ | 239,143 |
Parts and service |  |  | 20,402 |  |  | 10,085 |  |  | 7,921 |
Related party |  |  | 17,054 |  |  | 17,240 |  |  | 16,873 |
Total revenues |  |  | 584,352 |  |  | 276,671 |  |  | 263,937 |
Costs and expenses: |  |  |  |  |  |  |  |  |  |
Cost of operations, exclusive of depreciation and amortization |  |  | 214,724 |  |  | 125,204 |  |  | 112,898 |
Selling, general and administrative |  |  | 68,995 |  |  | 24,944 |  |  | 22,739 |
Depreciation and amortization |  |  | 213,692 |  |  | 166,558 |  |  | 155,134 |
Loss (gain) on disposition of assets |  |  | 12,964 |  |  | (367) |  |  | 120 |
Impairment of compression equipment |  |  | 8,666 |  |  | — |  |  | — |
Impairment of goodwill |  |  | — |  |  | 223,000 |  |  | — |
Total costs and expenses |  |  | 519,041 |  |  | 539,339 |  |  | 290,891 |
Operating income (loss) |  |  | 65,311 |  |  | (262,668) |  |  | (26,954) |
Other income (expense): |  |  |  |  |  |  |  |  |  |
Interest expense, net |  |  | (78,377) |  |  | — |  |  | — |
Other |  |  | 41 |  |  | (223) |  |  | (153) |
Total other expense |  |  | (78,336) |  |  | (223) |  |  | (153) |
Net loss before income tax expense (benefit) |  |  | (13,025) |  |  | (262,891) |  |  | (27,107) |
Income tax expense (benefit) |  |  | (2,474) |  |  | 1,843 |  |  | (163) |
Net loss |  |  | (10,551) |  |  | (264,734) |  |  | (26,944) |
Less: distributions on Preferred Units |  |  | (36,430) |  |  | — |  |  | — |
Net loss attributable to common and Class B unitholders' interests |  | $ | (46,981) |  | $ | (264,734) |  | $ | (26,944) |
Net loss attributable to: |  |  |  |  |  |  |  |  |  |
Common units |  | $ | (32,053) |  |  |  |  |  |  |
Class B units |  | $ | (14,928) |  |  |  |  |  |  |
Weighted average common units outstanding - basic and diluted |  |  | 74,481 |  |  |  |  |  |  |
Weighted average Class B Units outstanding - basic and diluted |  |  | 6,398 |  |  |  |  |  |  |
Basic and diluted net loss per common unit |  | $ | (0.43) |  |  |  |  |  |  |
Basic and diluted net loss per Class B Unit |  | $ | (2.33) |  |  |  |  |  |  |
Distributions declared per common unit |  | $ | 1.575 |  |  |  |  |  |  |

See accompanying notes to consolidated financial statements.

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USA COMPRESSION PARTNERS, LP

Consolidated Statements of Changes in Partners’ Capital

And Predecessor Parent Company Net Investment

(in thousands)

|  |  |  |  |  |  |  |  |  |  | Predecessor Parent |  |  |
|  |  |  |  |  |  |  |  |  |  | Company Net |  |  |
|  | Common Units |  | Class B Units |  | Warrants |  | Investment |  | Total
Ending balance, December 31, 2015 |  | $ | — |  | $ | — |  | $ | — |  | $ | 2,042,996 |  | $ | 2,042,996
Predecessor net loss |  |  | — |  |  | — |  |  | — |  |  | (26,944) |  |  | (26,944)
Predecessor parent company net distributions |  |  | — |  |  | — |  |  | — |  |  | (86,829) |  |  | (86,829)
Ending balance, December 31, 2016 |  |  | — |  |  | — |  |  | — |  |  | 1,929,223 |  |  | 1,929,223
Predecessor net loss |  |  | — |  |  | — |  |  | — |  |  | (264,734) |  |  | (264,734)
Predecessor parent company net contributions |  |  | — |  |  | — |  |  | — |  |  | 381 |  |  | 381
Ending balance, December 31, 2017 |  |  | — |  |  | — |  |  | — |  |  | 1,664,870 |  |  | 1,664,870
Predecessor net loss for the period January 1, 2018 to April 1, 2018 |  |  | — |  |  | — |  |  | — |  |  | (23,370) |  |  | (23,370)
Predecessor parent company net contribution for the period January 1, 2018 to April 1, 2018 |  |  | — |  |  | — |  |  | — |  |  | 26,730 |  |  | 26,730
Allocation of Predecessor parent company net investment |  |  | 1,668,230 |  |  | — |  |  | — |  |  | (1,668,230) |  |  | —
Deemed distribution for additional interest in USA Compression Predecessor |  |  | (36,111) |  |  | — |  |  | — |  |  | — |  |  | (36,111)
Purchase Price Adjustment for USA Compression Partners, LP |  |  | (654,340) |  |  | — |  |  | — |  |  | — |  |  | (654,340)
Issuance of common units for the Equity Restructuring |  |  | 135,440 |  |  | — |  |  | — |  |  | — |  |  | 135,440
Issuance of common units for the CDM Acquisition |  |  | 324,910 |  |  | — |  |  | — |  |  | — |  |  | 324,910
Issuance of Class B Units for the CDM Acquisition |  |  | — |  |  | 86,125 |  |  | — |  |  | — |  |  | 86,125
Issuance of Warrants |  |  | — |  |  | — |  |  | 13,979 |  |  | — |  |  | 13,979
Vesting of phantom units |  |  | 5,283 |  |  | — |  |  | — |  |  | — |  |  | 5,283
Distributions and distribution equivalent rights |  |  | (141,694) |  |  | — |  |  | — |  |  | — |  |  | (141,694)
Issuance of common units under the DRIP |  |  | 645 |  |  | — |  |  | — |  |  | — |  |  | 645
Net loss for the period April 2, 2018 to December 31, 2018 |  |  | (12,632) |  |  | (10,979) |  |  | — |  |  | — |  |  | (23,611)
Partners' capital ending balance, December 31, 2018 |  | $ | 1,289,731 |  | $ | 75,146 |  | $ | 13,979 |  | $ | — |  | $ | 1,378,856

See accompanying notes to consolidated financial statements.

F-5

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USA COMPRESSION PARTNERS, LP

Consolidated Statements of Cash Flows

(in thousands)

|  | Year Ended December 31, |
|  | 2018 |  | 2017 |  | 2016 |
Cash flows from operating activities: |  |  |  |  |  |  |  |  |  |
Net loss |  | $ | (10,551) |  | $ | (264,734) |  | $ | (26,944) |
Adjustments to reconcile net loss to net cash provided by operating activities: |  |  |  |  |  |  |  |  |  |
Depreciation and amortization |  |  | 213,692 |  |  | 166,558 |  |  | 155,134 |
Bad debt expense (recovery) |  |  | 633 |  |  | (1,777) |  |  | (593) |
Amortization of debt issue costs |  |  | 5,080 |  |  | — |  |  | — |
Unit-based compensation expense |  |  | 11,740 |  |  | 4,048 |  |  | 3,539 |
Deferred income tax expense (benefit) |  |  | (2,663) |  |  | 1,801 |  |  | (155) |
Loss (gain) on disposition of assets |  |  | 12,964 |  |  | (367) |  |  | 120 |
Impairment of compression equipment |  |  | 8,666 |  |  | — |  |  | — |
Impairment of goodwill |  |  | — |  |  | 223,000 |  |  | — |
Changes in assets and liabilities, net of effects of business combination: |  |  |  |  |  |  |  |  |  |
Accounts receivable, net |  |  | (50,029) |  |  | 9,331 |  |  | 25,578 |
Inventory, net |  |  | (6,736) |  |  | (698) |  |  | (515) |
Prepaid expenses and other current assets |  |  | 9,298 |  |  | (3,569) |  |  | (167) |
Other noncurrent assets |  |  | (59) |  |  | 8 |  |  | (34) |
Accounts payable and related party payables |  |  | (5,140) |  |  | 2,531 |  |  | (2,291) |
Other current liabilities |  |  | (4,879) |  |  | 228 |  |  | (1,769) |
Accrued liabilities and deferred revenue |  |  | 44,324 |  |  | (404) |  |  | (21,840) |
Net cash provided by operating activities |  |  | 226,340 |  |  | 135,956 |  |  | 130,063 |
Cash flows from investing activities: |  |  |  |  |  |  |  |  |  |
Capital expenditures, net |  |  | (266,566) |  |  | (157,292) |  |  | (61,575) |
Proceeds from disposition of property and equipment |  |  | 7,466 |  |  | 14,834 |  |  | 24,808 |
Proceeds from insurance recovery |  |  | 409 |  |  | — |  |  | — |
Acquisition of USA Compression Predecessor |  |  | (1,231,478) |  |  | — |  |  | — |
Assumed cash acquired in business combination of USA Compression Partners, LP |  |  | 710,506 |  |  | — |  |  | — |
Net cash used in investing activities |  |  | (779,663) |  |  | (142,458) |  |  | (36,767) |
Cash flows from financing activities: |  |  |  |  |  |  |  |  |  |
Proceeds from revolving credit facility |  |  | 697,684 |  |  | — |  |  | — |
Payments on revolving credit facility |  |  | (467,199) |  |  | — |  |  | — |
Proceeds from issuance of Preferred Units and Warrants, net |  |  | 479,100 |  |  | — |  |  | — |
Cash paid related to net settlement of unit-based awards |  |  | (4,447) |  |  | — |  |  | — |
Cash distributions on common units |  |  | (142,324) |  |  | — |  |  | — |
Cash distributions on Preferred Units |  |  | (24,242) |  |  | — |  |  | — |
Financing costs |  |  | (17,683) |  |  | — |  |  | — |
Contributions from (distributions to) Parent, net |  |  | 28,520 |  |  | (3,666) |  |  | (90,367) |
Net cash provided by (used in) financing activities |  |  | 549,409 |  |  | (3,666) |  |  | (90,367) |
Increase (decrease) in cash and cash equivalents |  |  | (3,914) |  |  | (10,168) |  |  | 2,929 |
Cash and cash equivalents, beginning of year |  |  | 4,013 |  |  | 14,181 |  |  | 11,252 |
Cash and cash equivalents, end of year |  | $ | 99 |  | $ | 4,013 |  | $ | 14,181 |
Supplemental cash flow information: |  |  |  |  |  |  |  |  |  |
Cash paid for interest, net of capitalized amounts |  | $ | 61,021 |  | $ | — |  | $ | — |
Cash paid for income taxes |  | $ | 183 |  | $ | — |  | $ | — |
Supplemental non-cash transactions: |  |  |  |  |  |  |  |  |  |
Non-cash distributions to certain common unitholders (DRIP) |  | $ | 645 |  | $ | — |  | $ | — |
Predecessor's Non-cash contribution (to) from Predecessor's Parent |  | $ | (1,790) |  | $ | 4,047 |  | $ | 3,538 |
Transfers to inventory from property and equipment |  | $ | (10,602) |  | $ | — |  | $ | — |
Transfer from long-term installment receivable to short-term |  | $ | (2,809) |  | $ | — |  | $ | — |
Transfer from long-term liabilities to short-term |  | $ | 914 |  | $ | — |  | $ | — |
Change in capital expenditures included in accounts payable and accrued liabilities |  | $ | (32,168) |  | $ | 17,300 |  | $ | (3,678) |
Deemed distribution for additional interest in USA Compression Predecessor |  | $ | (36,111) |  | $ | — |  | $ | — |
Issuance of common units for the CDM Acquisition |  | $ | 324,910 |  | $ | — |  | $ | — |
Issuance of Class B Units for the CDM Acquisition |  | $ | 86,125 |  | $ | — |  | $ | — |
Issuance of common units for the Equity Restructuring |  | $ | 135,440 |  | $ | — |  | $ | — |

See accompanying notes to consolidated financial statements.

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Table of Contents

USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

(1) Organization and Description of Business

Unless the context otherwise requires or where otherwise indicated, the terms “our”, “we”, “us”, “the Partnership” and similar language when used in the present or future tense and for periods on or subsequent to April 2, 2018 (the “Transactions Date”) refer to USA Compression Partners, LP, collectively with its consolidated operating subsidiaries, including the USA Compression Predecessor. Unless the context otherwise requires or where otherwise indicated, the term “USA Compression Predecessor,” as well as the terms “our,” “we,” “us” and “its” when used in an historical context or in reference to periods prior to the Transactions Date, refers to CDM Resource Management LLC (“CDM Resource”) and CDM Environmental & Technical Services LLC (“CDM E&T”) collectively, which has been deemed to be the predecessor of the Partnership for financial reporting purposes.

We are a Delaware limited partnership. Through our operating subsidiaries, we provide compression services under fixed-term contracts with customers in the natural gas and crude oil industries, using natural gas compression packages that we design, engineer, own, operate and maintain. We primarily 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.

USA Compression GP, LLC, a Delaware limited liability company, serves as our general partner and is referred to herein as the “General Partner”. The General Partner was wholly owned by Energy Transfer Equity, L.P. (“ETE”), through its wholly owned subsidiary, Energy Transfer Partners, L.L.C. (“ETP LLC”). In October 2018, ETE and Energy Transfer Partners, L.P. (“ETP”) completed the merger of ETP with a wholly owned subsidiary of ETE in a unit-for-unit exchange (the “ETE Merger”). Following the closing of the ETE Merger, ETE changed its name to “Energy Transfer LP” and ETP changed its name to “Energy Transfer Operating, L.P.” Upon the closing of the ETE Merger, ETE contributed to ETP 100% of the limited liability company interests in the General Partner. References herein to “ETP” refer to Energy Transfer Partners, L.P. for periods prior to the ETE Merger and Energy Transfer Operating, L.P. following the ETE Merger, and references to “ETE” refer to Energy Transfer Equity, L.P. for periods prior to the ETE Merger and Energy Transfer LP following the ETE Merger.

The USA Compression Predecessor owned and operated a fleet of compressors used to provide natural gas compression services for customer specific systems. The USA Compression Predecessor also owned and operated a fleet of equipment used to provide treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling, and dehydration. The USA Compression Predecessor had operations located in Texas, Oklahoma, Louisiana, Arkansas, Pennsylvania, New Mexico, Colorado, Ohio, and West Virginia.

Certain of our operating subsidiaries are borrowers under a revolving credit facility and the Partnership is a guarantor of that revolving credit facility (see Note 10). The accompanying consolidated financial statements include the accounts of the Partnership and its operating subsidiaries, all of which are wholly owned by us.

Net loss is allocated to our common units and Class B Units using the two-class income allocation method. All intercompany balances and transactions have been eliminated in consolidation. Our common units trade on the New York Stock Exchange under the ticker symbol “USAC”.

USA Compression Management Services, LLC (“USAC Management”), a wholly owned subsidiary of the General Partner, 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 of December 31, 2018, USAC Management had 864 full time employees. None of our employees are subject to collective bargaining agreements.

CDM Acquisition

On the Transactions Date, we consummated the transactions contemplated by the Contribution Agreement dated January 15, 2018, pursuant to which, among other things, we acquired all of the issued and outstanding membership interests of the USA Compression Predecessor from ETP (the “CDM Acquisition”) in exchange for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 common units representing limited partner

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

interests in us (the “common units”), (ii) 6,397,965 Class B units representing limited partner interests in us (“Class B Units”) and (iii) $1.2 billion in cash (including customary closing adjustments).

General Partner Purchase Agreement

On the Transactions Date, and in connection with the closing of the CDM Acquisition, we consummated the transactions contemplated by the Purchase Agreement dated January 15, 2018, by and among ETE, ETP LLC, USA Compression Holdings, LLC (“USA Compression Holdings”) and, solely for certain purposes therein, R/C IV USACP Holdings, L.P. and ETP, pursuant to which, among other things, ETE acquired from USA Compression Holdings (i) all of the outstanding limited liability company interests in the General Partner and (ii) 12,466,912 common units for cash consideration paid by ETE to USA Compression Holdings equal to $250.0 million (the “GP Purchase”). Upon the closing of the ETE Merger, ETE contributed all of the interests in the General Partner and the 12,466,912 common units to ETP.

Equity Restructuring Agreement

On the Transactions Date, and in connection with the closing of the CDM Acquisition, we consummated the transactions contemplated by the Equity Restructuring Agreement dated January 15, 2018, pursuant to which, among other things, the Partnership, the General Partner and ETE agreed to cancel the Partnership’s Incentive Distribution Rights (“IDRs”) and convert the General Partner Interest (as defined in the Equity Restructuring Agreement) into a non-economic general partner interest, in exchange for the Partnership’s issuance of 8,000,000 common units to the General Partner (the “Equity Restructuring”).

The CDM Acquisition, GP Purchase and Equity Restructuring are collectively referred to as the “Transactions.”

(2) Basis of Presentation and Significant Accounting Policies

Basis of Presentation

The Partnership

The consolidated financial statements give effect to the business combination and the Transactions discussed above under the acquisition method of accounting, and the business combination has been accounted for in accordance with the applicable reverse merger accounting guidance. ETE acquired a controlling financial interest in us through the acquisition of the General Partner. As a result, the USA Compression Predecessor is deemed to be the accounting acquirer of the Partnership because its ultimate parent company obtained control of the Partnership through its control of the General Partner. Consequently, the USA Compression Predecessor is deemed to be the predecessor of the Partnership for financial reporting purposes, and the historical financial statements of the Partnership now reflect the USA Compression Predecessor for all periods prior to the closing of the Transactions. The closing of the Transactions occurred on the Transactions Date.

The USA Compression Predecessor’s assets and liabilities retained their historical carrying values. Additionally, the Partnership’s assets acquired and liabilities assumed by the USA Compression Predecessor in the business combination have been recorded at their fair values measured as of the Transactions Date. The excess of the assumed purchase price of the Partnership over the estimated fair values of the Partnership’s net assets acquired has been recorded as goodwill. The assumed purchase price and fair value of the Partnership has been determined using acceptable fair value methods. Additionally, because the USA Compression Predecessor is reflected at ETE’s historical cost, the difference between the $1.7 billion in consideration paid by the Partnership and ETE’s historical carrying values (net book value) at the Transactions Date has been recorded as a decrease to partners’ capital in the amount of $36.1 million.

Our accompanying consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”) and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). As noted above, the historical consolidated financial statements of the Partnership now reflect the historical consolidated financial statements of the USA Compression Predecessor in accordance with the

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

applicable accounting and financial reporting guidance. Therefore, the historical consolidated financial statements are comprised of the balance sheet and statement of operations of the USA Compression Predecessor as of and for periods prior to the Transactions Date. The historical consolidated financial statements are also comprised of the consolidated balance sheet and statement of operations of the Partnership, which includes the USA Compression Predecessor, as of and for all periods subsequent to the Transactions Date. The presentation of certain line items in historical periods have been conformed to the Partnership’s current year presentation for comparability.

USA Compression Predecessor

ETP allocated various corporate overhead expenses to the USA Compression Predecessor based on a percentage of assets, net income (loss), or adjusted earnings before interest, taxes, depreciation and amortization (“EBITDA”). These allocations are not necessarily indicative of the cost that the USA Compression Predecessor would have incurred had it operated as an independent standalone entity. The USA Compression Predecessor also historically relied upon ETP for funding operating and capital expenditures as necessary. As a result, the historical financial statements of the USA Compression Predecessor may not fully reflect or be necessarily indicative of what the USA Compression Predecessor’s balance sheet, results of operations and cash flows would have been or will be in the future.

Certain expenses incurred by ETP are only indirectly attributable to the USA Compression Predecessor. As a result, certain assumptions and estimates are made in order to allocate a reasonable share of such expenses to the USA Compression Predecessor, so that the accompanying financial statements reflect substantially all costs of doing business. The allocations and related estimates and assumptions are described more fully in Note 14.

Certain amounts of the USA Compression Predecessor’s revenues are derived from related party transactions, as described more fully in Note 14.

Significant Accounting Policies

Cash and Cash Equivalents

Cash and cash equivalents consist of all cash balances. We consider investments in highly liquid financial instruments purchased with an original maturity of 90 days or less to be cash equivalents.

Trade Accounts Receivable and Allowance for Doubtful Accounts

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. Our determination of the allowance for doubtful accounts requires us to make estimates and judgments regarding our customers’ ability to pay amounts due. We continuously evaluate the financial strength of our customers based on payment history, the overall business climate in which our customers operate and specific identification of customer bad debt and make adjustments to the allowance as necessary. Our evaluation of our customers’ financial strength is based on the aging of their respective receivables balance, customer correspondence, financial information and third-party credit ratings. Our evaluation of the business climate in which our customers operate is based on a review of various publicly-available materials regarding our customers’ industries, including the solvency of various companies in the industry.

The USA Compression Predecessor determined its allowance for doubtful accounts based upon historical write-off experience and specific identification of unrecoverable amounts.

Inventory

Inventory consists of serialized and non-serialized parts used primarily in the repair of compression units. All inventory is stated at the lower of cost or net realizable value. Serialized parts inventory is determined using the specific identification method, while non-serialized parts inventory is determined using the weighted average cost method. Purchases of these assets are considered operating activities in the Consolidated Statements of Cash Flows.

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

Property and Equipment

Property and equipment are carried at cost except for (i) certain acquired assets which are recorded at fair value on their respective acquisition dates and (ii) impaired assets which are recorded at fair value on the last impairment evaluation date for which an adjustment was required. Overhauls and major improvements that increase the value or extend the life of compression equipment are capitalized and depreciated over 3 to 5 years. Ordinary maintenance and repairs are charged to cost of operations, exclusive of depreciation and amortization.

When property and equipment is retired or sold, its carrying value and the related accumulated depreciation are removed from our accounts and any associated gains or losses are recorded on our statements of operations in the period of sale or disposition.

Capitalized interest is calculated by multiplying the Partnership’s monthly effective interest rate on outstanding debt by the amount of qualifying costs, which include upfront payments to acquire certain compression units. Capitalized interest was $0.3 million for the year ended December 31, 2018. The USA Compression Predecessor had no capitalized interest for the years ended December 31, 2017 or 2016, as it did not hold any debt during either period.

Impairments of Long-Lived Assets

Long-lived assets with recorded values that are not expected to be recovered through future cash flows are written-down to 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 circumstance requiring compression units to be tested for impairment is when idle units do not meet the performance characteristics of our active revenue generating horsepower.

The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If the carrying value exceeds the sum of the undiscounted cash flows associated with the operating fleet, an impairment loss equal to the amount of the carrying value exceeding the fair value of the asset is recognized. The fair value of the asset is measured using quoted market prices or, in the absence of quoted market prices, based on an estimate of discounted cash flows, the expected net sale proceeds compared to the other similarly configured fleet units we recently sold or a review of other units recently offered for sale by third parties, or the estimated component value of the equipment we plan to use.

Refer to Note 7 for more detailed information about impairment charges during the year ended December 31, 2018.

Identifiable Intangible Assets

Identifiable intangible assets are recorded at cost and amortized using the straight-line method over their estimated useful lives, which is the period over which the assets are expected to contribute directly or indirectly to our future cash flows. The estimated useful lives range from 15 to 25 years.

We assess identifiable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. We did not record any impairment of identifiable intangible assets for the years ended December 31, 2018, 2017 or 2016.

Goodwill

Goodwill represents consideration paid in excess of the fair value of the identifiable net assets acquired in a business combination. Goodwill is not amortized, but is reviewed for impairment annually based on the carrying values as of October 1, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered.

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

The Partnership did not record any goodwill impairment during the year ended December 31, 2018. The USA Compression Predecessor recorded $223 million of goodwill impairment for the year ended December 31, 2017 and no goodwill impairment for the year ended December 31, 2016. Refer to the Goodwill section in Note 7 for more information about the goodwill impairment assessment performed during the years ended December 31, 2018 and 2017.

Predecessor Parent Company Net Investment

The USA Compression Predecessor participated in a centralized cash management function managed by ETP. Balances payable to or due from ETP generated under this arrangement are reflected in Predecessor parent company net investment.

ETP’s net investment in the operations of the USA Compression Predecessor is presented as Predecessor parent company net investment within the consolidated balance sheets. Predecessor parent company net investment represents the accumulated net earnings of the operations of the USA Compression Predecessor and accumulated net contributions from ETP. Net contributions for the period January 1, 2018 to April 1, 2018 were primarily comprised of intercompany operations and expense, cash clearing and other financing activities, and general and administrative cost allocations to the USA Compression Predecessor.

Income Taxes

These consolidated financial statements do not include a provision for income taxes as the Partnership is treated as a partnership for U.S. federal and state income tax purposes, with each partner being separately taxed on its distributive share of the Partnership’s items of income, gain, loss, or deduction. While the Partnership is generally not subject to entity-level income taxes, Texas imposes an entity-level income tax on partnerships. Refer to Note 9 for more detailed information about the Texas Franchise Tax for the years ended December 31, 2018, 2017 and 2016.

Pass Through Taxes

Sales taxes incurred on behalf of, and passed through to, customers are accounted for on a net basis.

Fair Value Measurements

Accounting standards on fair value measurements establish a framework for measuring fair value and stipulate disclosures about fair value measurements. The standards apply to recurring and non-recurring financial and non-financial assets and liabilities that require or permit fair value measurements. Among the required disclosures is the fair value hierarchy of 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 ability to access at the measurement date.

Level 2 inputs are those other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.

Level 3 inputs are unobservable inputs for the asset or liability.

As of December 31, 2018, our financial instruments consisted primarily of cash and cash equivalents, trade accounts receivable, trade accounts payable and long-term debt. The book values of cash and cash equivalents, trade accounts receivable, and trade accounts payable are representative of fair value due to their short-term maturities. The carrying amount of our revolving credit facility approximates fair value due to the floating interest rates associated with the debt.

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

The fair value of our 6.875% Senior Notes due 2026 (the “Senior Notes”) was estimated using quoted prices in inactive markets and is considered a Level 2 measurement. The following table summarizes the carrying amount and fair value of these assets and liabilities (in thousands):

|  | December 31,
Assets (Liabilities) |  | 2018 |  | 2017
Carrying amount of Senior Notes (1) |  | $ | 709,511 |  | $ | —
Fair value of Senior Notes |  |  | 696,000 |  |  | —

| (1) |  | Carrying amount is shown net of unamortized deferred financing costs. As of December 31, 2018, the outstanding aggregate principal amount of our Senior Notes was $725.0 million. See Note 10 for further details.

As of December 31, 2017, the USA Compression Predecessor did not have financial instruments with fair values determined using available market information and valuation methodologies. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to their short-term maturities.

As part of the impairment analysis of goodwill as of December 31, 2017, the fair value of the USA Compression Predecessor’s goodwill was re-measured using Level 3 inputs. Refer to the Goodwill section in Note 7 for more information about this valuation as of December 31, 2017.

Use of Estimates

The preparation of our consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the amounts reported in these consolidated financial statements and the accompanying results. Although these estimates are based on management’s available knowledge of current and expected future events, actual results could differ from these estimates.

Operating Segment

We operate in a single business segment, the compression services business.

(3) Acquisitions

The USA Compression Predecessor is deemed to be the accounting acquirer of the Partnership in the business combination because its ultimate parent company obtained control of the Partnership through its control of the General Partner. Consequently, the USA Compression Predecessor’s assets and liabilities retained their historical carrying values. The Partnership’s assets acquired and liabilities assumed by the USA Compression Predecessor have been recorded at their fair values measured as of the Transactions Date. The excess of the assumed purchase price of the Partnership over the estimated fair values of the Partnership’s net assets acquired has been recorded as goodwill. The assumed purchase price and fair value of the Partnership was determined using a combination of an income and cost valuation methodology, the fair value of the Partnership’s common units as of the Transactions Date and the consideration paid by ETE for the General Partner and IDRs. The valuation and purchase price allocation is considered final.

The property and equipment of the USA Compression Predecessor is reflected at historical carrying value, which is less than the consideration paid for the business. The excess of the consideration paid over the historical carrying value was $36.1 million and is reflected as a decrease to partners’ capital.

The Partnership incurred $21.7 million in transaction-related expenses prior to the Transactions Date, which were recognized by the Partnership when incurred in the periods prior to the Transactions Date, and therefore are not included within the results of operations presented within the consolidated financial statements for the year ended December 31, 2018.

For the period from April 2, 2018 to December 31, 2018, we recognized $269.2 million in revenues and $23.1 million in net income attributable to the Partnership’s historical assets.

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

The following table summarizes the assumed purchase price and fair value and the allocation to the assets acquired and liabilities assumed (in thousands):

Assumed purchase price allocation to USA Compression Partners, LP |  |  |
Current assets |  | $ | 786,258
Fixed assets |  |  | 1,331,850
Other long-term assets |  |  | 15,018
Customer relationships |  |  | 221,500
Total identifiable assets acquired |  |  | 2,354,626
Current liabilities |  |  | (110,465)
Long-term debt |  |  | (1,526,865)
Other long-term liabilities |  |  | (1,538)
Total liabilities assumed |  |  | (1,638,868)
Net identifiable assets acquired |  |  | 715,758
Goodwill (1) |  |  | 365,983
Net assets acquired |  | $ | 1,081,741
April 2, 2018 Transactions: |  |  |
Cash assumed in the CDM Acquisition |  |  | (710,506)
Issuance of Preferred Units |  |  | (465,121)
Issuance of Class B Units for the CDM Acquisition |  |  | (86,125)
Issuance of Warrants |  |  | (13,979)
Issuance of common units for the Equity Restructuring |  |  | (135,440)
Issuance of common units for the CDM Acquisition |  |  | (324,910)
Purchase Price Adjustment for USA Compression Partners, LP |  | $ | (654,340)

| (1) |  | Goodwill recognized from the business combination primarily relates to the value attributed to additional growth opportunities, synergies and operating leverage within the Partnership’s areas of operation. The valuation of goodwill recognized from the business combination is final.

Transition Services Agreement

In connection with the closing of the Transactions, we entered into an agreement with the USA Compression Predecessor and ETP pursuant to which ETP and its affiliates provided certain services to us with respect to the business and operations of the USA Compression Predecessor’s existing assets, including information technology, accounting and emissions testing services, for a period of three months following the closing of the Transactions. Expenses associated with the transition services agreement were $0.7 million for the year ended December 31, 2018.

Unaudited Pro Forma Financial Information

The following unaudited pro forma condensed financial information for the years ended December 31, 2018 and 2017 gives effect to the Transactions as if they had occurred on January 1, 2017. The unaudited pro forma condensed financial information has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Transactions taken place on the dates indicated and is not intended to be a projection of future events. The pro forma adjustments for the periods presented consist of (i) adjustments to combine the USA Compression Predecessor’s and the Partnership’s historical results of operations for the periods, (ii) adjustments to interest expense to include interest expense for additional revolving credit facility borrowings and include the interest expense associated with our Senior Notes (see Note 10), (iii) adjustments to depreciation and amortization expense attributable to adjustments recorded as a result of the purchase price allocation to the Partnership’s assets and liabilities and (iv) adjustments to net loss attributable to common units and Class B Units attributable to distributions on the Partnership’s Series A Preferred Units (the “Preferred Units”).

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

The following table presents the unaudited pro forma revenues, net loss and basic and diluted net loss per unit information for each period:

|  | Year Ended December 31,
|  | 2018 |  | 2017
Total revenues |  | $ | 662,091 |  | $ | 556,893
Net loss |  | $ | (44,894) |  | $ | (344,995)
Net loss attributable to common and Class B unitholders' interests |  | $ | (93,644) |  | $ | (393,745)
Basic and diluted net loss per common unit and Class B Unit |  | $ | (0.98) |  | $ | (4.14)

The pro forma net loss for the year ended December 31, 2018 includes expenses that were a direct result of the Transactions, including $1.0 million in employee severance charges attributable to employees not retained by the Partnership subsequent to the Transactions and $21.7 million in transaction expenses, including advisory, audit and legal fees. These expenses were recognized by the Partnership as they were incurred during the period from January 1, 2018 to April 1, 2018, but because the USA Compression Predecessor’s historical condensed consolidated financial statements are now reflected for that period, the condensed consolidated financial statements presented in accordance with GAAP for the year ended December 31, 2018 do not reflect such expenses incurred as a direct result of the Transactions.

(4) Trade Accounts Receivable

The allowance for doubtful accounts, which was $1.7 million and $0.8 million as of December 31, 2018 and 2017, respectively, is our best estimate of the amount of probable credit losses included in our existing accounts receivable. During the year ended December 31, 2018, we increased our allowance for doubtful accounts by $0.9 million, due primarily to estimated uncollectible amounts from customers of the USA Compression Predecessor.

The USA Compression Predecessor reduced its allowance for doubtful accounts by $4.1 million and $1.0 million during the years ended December 31, 2017 and 2016, respectively, due to write-offs of receivables and collections on accounts previously reserved. Due to the decrease in the allowance for doubtful accounts during 2017 and 2016, the USA Compression Predecessor recognized a reduction of bad debt expense of $1.8 million and $0.6 million for the years ended December 31, 2017 and 2016, respectively.

| (5) |  | Inventory

Components of inventory were as follows (in thousands):

|  | December 31,
|  | 2018 |  | 2017
Serialized parts |  | $ | 45,568 |  | $ | —
Non-serialized parts |  |  | 43,439 |  |  | 34,335
Total Inventory, gross |  |  | 89,007 |  |  | 34,335
Less: obsolete and slow moving reserve |  |  | — |  |  | (1,114)
Total Inventory, net |  | $ | 89,007 |  | $ | 33,221

(6) Installment Receivable

We granted a bargain purchase option to a customer with respect to certain compressor packages leased to the customer. The bargain purchase option provides the customer with an option to acquire the equipment at a value significantly less than the fair market value at the end of the lease term, which is July 31, 2021.

We accounted for this option as a sales type lease resulting in a current installment receivable included in other accounts receivable of $3.7 million and a long-term installment receivable of $6.9 million as of December 31, 2018. The USA Compression Predecessor had no capital lease installment receivables as of December 31, 2017.

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

Revenue and interest income related to the capital lease is recognized over the lease term. We recognize maintenance revenue within Contract operations revenue and interest income within Interest expense, net. Maintenance revenue was $1.0 million for the year ended December 31, 2018. Interest income was $0.7 million for the year ended December 31, 2018. The USA Compression Predecessor had no capital lease revenue or maintenance revenue related to capital lease for the years ended December 31, 2017 or 2016.

(7) Property and Equipment, Identifiable Intangible Assets and Goodwill

Property and Equipment

Property and equipment consisted of the following (in thousands):

|  | December 31, |
|  | 2018 |  | 2017 |
Compression and treating equipment |  | $ | 3,239,831 |  | $ | 1,799,151 |
Furniture and fixtures |  |  | 1,129 |  |  | 780 |
Automobiles and vehicles |  |  | 32,490 |  |  | 41,796 |
Computer equipment |  |  | 54,806 |  |  | 25,049 |
Buildings |  |  | 9,314 |  |  | 13,891 |
Land |  |  | 77 |  |  | 77 |
Leasehold improvements |  |  | 5,377 |  |  | 2,051 |
Total Property and equipment, gross |  |  | 3,343,024 |  |  | 1,882,795 |
Less: accumulated depreciation and amortization |  |  | (821,536) |  |  | (689,874) |
Total Property and equipment, net |  | $ | 2,521,488 |  | $ | 1,192,921 |

Depreciation is calculated using the straight-line method over the estimated useful lives of the assets as follows:

Compression equipment, acquired new |  | 25 years |
Compression equipment, acquired used |  | 5 - 25 years |
Furniture and fixtures |  | 3 - 10 years |
Vehicles and computer equipment |  | 1 - 10 years |
Buildings |  | 5 years |
Leasehold improvements |  | 5 years |

Depreciation expense on property and equipment was $186.5 million, $146.0 million and $134.6 million for the years ended December 31, 2018, 2017 and 2016, respectively.

The Partnership implemented a change in the estimated useful lives of the USA Compression Predecessor’s property and equipment to conform to the Partnership’s historical asset lives, which is accounted for as a change in accounting estimate beginning on the Transactions Date on a prospective basis. This change resulted in a $33.8 million increase to both operating income and net income for the year ended December 31, 2018, and a $0.42 increase to both basic and diluted earnings per common unit and Class B Unit for year ended December 31, 2018.

As of December 31, 2018 and 2017, there was $7.9 million and $14.6 million, respectively, of property and equipment purchases in accounts payable and accrued liabilities.

During the year ended December 31, 2018, there were net losses on the disposition of assets of $13.0 million, primarily attributable to disposals of various property and equipment by the USA Compression Predecessor. During the years ended December 31, 2017 and 2016, the USA Compression Predecessor recognized a $0.4 million net loss and $0.1 million net gain on disposition of assets, respectively.

For the year ended December 31, 2018, we evaluated the future deployment of our idle fleet under then-current market conditions and determined to retire and re-utilize key components of 103 compressor units, or approximately 33,000 horsepower, that were previously used to provide services in our business. As a result, we recorded $8.7 million

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

in impairment of compression equipment for the year ended December 31, 2018. The primary causes for this impairment were: (i) units were not considered marketable in the foreseeable future, (ii) units were subject to excessive maintenance costs or (iii) units were unlikely to be accepted by customers due to certain performance characteristics of the unit, such as the inability to meet then-current quoting criteria without excessive retrofitting costs. These compression units were written down to their respective estimated salvage values, if any.

The USA Compression Predecessor did not record any impairment of long-lived assets during the years ended December 31, 2017 or 2016.

Identifiable Intangible Assets

Identifiable intangible assets, net consisted of the following (in thousands):

|  | Customer |  |  |  |  |  |  |
|  | Relationships |  | Trade Names |  | Total |
Gross Balance at December 31, 2016 |  | $ | 263,662 |  | $ | 65,500 |  | $ | 329,162 |
Accumulated amortization |  |  | (106,111) |  |  | (24,836) |  |  | (130,947) |
Net Balance at December 31, 2017 |  | $ | 157,551 |  | $ | 40,664 |  | $ | 198,215 |
Gross Balance at December 31, 2017 |  | $ | 263,662 |  | $ | 65,500 |  | $ | 329,162 |
Additions |  |  | 221,500 |  |  | — |  |  | 221,500 |
Accumulated amortization |  |  | (130,001) |  |  | (28,111) |  |  | (158,112) |
Net Balance at December 31, 2018 |  | $ | 355,161 |  | $ | 37,389 |  | $ | 392,550 |

Amortization expense for the year ended December 31, 2018 was $27.2 million and for each of the years ended December 31, 2017 and 2016 was $20.5 million. The expected amortization of the intangible assets for each of the five succeeding years is $29.4 million.

Goodwill

As of October 1, 2018, we performed a qualitative assessment and concluded that it is not more likely than not that the fair value of our single reporting unit was less than its carrying value and that our goodwill was not impaired.

For the year ended December 31, 2017 and in accordance with its early adoption of Accounting Standards Update (“ASU”) 2017-04, the USA Compression Predecessor performed a quantitative assessment for its annual goodwill impairment test and determined its fair value using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The USA Compression Predecessor believed the estimates and assumptions used in the impairment assessment were reasonable and based on available market information, but variations in any of the assumptions could have result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the USA Compression Predecessor determined fair value based on estimated future cash flows including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflects the overall level of inherent risk of the company. Cash flow projections were derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which were developed by management. Subsequent period cash flows were developed using growth rates that management believed were reasonably likely to occur. Under the guideline company method, the USA Compression Predecessor determined its estimated fair value by applying valuation multiples of comparable publicly-traded companies to the projected EBITDA of the company and then averaging that estimate with similar historical calculations using a three-year average. In addition, the USA Compression Predecessor estimated a reasonable control premium representing the incremental value that accrues to the predecessor’s majority owner from the opportunity to dictate the strategic and operational actions of the business. Additionally, the USA Compression Predecessor considered the presence and probability of subsequent events on market transactions in estimating the fair value of the company, such as the Transactions discussed in Note 1.

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

Based on the completion of the annual goodwill impairment testing as described above, the USA Compression Predecessor recorded a $223.0 million impairment equal to the excess of the carrying value over fair value for the year ended December 31, 2017. There was no goodwill impairment for the year ended December 31, 2016.

As of December 31, 2018, the Partnership had $619.4 million of goodwill, of which $366.0 million was determined as part of the purchase price allocation to the Partnership’s assets acquired by the USA Compression Predecessor.

(8) Other Current Assets and Other Current Liabilities

As of December 31, 2018, accrued liabilities included $44.9 million of accrued sales tax contingency (Note 17), $16.4 million of accrued interest expense, $10.7 million of accrued payroll and benefits and $7.9 million of accrued capital expenditures.

As of December 31, 2017, the USA Compression Predecessor recognized $27.8 million of accrued equipment and other asset purchases, $8.3 million of accrued payroll and benefits and $0.7 million of accrued property taxes within accrued liabilities and $3.8 million of miscellaneous prepaid expenses within prepaid expenses and other current assets.

(9) Income Tax Expense

We, including the USA Compression Predecessor, are subject to the Texas Franchise Tax, which applies a tax to our gross margin. We do not conduct business in any other state where a similar tax is applied. The Texas Franchise Tax requires certain forms of legal entities, including limited partnerships, to pay a tax of 0.75% on its “margin,” as defined in the law, based on annual results. The tax base to which the tax is applied is the least of (1) 70% of total revenues for federal income tax purposes, (2) total revenue less cost of goods sold or (3) total revenue less compensation for federal income tax purposes.

Components of our income tax expense (benefit) are as follows (in thousands):

|  | Year Ended December 31,
|  | 2018 |  | 2017 |  | 2016
Current tax expense (benefit) |  | $ | 189 |  | $ | 42 |  | $ | (8)
Deferred tax expense (benefit) |  |  | (2,663) |  |  | 1,801 |  |  | (155)
Total income tax expense (benefit) |  | $ | (2,474) |  | $ | 1,843 |  | $ | (163)

Deferred income tax balances are the direct effect of temporary differences between the financial statement carrying amounts and the tax basis of assets and liabilities at the enacted tax rates expected to be in effect when the taxes are actually paid or recovered. The tax effects of temporary differences related to property and equipment that give rise to deferred tax liabilities, included in other liabilities, are as follows (in thousands):

|  | December 31,
|  | 2018 |  | 2017
Deferred tax liability - Property and equipment |  | $ | 2,540 |  | $ | 3,791

The Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification (“ASC”) Topic 740 Income Taxes (“ASC Topic 740”) provides guidance on measurement and recognition in accounting for income tax uncertainties and provides related guidance on derecognition, classification, disclosure, interest, and penalties. As of December 31, 2018, we had no material unrecognized tax benefits (as defined in ASC Topic 740). We do not expect to incur interest charges or penalties related to our tax positions, but if such charges or penalties are incurred, our policy is to account for interest charges as 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 December 31, 2017. To the extent possible under the new rules, our general partner may elect to either pay the taxes

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

(including any applicable penalties and interest) directly to the Internal Revenue Service or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. The Bipartisan Budget Act of 2015 allows a partnership to elect to apply these provisions to any return of the partnership filed for partnership taxable years beginning after the date of the enactment, November 2, 2015. We do not intend to elect to apply these provisions for any tax return filed for partnership taxable years beginning before January 1, 2018.

(10) Long-Term Debt

Our long-term debt, of which there is no current portion, consisted of the following (in thousands):

|  | December 31,
|  | 2018 |  | 2017
Revolving Credit Facility |  | $ | 1,049,547 |  | $ | —
Senior Notes, aggregate principal |  |  | 725,000 |  |  | —
Less: deferred financing costs, net of amortization |  |  | (15,489) |  |  | —
Senior Notes, net |  |  | 709,511 |  |  | —
Total long-term debt, net |  | $ | 1,759,058 |  | $ | —

Revolving Credit Facility

On the Transactions Date, we entered into the Sixth Amended and Restated Credit Agreement (the “Credit Agreement”) by and among the Partnership, as borrower, USAC OpCo 2, LLC, USAC Leasing 2, LLC, USA Compression Partners, LLC, USAC Leasing, LLC, CDM Resource, CDM E&T and USA Compression Finance Corp. (“Finance Corp”), the lenders party thereto from time to time, JPMorgan Chase Bank, N.A., as agent and a Letter of Credit (“LC”) issuer, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Regions Capital Markets, a division of Regions Bank, RBC Capital Markets and Wells Fargo Bank, N.A., as joint lead arrangers and joint book runners, Barclays Bank PLC, Regions Bank, RBC Capital Markets and Wells Fargo Bank, N.A., as syndication agents, and MUFG Union Bank, N.A., SunTrust Bank and The Bank of Nova Scotia, as senior managing agents.

The Credit Agreement has an aggregate commitment of $1.6 billion (subject to availability under our borrowing base), with a further potential increase of $400 million, and has a maturity date of April 2, 2023.

The Credit Agreement permits us to make distributions of available cash to unitholders so long as (a) no default under the facility has occurred, is continuing or would result from the distribution, (b) immediately prior to and after giving effect to such distribution, we are in compliance with the facility’s financial covenants and (c) immediately after giving effect to such distribution, we have availability under the revolving credit facility of at least $100 million. In addition, the Credit Agreement contains various covenants that may limit, among other things, our ability to (subject to exceptions):

| · |  | grant liens;

| · |  | make certain loans or investments;

| · |  | incur additional indebtedness or guarantee other indebtedness;

| · |  | enter into transactions with affiliates;

| · |  | merge or consolidate;

| · |  | sell our assets; or

| · |  | make certain acquisitions.

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

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 annualized trailing three months of (a) 5.75 to 1.0 through the end of the fiscal quarter ending March 31, 2019, (b) 5.5 to 1.0 through the end of the fiscal quarter ending December 31, 2019 and (c) 5.00 to 1.0 thereafter, in each case subject to a provision for increases to such thresholds by 0.5 in connection with certain future acquisitions for the six consecutive month period following the period in which any such acquisition occurs.

If a default exists under the Credit Agreement, the lenders will be able to accelerate the maturity on the amount then outstanding and exercise other rights and remedies.

In connection with entering into the amended Credit Agreement, we paid certain upfront fees and arrangement fees to the arrangers, syndication agents and senior managing agents of the Credit Agreement in the amount of $14.3 million during the year ended December 31, 2018. These fees were capitalized to loan costs and will be amortized through April 2023. Amounts borrowed and repaid under the Credit Agreement may be re-borrowed.

As of December 31, 2018, we were in compliance with all of our covenants under the Credit Agreement.

As of December 31, 2018, we had outstanding borrowings under the Credit Agreement of $1.1 billion, $550.5 million of borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of $550.5 million. The borrowing base consists of eligible accounts receivable, inventory and compression units. The largest component, representing 95% of the borrowing base as of December 31, 2018, was eligible compression units. Eligible compression units consist of compressor packages that are leased, rented or under service contracts to customers and carried in the financial statements as fixed assets. Our interest rate in effect for all borrowings under the Credit Agreement as of December 31, 2018 was 4.97%, with a weighted-average interest rate of 4.69% for the period from the Transactions Date to December 31, 2018. There were no LCs issued as of December 31, 2018.

The Credit Agreement matures in April 2023 and we expect to maintain it for the term. The Credit Agreement is a “revolving credit facility” that includes a lock box arrangement, whereby remittances from customers are forwarded to a bank account controlled by the administrative agent and are applied to reduce borrowings under the facility.

Senior Notes

On March 23, 2018, the Partnership and its wholly owned finance subsidiary, Finance Corp, co-issued $725.0 million aggregate principal amount of the Senior Notes that mature on April 1, 2026. The Senior Notes accrue interest from March 23, 2018 at the rate of 6.875% per year. Interest on the Senior Notes is payable semi-annually in arrears on April 1 and October 1, with the first such payment having occurred on October 1, 2018.

At any time prior to April 1, 2021, we may redeem up to 35% of the aggregate principal amount of the Senior Notes at a redemption price equal to 106.875% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date, in an amount not greater than the net proceeds from one or more equity offerings, provided that at least 65% of the aggregate principal amount of the Senior Notes remains outstanding immediately after the occurrence of such redemption (excluding Senior Notes held by us and our subsidiaries) and redemption occurs within 180 days of the date of the closing of such equity offering.

Prior to April 1, 2021, we may redeem all or a part of the Senior Notes at a redemption price equal to the sum of (i) the principal amount thereof, plus (ii) a make-whole premium at the redemption date, plus accrued and unpaid interest, if any, to the redemption date.

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

On or after April 1, 2021, we may redeem all or a part of the Senior Notes at redemption prices (expressed as percentages of the principal amount) set forth below, plus accrued and unpaid interest, if any, to the applicable redemption date. If we experience a change of control followed by a ratings decline, unless we have previously exercised or concurrently exercise the right to redeem the Senior Notes (as described above), we may be required to offer to repurchase the Senior Notes at a purchase price equal to 101% of the principal amount repurchased, plus accrued and unpaid interest, if any, to the repurchase date.

Year |  |  | Percentages |
2021 |  |  | 105.156 | %
2022 |  |  | 103.438 | %
2023 |  |  | 101.719 | %
2024 and thereafter |  |  | 100.000 | %

The Indenture governing the Senior Notes (the “Indenture”) contains a Fixed Charge Coverage Ratio (as defined in the Indenture) that we must comply with in order to make certain Restricted Payments (as defined in the Indenture).

In connection with issuing the Senior Notes, we incurred certain issuance costs in the amount of $17.3 million which is amortized over the term of the Senior Notes using the effective interest method.

The Senior Notes are fully and unconditionally guaranteed (the “Guarantees”), jointly and severally, on a senior unsecured basis by all of our existing subsidiaries (other than Finance Corp), and will be fully and unconditionally guaranteed, jointly and severally, by each of our future restricted subsidiaries that either borrows under, or guarantees, our revolving credit facility or guarantees certain of our other indebtedness (collectively, the “Guarantors”). The Senior Notes and the Guarantees are general unsecured obligations and rank equally in right of payment with all of the Guarantors’ and our existing and future senior indebtedness and senior to the Guarantors’ and our future subordinated indebtedness, if any. The Senior Notes and the Guarantees are effectively subordinated in right of payment to all of the Guarantors and our existing and future secured debt, including debt under our revolving credit facility and guarantees thereof, to the extent of the value of the assets securing such debt, and are structurally subordinated to all indebtedness of any of our subsidiaries that do not guarantee the Senior Notes.

We have no assets or operations independent of our subsidiaries, and there are no significant restrictions upon our ability to obtain funds from our subsidiaries by dividend or loan. Each of the Guarantors is 100% owned by us. None of the assets of our subsidiaries represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act of 1933, as amended (“Securities Act”).

On January 14, 2019, the Partnership closed an exchange offer whereby holders of the Senior Notes exchanged all of the Senior Notes for an equivalent amount of senior notes (“Exchange Notes”) registered under the Securities Act. The Exchange Notes are substantially identical to the Senior Notes, except that the Exchange Notes have been registered and do not contain transfer restrictions, restrictive legends, registration rights or additional interest provisions of the Senior Notes.

Subsidiary Guarantors

On April 20, 2017, the Partnership filed a Registration Statement on Form S-3 (the “Registration Statement”) with the SEC to register the issuance and sale of, among other securities, debt securities, which may be co-issued by Finance Corp (together with the Partnership, the “Issuers”) and fully and unconditionally guaranteed on a joint and several basis by the Partnership’s operating subsidiaries for the benefit of each Holder and the Trustee. Such guarantees will be subject to release, subject to certain limitations, as follows (i) upon the sale, exchange or transfer, by way of a merger or otherwise, to any Person that is not our Affiliate, of all of our direct or indirect limited partnership or other equity interest in such Subsidiary Guarantor; or (ii) upon delivery by an Issuer of a written notice to the Trustee of the release or discharge of all guarantees by such Subsidiary Guarantor of any Debt of the Issuers other than obligations arising under the indenture governing such debt and any debt securities issued under such indenture, except a discharge or release by or as a result of payment under such guarantees. Capitalized terms used but not defined in this paragraph are defined in the Form of Indenture filed as Exhibit 4.1 to the Registration Statement.

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

Maturities of long-term debt for each of the five succeeding years are as follows (in thousands):

Year Ending December 31, |
2019 |  | $ | — |
2020 |  |  | — |
2021 |  |  | — |
2022 |  |  | — |
2023 |  |  | 1,049,547 |
Total Debt |  | $ | 1,049,547 |

The USA Compression Predecessor did not hold any debt as of December 31, 2017.

(11) Preferred Units and Warrants

Series A Preferred Unit and Warrant Private Placement

On the Transactions Date, we completed a private placement of $500 million in the aggregate of (i) newly authorized and established Preferred Units and (ii) warrants to purchase common units (the “Warrants”) pursuant to a Series A Preferred Unit and Warrant Purchase Agreement dated January 15, 2018, with certain investment funds managed or advised by EIG Global Energy Partners (collectively, the “Preferred Unitholders”). We issued 500,000 Preferred Units with a face value of $1,000 per Preferred Unit and issued two tranches of Warrants to the Preferred Unitholders, which included Warrants to purchase 5,000,000 common units with a strike price of $17.03 per unit and 10,000,000 common units with a strike price of $19.59 per unit. The Warrants may be exercised by the holders thereof at any time beginning April 2, 2019 and before April 2, 2028.

On November 13, 2018, the Partnership filed a Registration Statement on Form S-3 to register 41,202,553 common units that are potentially issuable upon conversion of the Preferred Units and exercise of the Warrants.

The Preferred Units rank senior to the common units with respect to distributions and rights upon liquidation. The Preferred Unitholders are entitled to receive cumulative quarterly distributions equal to $24.375 per Preferred Unit and which may be paid in cash or, subject to certain limits, a combination of cash and additional Preferred Units as determined by the General Partner with respect to any quarter ending on or prior to June 30, 2019. For the three months ended June 30, 2018, the distribution was pro-rated for the period the Preferred Units were outstanding, which resulted in an initial distribution of $24.107 per Preferred Unit which was paid on August 10, 2018. For the three months ended September 30, 2018, the quarterly distribution was equal to $24.375 per Preferred Unit and was paid on November 9, 2018. The distribution attributable to the quarter ended December 31, 2018 was paid on February 8, 2019 to Preferred Unitholders of record as of the close of business on January 28, 2019.

The Preferred Units are convertible, at the option of the Preferred Unitholders, into common units as follows: one third on or after April 2, 2021, two thirds on or after April 2, 2022, and the remainder on or after April 2, 2023. The conversion rate for the Preferred Units shall be the quotient of (a) the sum of (i) $1,000, plus (ii) any unpaid cash distributions on the applicable Preferred Unit, divided by (b) $20.0115 for each Preferred Unit. The Preferred Unitholders are entitled to vote on an as-converted basis with the common unitholders and (as proportionately adjusted for unit splits, unit distributions and similar transactions) will have certain other class voting rights with respect to any amendment to the Partnership Agreement that would adversely affect any rights, preferences or privileges of the Preferred Units. In addition, upon certain events involving a change of control the Preferred Unitholders may elect, among other potential elections, to convert their Preferred Units to common units at the then change of control conversion rate.

On or after April 2, 2023, we have the option to redeem all or any portion of the Preferred Units then outstanding. On or after April 2, 2028, the Preferred Unitholders have the right to require us to redeem all or a portion of the Preferred Units then outstanding, the purchase price for which we may elect to pay up to 50% in common units, subject to certain additional limits. The Preferred Units are presented as temporary equity in the mezzanine section of the Consolidated Balance Sheets because the redemption provisions on or after April 2, 2028 are outside the Partnership’s control. The

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

Preferred Units have been recorded at their issuance date fair value, net of issuance cost. Net income allocations increase the carrying value and declared distributions decrease the carrying value of the Preferred Units. As the Preferred Units are not currently redeemable and it is not probable that they will become redeemable, adjustment to the initial carrying amount is not necessary and would only be required if it becomes probable that the Preferred Units would become redeemable.

Changes in the Preferred Units balance from December 31, 2017 through December 31, 2018 are summarized below (in thousands):

|  | Preferred Units
Balance at December 31, 2017 |  | $ | —
Issuance of Preferred Units on April 2, 2018, net |  |  | 465,121
Net income allocated for April 2, 2018 through December 31, 2018 |  |  | 36,430
Cash distributions on Preferred Units |  |  | (24,242)
Balance at December 31, 2018 |  | $ | 477,309

The Warrants are presented within the equity section of the Consolidated Balance Sheets in accordance with GAAP as they are indexed to the Partnership’s own stock and require physical settlement or net share settlement. The Warrants were valued using the Black-Scholes-Merton model.

Refer to Note 14 for information about the rights EIG Veteran Equity Aggregator, L.P. (along with its affiliated funds, “EIG”) has to designate one of the members of the Board.

(12) Partners’ Capital

Common Units

As of December 31, 2018, we had 89,983,790 common units outstanding. As of December 31, 2018, ETP held 39,658,263 common units, including 8,000,000 common units held by the General Partner and controlled by ETP.

USA Compression Holdings, which controlled the General Partner and its IDRs until the Transactions Date, sold all of its remaining common units during the year ended December 31, 2018.

The limited partners holding our common units have the following rights, among others:

| · |  | Right to receive distributions of our available cash (as defined in our Second Amended and Restated Agreement of Limited Partnership of the Partnership (the “Partnership Agreement”)) within 45 days after the end of each quarter, so long as we have paid the required distributions on the Preferred Units for such quarter;

| · |  | Right to transfer limited partner unit ownership to substitute limited partners;

| · |  | Right to approve certain amendments of the Partnership Agreement;

| · |  | Right to electronic access of an annual report, containing audited financial statements and a report on those financial 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 the calendar year.

Class B Units

As of December 31, 2018, we had 6,397,965 Class B Units outstanding which represent limited partner interests in the Partnership, all of which are held by ETP. Each Class B Unit will automatically be converted into one common unit

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

following the record date attributable to the quarter ending June 30, 2019. Each Class B Unit has all of the rights and obligations of a common unit, except the right to participate in distributions made prior to conversion of the Class B Units into common units.

Cash Distributions

As the USA Compression Predecessor is deemed to be the predecessor of the Partnership for financial reporting purposes, cash distributions made by the Partnership in periods prior to the Transactions Date are not included within the results of operations presented within the consolidated financial statements for the year ended December 31, 2018.

We have declared quarterly distributions per unit to our limited partner unitholders of record, including holders of our common and phantom units, as follows (dollars in millions, except distribution per unit):

|  | Distribution per |  | Amount Paid to |  | Amount Paid to |  |  |  |
|  | Limited Partner |  | Common |  | Phantom |  | Total |
Payment Date |  | Unit |  | Unitholders |  | Unitholders |  | Distribution |
May 11, 2018 |  | $ | 0.525 |  | $ | 47.2 |  | $ | 0.4 |  | $ | 47.6 |
August 10, 2018 |  |  | 0.525 |  |  | 47.2 |  |  | 0.4 |  |  | 47.6 |
November 9, 2018 |  |  | 0.525 |  |  | 47.2 |  |  | 0.5 |  |  | 47.7 |
2018 Total Distributions |  | $ | 1.575 |  | $ | 141.6 |  | $ | 1.3 |  | $ | 142.9 |

Announced Quarterly Distribution

On January 17, 2019, we announced a cash distribution of $0.525 per unit on our common units. The distribution was paid on February 8, 2019 to unitholders of record as of the close of business on January 28, 2019.

Distribution Reinvestment Plan

During the year ended December 31, 2018, distributions of $0.6 million were reinvested under the Distribution Reinvestment Plan (the “DRIP”) resulting in the issuance of 39,280 common units.

Earnings Per Common Unit

The computations of earnings per unit are based on the weighted average number of participating securities outstanding during the period. Basic earnings per unit is determined by dividing net loss allocated to participating securities after deducting the amount distributed on Preferred Units, by the weighted average number of participating securities outstanding during the period. Net loss is allocated to participating securities based on their respective shares of the distributed and undistributed earnings for the period. To the extent cash distributions exceed net income (loss) for the period, the excess distributions are allocated to all participating securities outstanding based on their respective ownership percentages. Diluted earnings per unit are computed using the treasury stock method, which considers the potential issuance of limited partner units associated with our long-term incentive plan and warrants. The classes of participating securities include common units, Class B Units, and certain equity-based compensation awards. Unvested phantom units and unexercised warrants are not included in basic earnings per unit, as they are not considered to be participating securities, but are included in the calculation of diluted earnings per unit to the extent that they are dilutive, and in the case of warrants to the extent they are considered “in the money”. For the year ended December 31, 2018, approximately 208,000 incremental unvested phantom units were excluded from the calculation of diluted earnings per unit because the impact was anti-dilutive. Our outstanding warrants are not applicable to the computation as of December 31, 2018 as they are not considered “in the money” for the period. Earnings per unit is not applicable to the USA Compression Predecessor as the USA Compression Predecessor had no outstanding common units prior to the Transactions.

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

(13) Revenue Recognition

Revenue is recognized when obligations under the terms of a contract with our customer are satisfied; generally this occurs with the transfer of our services or goods. Revenue is measured at the amount of consideration we expect to receive in exchange for providing services or transferring goods. Sales taxes incurred on behalf of, and passed through to, customers are excluded from revenue. Incidental items, if any, that are immaterial in the context of the contract are recognized as expense.

Adoption of ASC Topic 606, “Revenue from Contracts with Customers”

On January 1, 2018, we adopted ASC Topic 606 Revenue from Contracts with Customers (“ASC Topic 606”) using the modified retrospective method applied to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning after January 1, 2018 are presented under ASC Topic 606, while prior period amounts are not adjusted and continue to be reported in accordance with our historic accounting under ASC Topic 605.

We identified no material impact on our historical revenues upon initial application of ASC Topic 606, and as such have not recognized any cumulative catch-up effect to the opening balance of our partners’ capital as of January 1, 2018. Additionally, the application of ASC Topic 606 has no material impact on any current financial statement line items.

The following table disaggregates our revenue by type of service (in thousands):

|  | Year Ended December 31,
|  | 2018 |  | 2017 (1) |  | 2016 (1)
Contract operations revenue |  | $ | 563,416 |  | $ | 266,130 |  | $ | 255,560
Retail parts and services revenue |  |  | 20,936 |  |  | 10,541 |  |  | 8,377
Total revenues |  | $ | 584,352 |  | $ | 276,671 |  | $ | 263,937

| (1) |  | As noted above, prior period amounts have not been adjusted under the modified retrospective method of ASC Topic 606.

The following table disaggregates our revenue by timing of provision of services or transfer of goods (in thousands):

|  | Year Ended December 31,
|  | 2018 |  | 2017 (1) |  | 2016 (1)
Services provided or goods transferred at a point in time |  | $ | 20,936 |  | $ | 10,541 |  | $ | 8,377
Services provided over time: |  |  |  |  |  |  |  |  |
Primary term |  |  | 288,299 |  |  | 128,864 |  |  | 158,313
Month-to-month |  |  | 275,117 |  |  | 137,266 |  |  | 97,247
Total revenues |  | $ | 584,352 |  | $ | 276,671 |  | $ | 263,937

| (1) |  | As noted above, prior period amounts have not been adjusted under the modified retrospective method of ASC Topic 606.

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

Contract operations revenue

Revenue from contracted compression, station, gas treating and maintenance services is recognized ratably under our fixed-fee contracts over the term of the contract as services are provided to our customers. Initial contract terms typically range from six months to five years, however we usually continue to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. We primarily enter into fixed-fee contracts whereby our customers are required to pay our monthly fee even during periods of limited or disrupted throughput. Services are generally billed monthly, one month in advance of the commencement of the service month, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of our invoice. Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue. The amount of consideration we receive and revenue we recognize is based upon the fixed fee rate stated in each service contract.

Variable consideration exists in select contracts when billing rates vary based on actual equipment availability or volume of total installed horsepower.

Our contracts with customers may include multiple performance obligations. For such arrangements, we allocate revenues to each performance obligation based on its relative standalone service fee. We generally determine standalone service fees based on the service fees charged to customers or use expected cost plus margin.

The majority of our service performance obligations are satisfied over time as services are rendered at selected customer locations on a monthly basis and based upon specific performance criteria identified in the applicable contract. The monthly service for each location is substantially the same service month to month and is promised consecutively over the service contract term. We measure progress and performance of the service consistently using a straight-line, time-based method as each month passes, because our performance obligations are satisfied evenly over the contract term as the customer simultaneously receives and consumes the benefits provided by our service. If variable consideration exists, it is allocated to the distinct monthly service within the series to which such variable consideration relates. We have elected to apply the invoicing practical expedient to recognize revenue for such variable consideration, as the invoice corresponds directly to the value transferred to the customer based on our performance completed to date.

There are typically no material obligations for returns or refunds. Our standard contracts do not usually include material non-cash consideration.

Retail parts and services revenue

Retail parts and services revenue is earned primarily on freight and crane charges that are directly reimbursable by our customers and maintenance work on units at our customers’ locations that are outside the scope of our core maintenance activities. Revenue from retail parts and services is recognized at the point in time the part is transferred or service is provided and control is transferred to the customer. At such time, the customer has the ability to direct the use of the benefits of such part or service after we have performed our services. We bill upon completion of the service or transfer of the parts, and payment is generally due 30 days after receipt of our invoice. The amount of consideration we receive and revenue we recognize is based upon the invoice amount. There are typically no material obligations for returns, refunds, or warranties. Our standard contracts do not usually include material variable or non-cash consideration.

Contract assets and trade accounts receivable

We record contract assets when we have completed performance under a contract but our right to consideration is not yet unconditional. We had no contract assets as of December 31, 2018 and the USA Compression Predecessor had no contract assets as of December 31, 2017. Trade accounts receivable are recorded when our right to consideration becomes unconditional and increased by $36.2 million during the year ended December 31, 2018 as a result of the USA Compression Predecessor’s acquisition of the Partnership for financial reporting purposes. There were no significant changes to our trade accounts receivable balances due to contract modifications or adjustments, or changes in time frame for a right to consideration to become unconditional during the period.

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

Deferred revenue

We record deferred revenue when cash payments are received or due in advance of our performance. The increase in the deferred revenue balance for the year ended December 31, 2018 is primarily driven by cash payments received or due in advance of satisfying our performance obligations under a contract and the addition of $31.0 million of deferred revenue from the USA Compression Predecessor’s acquisition of the Partnership, offset by $1.0 million of revenues recognized that were included in the deferred revenue balance of the USA Compression Predecessor as of December 31, 2017. There was no significant change to our deferred revenue balance as a result of changes in time frame for a performance obligation to be satisfied during the period.

Practical expedients and exemptions

We have elected to apply the practical expedient in ASC 606-10-50-14 and as such do not disclose the value of unsatisfied performance obligations for (i) contracts with an original expected length of one year or less and (ii) contracts for which we recognize revenue at the amount to which we have the right to invoice for services performed.

Costs to fulfill a contract

We sometimes incur non-reimbursable costs for loading, transporting and unloading equipment to and from our storage locations and customer locations. We defer and amortize these costs using the straight-line method over the life of the contract. We had no costs to fulfill a contract as of December 31, 2018 and $0.1 million in amortization expense of costs to fulfill a contract for the year ended December 31, 2018. The USA Compression Predecessor had no costs to fulfill a contract as of December 31, 2017 and amortization expense was zero for the year ended December 31, 2017.

(14) Transactions with Related Parties

We provide compression services to entities affiliated with ETP, which as of December 31, 2018, owned approximately 48% of our limited partner interests, including all of the Class B Units, and 100% of the General Partner. During the year ended December 31, 2018, we recognized $17.1 million in revenue from such affiliated entities. As of December 31, 2018, we had $2.7 million in related party receivables from such affiliated entities and $0.4 million in related party payables to such affiliated entities. Additionally, the Partnership had a $44.9 million related party receivable from ETP as of December 31, 2018 related to indemnification for sales tax contingencies incurred by the USA Compression Predecessor. See Note 17 for more information related to such sales tax contingencies.

The USA Compression Predecessor also provided compression services to entities affiliated with ETP. During the years ended December 31, 2017 and 2016, the USA Compression Predecessor recognized $17.2 million and $16.9 million, respectively, in revenue from such affiliated entities. As of December 31, 2017, the USA Compression Predecessor recognized $45,000 in related party receivables from such affiliated entities and $2.0 million in related party payables to such affiliated entities.

Accounts receivable and payable that related to revenues and expenses between the USA Compression Predecessor and ETP were reclassified to Predecessor parent company net investment as there was no expectation that those amounts would be settled in cash.

ETP provided certain benefits to the USA Compression Predecessor employees which did not continue following the Transactions Date. ETP provided medical, dental and other healthcare benefits to the USA Compression Predecessor employees. The total amount incurred by ETP for the benefit of the USA Compression Predecessor employees for the years ended December 31, 2018, 2017 and 2016 was $1.9 million, $7.4 million and $5.8 million, respectively, which was allocated to the USA Compression Predecessor and recorded in operation and maintenance and general and administrative expenses, as appropriate. ETP also provided a matching contribution to the USA Compression Predecessor employees’ 401(k) accounts. The total amount of matching contributions incurred for the benefit of the USA Compression Predecessor employees for the years ended December 31, 2018, 2017 and 2016 was $0.9 million, $3.0 million and $2.7 million, respectively, which was allocated to the USA Compression Predecessor and recorded in operation and maintenance and general and administrative expenses, as appropriate. ETP also provided a 3% profit

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

sharing contribution to the 401(k) accounts for all USA Compression Predecessor employees with base compensation below a specified threshold. The contribution was in addition to the 401(k) matching contribution and employees became vested in the profit sharing contribution based on years of service.

ETP allocated certain overhead costs associated with general and administrative services, including salaries and benefits, facilities, insurance, information services, human resources and other support departments to the USA Compression Predecessor which did not continue following the Transactions Date. Where costs incurred on the USA Compression Predecessor’s behalf could not be determined by specific identification, the costs were primarily allocated to the USA Compression Predecessor based on an average percentage of fixed assets, net income (loss) and adjusted EBITDA. The USA Compression Predecessor believes these allocations were a reasonable reflection of the utilization of services provided. However, the allocations may not fully reflect the expenses that would have been incurred had the USA Compression Predecessor been a standalone company during the periods presented. During the years ended December 31, 2018, 2017 and 2016 ETP allocated general and administrative expenses of $1.8 million, $3.6 million and $4.7 million, respectively, to the USA Compression Predecessor.

An independent director of the General Partner serves as a director of one of our customers. During the period of such director’s appointment as a director of the General Partner during the year ended December 31, 2018, we recognized $0.3 million in revenue on compression services and $0 in accounts receivable from this customer on the Consolidated Balance Sheets as of December 31, 2018.

Pursuant to that certain Board Representation Agreement entered into by us, the General Partner, ETE and EIG in connection with our private placement of Preferred Units and Warrants to EIG, EIG Management Company, LLC has the right to designate one of the members of the Board for so long as the holders of the Preferred Units hold more than 5% of the Partnership’s outstanding common units in the aggregate (taking into account the common units that would be issuable upon conversion of the Preferred Units and exercise of the Warrants).

(15) Unit-Based Compensation

Long-Term Incentive Plan

In connection with the Partnership’s initial public offering in January 2013, the board of directors of the General Partner (the “Board”) adopted the USA Compression Partners, LP 2013 Long-Term Incentive Plan (“LTIP”) for certain employees, consultants and directors of the General Partner and any of its affiliates who perform services for us. The LTIP provides for awards of unit options, unit appreciation rights, restricted units, phantom units, distribution equivalent rights (“DERs”), unit awards, profits interest units and other unit-based awards. On November 1, 2018 and effective the same day, the Board approved and adopted The First Amendment to the LTIP which, among other things, increased the number of common units of the Partnership available to be awarded under the LTIP by 8,590,000 common units (which brings the total number of common units available to be awarded under the LTIP to 10,000,000 common units) and extends the term of the LTIP until November 1, 2028. Awards that are forfeited, cancelled, paid or otherwise terminate or expire without the actual delivery of common units will be available for delivery pursuant to other awards. The LTIP is administered by the Board or a committee thereof.

The General Partner’s executive officers, certain of its employees and certain of its independent directors were granted these awards to incentivize them to help drive our future success and to share in the economic benefits of that success. All employees with phantom units have a portion of their award settled in cash and a portion settled in common units upon vesting, unless otherwise approved by the Board. The amount that can be settled in cash is in excess of the employee’s minimum statutory tax-withholding rate. ASC Topic 718 Compensation-Stock Compensation, requires the entire amount of an award with such features to be accounted for as a liability. Under the liability method of accounting for unit-based compensation, we re-measure the fair value of the award at each financial statement date until the award vests or is cancelled. The fair value is measured using the market price of the Partnership’s common units. During the requisite service period (the vesting period of the awards), compensation cost is recognized using the proportionate amount of the award’s fair value that has been earned through service to date. Phantom units granted to independent directors do not have a cash settlement option and as such we account for these awards as equity. Each phantom unit is granted in tandem with a corresponding DER, which entitles the recipient to receive an amount in cash on a quarterly basis equal to the product of (a) the number of the recipient’s outstanding, unvested phantom units on the record date for

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Notes to Consolidated Financial Statements

such quarter and (b) the quarterly distribution declared by the Board for such quarter with respect to the Partnership’s common units.

During the period from the Transactions Date to December 31, 2018, an aggregate of 1,136,447 phantom units (including the corresponding DERs) were granted under the LTIP to the General Partner’s executive officers and certain of its employees and independent directors. The phantom units (including the corresponding DERs) awarded are subject to restrictions on transferability, customary forfeiture provisions and time vesting provisions. Phantom unit awards granted after July 30, 2018 vest incrementally, with 60% of the phantom units vesting at the end of the third year following the grant and the remaining 40% vesting at the end of the fifth year following the grant. Phantom unit awards that were granted to employees of USAC Management prior to July 30, 2018 vest evenly over a three-year service period.

Phantom units granted prior to July 30, 2018 vest in full in the event of a change in control followed by a termination of employment, and phantom units granted on or after July 30, 2018 vest in full upon a change in control. Award recipients do not have all the rights of a unitholder in the Partnership with respect to the phantom units until the units have vested.

On the Transactions Date and in connection with the closing of the CDM Acquisition, and pursuant to the change in control provisions of our outstanding phantom unit awards, all of the performance-based phantom units granted during 2018, 2017 and 2016 and outstanding as of the Transactions Date, vested immediately upon the change in control event at 100% of the target level. In addition, all outstanding time-based phantom units held by our CEO vested immediately upon the change in control event. As such, 563,544 outstanding phantom units vested resulting in $6.8 million of compensation expense recognized during the year ended December 31, 2018.

ETP had a long-term incentive plan for the USA Compression Predecessor’s employees, officers and directors. ETP had granted restricted unit awards to the USA Compression Predecessor’s employees that vested on a pro-rata basis incrementally over a five-year vesting period, with vesting based on continued employment as of each applicable vesting date. Upon vesting, ETP common units were issued. These restricted unit awards also entitled the recipients of the unit awards to receive, with respect to each ETP common unit subject to such award that had not vested or been forfeited, a corresponding DER entitling the recipient to a cash payment equal to the cash distribution per ETP common unit paid by ETP to its unitholders promptly following each such distribution. All unit-based compensation awards were treated as equity within the USA Compression Predecessor financial statements.

The unit and per-unit amounts disclosed in the remainder of this note for periods prior to the Transactions Date reflect amounts related to ETP. These amounts have been retrospectively adjusted to reflect a 1.5 to one unit-for-unit exchange related to the merger of ETP and Sunoco Logistics Partners L.P. in April 2017 and a 0.4124 to one unit-for unit exchange related to the merger of ETP and Regency Energy Partners LP in April 2015. The unit and per-unit amounts do not reflect the conversion of ETP units to ETE units as a result of the ETE Merger in October 2018.

On the Transactions Date and in connection with the closing of the CDM Acquisition, and pursuant to the change in control provisions of the USA Compression Predecessor’s outstanding phantom unit awards, all of the USA Compression Predecessor’s outstanding phantom unit awards were forfeited.

As of December 31, 2018, our total unit-based compensation liability was $3.6 million. During the years ended December 31, 2018, 2017 and 2016, we recognized $11.7 million, $4.0 million and $3.5 million of compensation expense associated with these awards, respectively, recorded in selling, general and administrative expense. During the years ended December 31, 2018, 2017 and 2016, amounts paid related to the cash settlement of vested awards under the LTIP were $4.4 million, $0.6 million and $0.9 million, respectively.

The total fair value and intrinsic value of the phantom units vested under the LTIP was $9.7 million for the period from the Transactions Date to December 31, 2018, and $1.6 million and $1.0 million during the years ended December 31, 2017 and 2016, respectively.

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Notes 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) |
USA Compression Predecessor's phantom units outstanding at December 31, 2015 |  | 334,354 |  | $ | 32.98 |
Granted |  | 147,384 |  |  | 24.22 |
Vested |  | (42,964) |  |  | 40.28 |
Forfeited |  | (9,239) |  |  | 28.58 |
USA Compression Predecessor's phantom units outstanding at December 31, 2016 |  | 429,535 |  | $ | 29.34 |
Granted |  | 2,500 |  |  | 18.75 |
Vested |  | (95,499) |  |  | 36.94 |
Forfeited |  | (11,614) |  |  | 27.41 |
USA Compression Predecessor's phantom units outstanding at December 31, 2017 |  | 324,922 |  | $ | 27.10 |
Forfeited upon change in control, April 2, 2018 |  | (324,922) |  |  | 27.10 |
Assumed upon change in control, April 2, 2018 (2) |  | 1,010,522 |  |  | 14.24 |
Granted (2) |  | 1,136,447 |  |  | 15.47 |
Vested (2) |  | (571,892) |  |  | 14.79 |
Forfeited (2) |  | (144,013) |  |  | 17.85 |
Phantom units outstanding at December 31, 2018 |  | 1,431,064 |  | $ | 14.98 |

| (1) |  | Determined by dividing the aggregate grant date fair value of awards by the number of units issued.

| (2) |  | Following the Transactions Date, the outstanding unvested phantom units granted by the USA Compression Predecessor were forfeited and the outstanding unvested phantom units granted by the Partnership prior to the Transactions Date were maintained. The number of units assumed upon change in control represent the Partnership’s unvested outstanding phantom units as of March 31, 2018. The subsequent number of units granted, vested and forfeited reflect activity following the Transactions Date through December 31, 2018.

The unrecognized compensation cost associated with phantom unit awards was an aggregate $15.0 million as of December 31, 2018. We expect to recognize the unrecognized compensation cost for these awards on a weighted-average basis over a period of 2.2 years.

(16) Employee Benefit Plans

A 401(k) plan is available to all of our employees. The plan permits employees to contribute up to 20% of their salary, up to the statutory limits, which was $18,500 for 2018. The plan provides for discretionary matching contributions by us on an annual basis. Aggregate matching contributions made to employees’ 401(k) plans were $3.2 million for the year ended December 31, 2018, including $0.9 million made by ETP to employees of the USA Compression Predecessor prior to the Transactions Date.

Refer to Note 14 for information about the 401(k) plan provided by ETP to employees of the USA Compression Predecessor.

(17) Commitments and Contingencies

| (a) |  | Leases

We maintain both capital leases and operating leases, primarily related to office space, warehouse facilities and certain corporate equipment. We held $7.6 million and $7.6 million of capital leases, in property and equipment as of December 31, 2018 and 2017, respectively, representing the present value of the future minimum lease payments over the term of the lease determined at the inception of the lease and $4.9 million and $3.8 million of accumulated amortization on assets recorded under capital leases, respectively. Amortization expense on assets recorded under capital

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

leases is included within depreciation and amortization expense on the consolidated statements of operations. We recorded $1.1 million and $1.2 million as of December 31, 2018 and 2017, respectively, as the current portion of the lease obligation, which is included in accrued liabilities, and $2.1 million and $3.2 million as of December 31, 2018 and 2017, respectively, as the long-term portion of the lease obligation, included in other non-current liabilities on the consolidated balance sheets.

Total rent expense for operating leases, including those leases with terms of less than one year, was $4.4 million, $3.6 million and $4.0 million for the years ended December 31, 2018, 2017 and 2016, respectively.

Commitments for future minimum lease payments for non-cancelable leases, with lease terms in excess of one year, are as follows (in thousands):

2019 |  | $ | 3,773 |
2020 |  |  | 1,563 |
2021 |  |  | 854 |
2022 |  |  | 569 |
2023 |  |  | 509 |
Thereafter |  |  | 642 |
Total minimum lease payments |  | $ | 7,910 |
Less: Amount representing minimum operating lease payments |  |  | (3,938) |
Total minimum capital lease payments |  |  | 3,972 |
Less: Amount representing estimated taxes, maintenance and insurance costs included in total amounts above |  |  | (652) |
Net minimum capital lease payments |  |  | 3,320 |
Less: Amount representing interest |  |  | (121) |
Present value of net minimum lease payments |  | $ | 3,199 |
Less: Current maturities of capital lease obligations |  |  | (1,085) |
Long-term capital lease obligations |  | $ | 2,114 |

| (b) |  | Major Customers

Neither we nor the USA Compression Predecessor had revenue from any single customer representing 10% or more of total revenue for the years ended December 31, 2018, 2017 or 2016.

| (c) |  | Litigation

From time to time, we and our subsidiaries may be involved in various claims and litigation arising in the ordinary course of business. In management’s opinion, the resolution of such matters is not expected to have a material adverse effect on 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 units ordered but not received. The commitments as of December 31, 2018 were $107.5 million, all of which is expected 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. The Office of the Texas Comptroller of Public Accounts (“Comptroller”) has claimed that specific operational processes, which we and others in our industry regularly conduct, result in transactions that are subject to state sales taxes. We and other companies in our industry have disputed these claims based on existing tax statutes which provide for manufacturing

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USA COMPRESSION PARTNERS, LP

Notes to Consolidated Financial Statements

exemptions on the transactions in question. The manufacturing exemptions are based on the fact that our natural gas compression equipment is used in the process of treating natural gas for ultimate use and sale.

The USA Compression Predecessor has several open audits with the Comptroller for certain periods prior to the Transactions Date wherein the Comptroller has challenged the applicability of the manufacturing exemption. Any liability for the periods prior to the Transactions Date will be covered by an indemnity between us and ETP. As of December 31, 2018, we have recorded a $44.9 million accrued liability and $44.9 million related party receivable from ETP.

During the year ended December 31, 2018, we entered into a compromise and settlement agreement with the Comptroller for the audit of the Partnership for the period from January 2009 to August 2012 for a $0.2 million refund to the Partnership.

| (f) |  | Environmental

The Partnership’s operations are subject to federal, state and local laws and rules and regulations regarding water quality, hazardous and solid waste management, air quality control and other environmental matters. These laws, rules and regulations require the Partnership to conduct its operations in a specified manner and to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with applicable environmental laws, rules and regulations may expose the Partnership to significant fines, penalties and/or interruptions in operations. The Partnership’s environmental policies and procedures are designed to achieve compliance with such applicable laws and regulations. These evolving laws and regulations and claims for damages to property, employees, other persons and the environment resulting from current or past operations may result in significant expenditures and liabilities in the future.

(18) Recent Accounting Pronouncements

In June 2016, the FASB issued ASU 2016-13, Financial Instruments- Credit Losses (“ASC Topic 326”): Measurement of Credit Losses on Financial Instruments. The amendment in ASC Topic 326 require immediate recognition of estimated credit losses expected to occur over the remaining life of many financial assets. The amendments in this update are effective for interim and annual periods beginning after January 1, 2020, with early adoption permitted by one year. We plan to adopt this new standard on January 1, 2020 and expect that our adoption of this standard will not have a material impact on our consolidated financial statements.

In February 2016, the FASB issued ASC Topic 842 Leases (“ASC Topic 842”). ASC Topic 842 is a new leasing standard that increases transparency and comparability among organizations by, among other things, requiring lessees to recognize most lease assets and lease liabilities on the balance sheet and requiring both lessees and lessors to disclose expanded qualitative and quantitative information about leasing arrangements. ASC Topic 842 becomes effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2018. Early adoption of this standard is permitted. In March 2018, the FASB approved amendments to ASC Topic 842 which allow the additional transition method of using the effective date as the date of initial application, as compared to the beginning of the earliest period presented, and recognize a cumulative-effect adjustment to the beginning balance of retained earnings as of the effective date. We adopted this new standard on January 1, 2019 and plan to use the current period adjustment method. Upon adoption, we will recognize the cumulative effect of adoption as an adjustment to the opening balance of our partners’ capital. Comparative information will continue to be reported under the accounting standards in effect for those periods.

Additionally, in July 2018, the FASB approved amendments to ASC Topic 842 (the “July 2018 amendment”) which provided lessors with a practical expedient to not separate non-lease components from the associated lease component and, instead, to account for those components as a single component if the non-lease components otherwise would be accounted for under ASC Topic 606 and certain conditions are met. The July 2018 amendment also provided clarification on whether ASC Topic 842 or ASC Topic 606 is applicable to the combined component based on determination of the predominant component. An entity that elects the lessor practical expedient also should provide certain disclosures. We have evaluated the impact of the July 2018 amendment on our contract operations services

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Notes to Consolidated Financial Statements

agreements and have concluded that the services non-lease component is predominant, which would result in the ongoing recognition of revenue following ASC Topic 606 guidance.

We have completed the collection of our lease data for the effective date and are using information technology tools to assist in our continuing lease data collection and analysis. We are updating our accounting policies and internal controls that are impacted by the new guidance. We do not believe the standard will materially affect our consolidated balance sheets, statements of operations or cash flows. Our preliminary estimate of the impact of recording lease assets and lease liabilities on our consolidated balance sheet upon adoption does not exceed $4.0 million, with no material impact to our consolidated statements of operations.

In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (“ASC Topic 820”): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement. The amendments to ASC Topic 820 eliminate, add and modify certain disclosure requirements for fair value measurements as part of the FASB’s disclosure framework project. The amendments in this update are effective for interim and annual periods beginning on January 1, 2020, with early adoption permitted. We are currently evaluating the impact, if any, of the amendments to ASC Topic 820 on our consolidated financial statements.

In August 2018, the FASB issued ASU 2018-15, Intangibles-Goodwill and Other-Internal-Use Software (“ASC Subtopic 350-40”): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract. The amendments to ASC Subtopic 350-40 align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software (and hosting arrangements that include an internal-use software license). The accounting for the service element of a hosting arrangement that is a service contract is not affected by the amendments to ASC Subtopic 350-40. The amendments in this update are effective for interim and annual periods beginning on January 1, 2020, with early adoption permitted. The amendments in this update should be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. We are currently evaluating the impact, if any, of the amendments to ASC Subtopic 350-40 on our consolidated financial statements.

(19) Subsequent Events

Phantom Units

In January 2019, an aggregate of 15,150 phantom units (including the corresponding DERs) were granted under the LTIP to two of the independent directors of the General Partner. The phantom units (including the corresponding DERs) awarded are subject to restrictions on transferability, customary forfeiture provisions and will vest incrementally, with 60% of the phantom units vesting on December 5, 2021 and 40% of the phantom units vesting on December 5, 2023. The phantom units will vest in full upon a change in control of the Partnership.

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Supplemental Selected Quarterly Financial Data

(Unaudited)

In the opinion of our management, the summarized quarterly financial data below (in thousands, except per unit amounts) contains all appropriate adjustments, all of which are normally recurring adjustments, considered necessary to present fairly our financial position and the results of operations for the respective periods.

|  | March 31, |  | June 30, |  | September 30, |  | December 31, |
|  | 2018 |  | 2018 |  | 2018 |  | 2018 |
Revenue |  | $ | 76,530 |  | $ | 166,898 |  | $ | 168,947 |  | $ | 171,977 |
Gross profit (1) |  | $ | 39,195 |  | $ | 109,365 |  | $ | 104,638 |  | $ | 116,430 |
Net loss attributable to common and Class B unitholders' interests |  | $ | (23,370) |  | $ | (8,857) |  | $ | (12,751) |  | $ | (2,003) |
Net income (loss) per common unit - basic and diluted (2) |  |  |  |  | $ | (0.06) |  | $ | (0.10) |  | $ | 0.01 |
Net loss per Class B Unit - basic and diluted (2) |  |  |  |  | $ | (0.58) |  | $ | (0.62) |  | $ | (0.51) |

|  | March 31, |  | June 30, |  | September 30, |  | December 31, |
|  | 2017 |  | 2017 |  | 2017 |  | 2017 |
Revenue |  | $ | 65,271 |  | $ | 67,372 |  | $ | 71,089 |  | $ | 72,939 |
Gross profit (1) |  | $ | 36,729 |  | $ | 37,025 |  | $ | 39,422 |  | $ | 38,291 |
Net loss |  | $ | (10,448) |  | $ | (9,715) |  | $ | (12,355) |  | $ | (232,216) |

| (1) |  | Gross profit is defined as revenue less cost of operations, exclusive of depreciation and amortization expense.

| (2) |  | Earnings per unit is not applicable to the USA Compression Predecessor for periods prior to the Transactions Date as the USA Compression Predecessor had no outstanding common units prior to the Transactions.

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