ITEM 1.Business

~~References~~

USA Compression Partners, LP (the “Partnership”) is a growth-oriented Delaware limited partnership. We are managed by our general partner, USA Compression GP, LLC (the “General Partner”), which is a wholly owned subsidiary of Energy Transfer Operating, L.P. (“ETO”), a consolidated subsidiary of Energy Transfer LP (“ET LP”).

On April 2, 2018 (the “Transactions Date”), we acquired (the “CDM Acquisition”) all of the equity interests in CDM Resource Management LLC and CDM Environmental & Technical Services LLC, which together represent the CDM Compression Business (the “USA Compression Predecessor”), and ET LP acquired all of the equity interests in the General Partner, which it subsequently contributed to ETO. USA Compression Predecessor has been determined to be the historical predecessor of the Partnership for financial reporting purposes because ET LP controlled the USA Compression Predecessor prior to the CDM Acquisition and obtained control of the Partnership through its acquisition of the General Partner.

All references in this report to ~~“USA~~the USA Compression Predecessor, as well as the terms “our,” “we,” “us” and “its” refer to the USA Compression Predecessor when used in 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,” ~~“us,~~“we,” ~~“the Partnership” or like terms~~“us” and “its” refer to USA Compression Partners, LP, ~~and~~together with its ~~wholly owned~~consolidated subsidiaries, including the USA Compression ~~Partners, LLC (“USAC Operating”) and USAC OpCo 2, LLC (“OpCo 2” and, together with USAC Operating,~~Predecessor, when used in periods subsequent to the ~~“Operating Subsidiaries”). References to our “general partner” refer to USA Compression GP, LLC. References to “USA Compression Holdings” refer to USA Compression Holdings, LLC,~~Transactions Date, unless the owner of our general partner. References to “USAC Management” refer to USA Compression Management Services, LLC, a wholly owned subsidiary of our general partner. References to “Riverstone” refer to Riverstone/Carlyle Global Energy and Power Fund IV, L.P., and affiliated entities, including Riverstone Holdings, LLC.

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 natural gas compression services in the ~~United States (“~~U.S.”) in terms of total compression fleet horsepower. We have been providing compression services since 1998 and completed our initial public offering in January 2013. As of December 31, ~~2017,~~2020, we had ~~1,799,781~~3,726,181 horsepower in our ~~fleet and 153,020 horsepower on order for expected delivery during 2018 and 2019.~~fleet. 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. ~~The demand~~Demand for our services is driven by the domestic production of natural gas and crude ~~oil; as~~oil. As such, we have focused our activities in areas ~~with~~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”),~~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.~~term. 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~~well-positioned to meet these changing operating conditions due to the operational design flexibility ofinherit in 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, ~~thus reducing~~in order to reduce the hydrostatic pressure and ~~allowing~~allow the oil to flow at a higher rate, and other artificial lift technologies are critical to the enhancement of oil production ~~of oil~~ from horizontal wells operating in tight shale plays.

We operate a modern fleet of compression units, with an average age of approximately ~~five~~seven 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 redeployment risk of our horsepower in the field. Our modern and standardized fleet, decentralized field level operating structure and technical proficiency in predictive

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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.~~

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.

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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~~fixed-fee 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 ~~help generate~~maximize the ~~maximum~~ throughput of product, reduce fuel costs and minimize emissions. While we ~~are currently focused on~~significantly expanded our ~~existing service areas,~~geographic footprint with the CDM Acquisition, our customers may have compression demands in ~~other~~ areas of the U.S. in conjunction with their field development ~~projects.~~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~~Part II, Item 8 “Financial Statements and Supplementary Data” for financial information on our operations and assets; such information is incorporated herein by reference.

Recent Developments

~~On January 15, 2018, we entered into a Contribution~~

Credit Agreement Amendment

The Credit Agreement was amended on August 3, 2020 (the ~~“Contribution Agreement”~~“Amendment Effective Date”) with Energy Transfer Partners, L.P. (“ETP”), Energy Transfer Partners GP, L.P., the general partner of ETP (“ETP GP”), ETC Compression, LLC (“ETC” and, together with ETP and ETP GP, the “Contributors”) and, solely for certain purposes therein, Energy Transfer Equity, L.P. (“ETE” and together with ETP, the “Energy Transfer Parties”), pursuant to ~~which,~~amend, among other things, ~~ETP will contribute to us,~~the requirements of certain covenants and ~~we will acquire from ETP, all~~the date on which certain covenants in the Credit Agreement must be met beginning on the Amendment Effective Date until the last day of the ~~issued~~fiscal quarter ending December 31, 2021 (the “Covenant Relief Period”).

The amendment, among other items, increases the maximum funded debt to EBITDA ratio to (i) 5.75 to 1.00 for the fiscal quarters ending September 30, 2020 and ~~outstanding membership interests~~December 31, 2020, (ii) 5.50 to 1.00 for the fiscal quarters ending March 31, 2021 and June 30, 2021 and (iii) 5.25 to 1.00 for the fiscal quarters ending September 30, 2021 and December 31, 2021 (reverting back to 5.00 to 1.00 after the Covenant Relief Period).

In addition, during the Covenant Relief Period, the applicable margin for Eurodollar borrowings is increased from a range of ~~CDM Resource Management LLC (“CDM Management”) and CDM Environmental & Technical Services LLC (“CDM E&T” and, together with CDM Management, “CDM”) for aggregate consideration~~2.00% – 2.75% to a range of ~~approximately $1.7 billion consisting of units representing limited partner interests in the Partnership and an amount in cash equal to $1.225 billion, subject to certain adjustments(the “CDM Acquisition”)~~2.25% – 3.00%.

~~The CDM Acquisition is expected to close~~

COVID-19

Beginning in the first ~~half~~quarter of ~~2018, subject~~2020, the COVID-19 pandemic prompted several states and municipalities in which we operate to ~~customary closing conditions, including (i)~~take extraordinary and wide-ranging actions to contain and combat the ~~concurrent closing~~outbreak and spread of the ~~GP Purchase (as defined below),~~virus, including mandates for many individuals to substantially restrict daily activities and ~~(ii)~~for many businesses to curtail or cease normal operations. These mandates and restrictions have varied across jurisdictions and, over time, have been rescinded and reinstated as the transactions contemplated by the Equity Restructuring Agreement (as defined below), including the Restructuring (as defined below), shall be able to be consummated immediately following the Closing (as defined below), and as otherwise described in the Contribution Agreement (the “Closing”).

~~On January 15, 2018, and in connection with the execution~~severity of the ~~Contribution Agreement, ETE entered into a Purchase Agreement (the “GP Purchase Agreement”) with Energy Transfer Partners, L.L.C. (together with ETE,~~pandemic fluctuated. For as long as COVID-19 continues or worsens, governments may impose additional similar restrictions or reinstate previously lifted ones. To date, our field operations have continued largely uninterrupted as the ~~“GP Purchasers”), USA Compression Holdings,~~U.S. Department of Homeland Security designated our industry part of our country’s critical infrastructure. Thus far, remote work and ~~solely for certain purposes therein, R/C IV USACP Holdings, L.P.~~other COVID-19 related conditions have not significantly impacted our ability to maintain operations or caused us to incur significant additional expenses; however, we are unable to predict the duration or ultimate impact of current and ETP, pursuant to which the GP Purchasers will acquire from USA Compression Holdings (i) all of the outstanding limited liability company interests in our general partner, and (ii) 12,466,912 common units (the “GP Purchase”).

On January 15, 2018, and in connection with the execution of the Contribution Agreement, we entered into an Equity Restructuring Agreement (the “Equity Restructuring Agreement”) with our general partner and ETE, pursuant to which, among other things, we, our general partner and ETE have agreed to cancel our incentive distribution rights (the “Cancellation”) and convert our General Partner Interest (as defined in the Equity Restructuring Agreement) into a non-economic general partner interest (the “Conversion” and, together with the Cancellation, the “Restructuring”), in exchange for our issuance of 8,000,000 common units to the general partner, effective at the Closing.

potential future COVID-19 mitigation measures.

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On January 15, 2018, we entered into a Series A Preferred Unit and Warrant Purchase Agreement (the “Series A Purchase Agreement”) with certain investment funds managed or sub-advised by EIG Global Energy Partners (“EIG”) and other investment vehicles unaffiliated with EIG (collectively, the “Purchasers”) to issue and sell in a private placement (the “Private Placement”) $500 million in the aggregate of (i) newly authorized and established Series A Perpetual Preferred Units representing limited partner interests in the Partnership (the “Preferred Units”) and (ii) warrants to purchase common units (the “Warrants”). We will issue 500,000 Preferred Units to the Purchasers at a price of $1,000 per Preferred Unit (the “Preferred Unit Purchase Price”), less a 1.0% structuring and origination fee, for total net proceeds, before expenses, of $495 million. In addition, we will pay a 1.0% commitment fee to the Purchasers at the closing, as well as reimburse the Purchasers for up to $400,000 of certain expenses incurred in connection with the transaction. We will also issue two tranches of Warrants to the Purchasers, which will include Warrants to purchase 5,000,000 common units with a strike price of $17.03 per unit and 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 closing date and before the tenth anniversary of the closing date. Upon exercise of the Warrants, we may, at our option, elect to settle the Warrants in common units on a net basis. The Series A Purchase Agreement contains customary representations, warranties and covenants of the Partnership and the Purchasers. The closing of the Private Placement is subject to customary closing conditions, including that we will have increased the aggregate commitments under our revolving credit facility to (or entered into a similar revolving facility with minimum aggregate commitments of) at least $1.3 billion.

In connection with the CDM Acquisition, on January 15, 2018, we entered into a commitment letter (the “Bridge Commitment”) with JPMorgan Chase Bank, N.A. and Barclays Bank PLC, as modified by the joinder to commitment letter and bridge fee letter entered into by the Partnership, JPMorgan Chase Bank, N.A. and Barclays Bank PLC with each of Regions Bank, Royal Bank of Canada, Wells Fargo Bank, N.A., MUFG Union Bank, N.A., a member of MUFG, a global financial group, The Bank of Nova Scotia and SunTrust Bank and certain affiliates of such parties (the “Commitment Letter”). The Commitment Letter provides for senior unsecured bridge loans in an aggregate amount up to $725 million (the “Bridge Loans”). The proceeds of such Bridge Loans may be used (a) to finance a portion of the purchase price of the CDM Acquisition and (b) to pay fees and expenses incurred in connection therewith. The availability of the borrowings is subject to the satisfaction of certain customary conditions. The Bridge Commitment will expire upon the earliest to occur of (1) the Outside Date as defined in the Contribution Agreement (as the same may be extended thereunder), (2) the consummation of the CDM Acquisition without use of the Bridge Loans, (3) the termination of the Contribution Agreement in accordance with its terms, or (4) September 30, 2018. The Bridge Loans are available to backstop a portion of the CDM Acquisition purchase price that we expect to fund with the net proceeds of other debt financing.

~~Our historical financial and other information in this Annual Report on Form 10-K do not give effect to any of the transactions described in this section titled “Recent Developments.”~~

~~Business Strategies~~

Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over 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 both in emerging shale plays and conventional basins.

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~~Continue to execute on attractive organic growth opportunities~~. From 2007 to 2017, we grew the horsepower in our fleet of compression units and our compression revenues each at a compound annual growth rate of 15% primarily through organic growth. We believe organic growth opportunities will continue to be a source of near-term growth and we expect such organic growth levels in 2018 will be consistent with the growth seen in the second half of 2017. We seek to achieve continued organic growth by (i) increasing our business with existing customers, (ii) obtaining new customers in our existing areas of operations and (iii) expanding our operations into 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 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 be able to take advantage of growth opportunities. Historically, we have utilized our cash flow from operations, borrowings under our revolving credit facility 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 our debt at levels 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 fixed 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.

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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. ~~Approximately 98% of our fleet horsepower as~~As of December 31, ~~2017 was purchased new and~~2020, the average age of our compression units was approximately ~~five~~seven years. Our modern, standardized compression unit fleet is powered primarily by the Caterpillar 3400, 3500 and 3600 engine classes, which range from 401 to ~~4,735~~5,000 horsepower per unit. These larger horsepower units, which we define as 400 horsepower per unit or greater, represented ~~83.0%~~86.3% of our total fleet horsepower ~~(including compression units on order)~~ as of December 31, ~~2017. In addition, a portion~~2020. The remainder of our fleet consists of smaller horsepower units ranging from 3040 horsepower to 399 horsepower that are primarily used in gas lift applications. We believe the ~~young~~average age and 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, ~~2017:~~

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

333,004

2,227

—

—

333,004

2,227

17.1
%

65.0
%
Large horsepower

>400 and <1,000

161,822

284

—

—

161,822

284

8.3
%

8.3
%
>1,000

1,304,955

844

153,020

69

1,457,975

913

74.7
%

26.7
%
Total

1,799,781

3,355

153,020

69

1,952,801

3,424

100.0
%

100.0
%

2020:


Unit Horsepower	Fleet Horsepower	Number of Units	Percent of Fleet Horsepower		Percent of Units
Small horsepower
<400	510,123	3,001	13.7	%	55.0	%
Large horsepower
>400 and <1,000	437,543	751	11.7	%	13.8	%
>1,000	2,778,515	1,702	74.6	%	31.2	%
Total large horsepower	3,216,058	2,453	86.3	%	45.0	%
Total horsepower	3,726,181	5,454	100.0	%	100.0	%

~~(1)~~

~~As of December 31, 2017, we had 147,500 and 5,520 horsepower on order for delivery during 2018 and 2019, respectively.~~

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

Year Ended

Percent

December 31,

Change

Operating Data:

2017

2016

2015

2017

2016

Fleet horsepower (at period end) (1)

1,799,781

1,720,547

1,712,196

4.6
%
0.5
%
Total available horsepower (at period end) (2)

1,950,301

1,730,547

1,712,196

12.7
%
1.1
%
Revenue generating horsepower (at period end) (3)

1,624,377

1,387,073

1,424,537

17.1
%
(2.6)
%
Average revenue generating horsepower (4)

1,505,657

1,377,966

1,408,689

9.3
%
(2.2)
%
Revenue generating compression units (at period end)

2,830

2,552

2,737

10.9
%
(6.8)
%
Average horsepower per revenue generating compression unit (5)

554

534

517

3.7
%
3.3
%
Horsepower utilization (6):

At period end

94.8
%
87.1
%
89.2
%
8.8
%
(2.4)
%
Average for the period (7)

92.0
%
87.4
%
90.5
%
5.3
%
(3.4)
%
indicated and excludes certain natural gas treating assets for which horsepower is not a relevant metric:


	Year Ended December 31,				Percent
Operating Data:	2020		2019		Change
Fleet horsepower (at period end) (1)	3,726,181		3,682,968		1.2	%
Total available horsepower (at period end) (2)	3,726,181		3,709,468		0.5	%
Revenue generating horsepower (at period end) (3)	2,997,262		3,310,024		(9.4)	%
Average revenue generating horsepower (4)	3,139,732		3,279,374		(4.3)	%
Revenue generating compression units (at period end)	3,968		4,559		(13.0)	%
Average horsepower per revenue generating compression unit (5)	746		720		3.6	%
Horsepower utilization (6):
At period end	82.8	%	93.7	%	(11.6)	%
Average for the period (7)	86.8	%	94.1	%	(7.8)	%

~~(1)~~

Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order). As of December 31, 2017, we had 147,500 and 5,520 horsepower on order for delivery during 2018 and 2019, respectively.

________________________

~~(2)~~

Total available horsepower is revenue generating horsepower under contract for which we are billing a customer, horsepower in our 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.

(1)Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order).

~~(3)~~

~~Revenue generating horsepower is horsepower under contract for which we are billing a customer.~~

(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.

~~(4)~~

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

(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.

~~Table~~(6)Horsepower utilization is calculated as (i) the sum of ~~Contents~~

(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 80.4% and 89.9% at December 31, 2020 and 2019, respectively.

~~(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.~~

(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 84.5% and 89.8% for the years ended December 31, 2020 and 2019, respectively.

~~(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 at each applicable period end was 90.3%, 80.6% and 83.2% for the years ended December 31, 2017, 2016 and 2015, respectively.

~~(7)~~

Calculated as the average utilization for the months in the period based on utilization at the end of each month in the period. Average horsepower utilization based on revenue generating horsepower and fleet horsepower was 85.9%, 80.3% and 85.1% for each year ended December 31, 2017, 2016, and 2015, respectively.

~~A growing number~~Many of our compression units contain ~~electronic control systems~~devices that enable us to monitor the units remotely bythrough cellular and satellite ~~or other means~~networks to supplement our technicians’ on-site monitoring visits. We intend to continue to selectively add remote monitoring systems to our new and existing fleet during ~~2018~~2021 where beneficial from an ~~operating~~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 ~~to avoid~~that avoids excessive annual maintenance capital expenditures and ~~minimize~~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.

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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~~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 applicable 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, 2017, approximately 51% of our compression services on a revenue basis were provided on a month-to-month basis to customers who continue to utilize our services following expiration of the primary term of their contracts 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.

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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.

~~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 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, to determine a customer’s needs related to existing services being provided and to 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 ~~250~~275 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 ~~43%~~35%, 33% and 33% of our revenue for ~~each of~~ the years ended December 31, ~~2017~~2020, 2019 and ~~2016.~~

2018, 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

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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 ~~S&R Compression,~~Genis Holdings LLC, ~~(“S&R”)~~, to package and assemble our compression units. Although we rely primarily on these suppliers, we believe alternative sources for natural gas compression equipment are generally available if needed. However, relying 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~~as of December 31, 2020, lead-times for such engines and frames are approximately ~~one year or shorter.~~six months. Please read Part I, Item 1A ~~(“Risk Factors—~~“Risk Factors – Risks Related to Our ~~Business—~~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 ~~as well as~~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—~~“Risk Factors – Risks Related to Our ~~Business—~~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 ~~reflected any material~~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 – General Risk ~~Factors—Risks Related to Our Business—~~Factors – We do not insure against all potential losses and could be seriously harmed by unexpected liabilities”).

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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

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operations and limit our growth and revenue. Moreover, failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of remedial obligations and the issuance of injunctions delaying or prohibiting operations. Private parties may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. While we believe that our operations are in substantial compliance with applicable environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, ~~there is no assurance that this trend~~we cannot predict whether our cost of compliance will ~~continue~~materially increase in the future. ~~Thus, any~~Any changes in, or more stringent enforcement of, ~~these~~existing environmental laws and regulations, or passage of additional 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—~~“Risk Factors – Risks Related to ~~Our Business—~~Government Legislation and Regulation – 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 ~~the~~ 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 ~~emission~~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 ~~Standard~~Standards (“~~NAAQs”~~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 ~~9-hour~~8-hour concentration standards of 70 parts per ~~billion (“ppb”).~~billion. In December 2020, the EPA announced its decision to retain, without changes, the 2015 NAAQS. After the EPA revises a NAAQS standard, the states are expected to establish revised attainment/non-attainment regions. State implementation of the ~~revised~~2015 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 ~~emission~~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 ~~emission~~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

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OOOOa standards ~~will expand~~would have expanded 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, in September 2020, the EPA ~~announced in April 2017~~issued a final rule that ~~it intends to reconsider certain aspects of~~removed the transmission and storage segment from the 2016 New Source Performance Standards, rescinded VOCs and ~~in May 2017,~~methane emissions standards for the transmission and storage segment, and rescinded methane emissions standards for the production and processing segments. Various states and industry and environmental groups are separately challenging the EPA’s 2016 standards and its September 2020 final rule. Notwithstanding the current court challenges, on January 20, 2021, President Biden issued an executive order directing the EPA ~~issued an administrative stay of key provisions of~~to consider publishing for notice and comment a proposed rule suspending, revising, or rescinding the September 2020 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~~which could result 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.~~

~~Subpart OOOOa and any~~more stringent methane emission rulemaking.

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 ~~emission~~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~~.change. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse ~~gases.~~gases (“GHGs”). In recent years, the U.S. Congress has considered legislation to reduce ~~emissions~~GHG emissions. At the federal level, President Biden could seek to pursue legislative, regulatory or executive initiatives that may impose significant restrictions on fossil-fuel exploration, production and use such as limitations or bans on hydraulic fracturing of ~~greenhouse gases. It presently appears unlikely that~~oil and gas wells, bans or restrictions on new leases for production of minerals on federal properties, and imposing restrictive requirements on new pipeline infrastructure or fossil-fuel export facilities. For example, on January 27, 2021, President Biden issued an executive order directing the Secretary of the Interior to pause approval of new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive ~~climate legislation will be passed by either house~~review and reconsideration of ~~Congress in the near future, although~~federal oil and gas permitting and leasing practices. Other energy legislation and ~~other~~ initiatives ~~are expected to be proposed~~could include a carbon tax or cap and trade program. At the state level, many states, including the states in which we or our customers conduct operations, have adopted legal requirements that ~~may be relevant to greenhouse~~have imposed new or more stringent permitting, disclosure or well construction requirements on oil and gas ~~emissions issues. However,~~activities. Further, although Congress has not passed such legislation, almost half of the states have begun to address ~~greenhouse gas~~GHG emissions, primarily through the planned development of ~~emission~~emissions inventories or regional ~~greenhouse gas~~GHG cap and trade programs. Depending on the particular program, we could be required to control ~~greenhouse gas~~GHG emissions or to purchase and surrender allowances for ~~greenhouse gas~~GHG emissions resulting from our operations.

Independent of Congress, the EPA undertook to adopt regulations controlling ~~greenhouse gas~~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 ~~greenhouse gases~~GHGs endanger human health and the environment, allowing the agency to proceed with the adoption of regulations that restrict emissions of ~~greenhouse gases~~GHG under existing provisions of the CAA. In 2009 and 2010, the EPA adopted rules regarding regulation of ~~greenhouse gas~~GHG emissions from motor vehicles and requiring the reporting of ~~greenhouse gas~~GHG emissions in the U.S. from specified large ~~greenhouse gas emission~~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,~~addition, from time to time, there have been various proposals to regulate hydraulic fracturing at the ~~EPA published standards~~federal level. Hydraulic fracturing involves the injection of ~~performance for greenhouse~~water, sand and chemicals under pressure into the rock formation to stimulate gas ~~emissions from new power plants. The final rule establishes a performance standard for integrated gasification combined cycled units and utility boilers based on~~production. On January 27, 2021, President Biden issued an executive order directing the ~~use~~Secretary of the ~~best system~~Interior to pause approval of emission reduction that 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 (“CCP”), 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

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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 of the D.C. Circuit and the Supreme Court through any certiorari petition that may be granted. It is not yet clear how the courts will rule on the legality of the CPP. Additionally, in October 2017 the EPA proposed to repeal the CPP, although the final outcome of this action and the pending litigation regarding the CPP is uncertain at this time. In connection with the proposed repeal, EPA issued an Advance Notice of Proposed Rulemaking (“ANPRM”) in December 2017 regarding emission guidelines to limit emissions of greenhouse gases (“GHGs”) from existing electricity utility generating units. The ANPRM seeks comment regarding what the EPA should include in a potential new existing-source regulation under the Clean Air Act of GHG emissions from electric utility generating units that it may propose. If the effort to repeal the rules is unsuccessful and the rules are upheld at the conclusion of this appellate process and were implemented in their current form, or if the ANPRM results in a different proposal 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~~leases on public lands or in offshore waters pending completion of ~~electricity for our operations may also increase, thereby adversely impacting our business.~~

~~In addition to the EPA, the Bureau~~a comprehensive review

Table 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,~~ Contents

and ~~chemical disclosure for companies drilling on~~reconsideration of federal and tribal land. The agency subsequently finalized a rule in December 2017 rescinding the 2015 rule. On November 15, 2016, the BLM also finalized a rule to reduce the flaring, venting and leaking of methane from oil and gas ~~operations~~permitting and leasing practices, effectively limiting hydraulic fracturing on federal lands and Indian lands (“BLM Venting Rule”). The rule requires operators to use certain technologies and equipment to reduce flaring and to periodically inspect their operations for leaks. The rule also specifies when operators owewaters. Any limitations or bans on hydraulic fracturing at the government royalties for flared gas. In November 2016, state and industry groups challenged this BLM rule in the U.S. District Court for the District of Wyoming, asserting that the BLM lacks authority to prescribe air quality regulations. The court stayed the case in December 2017, however, when the BLM finalized a decision to delay implementation of key requirements in the rule for one year. If the BLM Venting Rule is not repealed and survives legal challenge, itfederal level could increase the costs of operations for our ~~clients~~customers who operate on ~~BLM~~federal land, and negatively impact our business.

Some states have also passed legislation or regulations regarding hydraulic fracturing. For example, in 2019, Colorado passed Senate Bill 181, which delegates authority to local governments to regulate oil and gas activities and requires the Colorado Oil and Gas Conservation Commission to minimize emissions of methane and other air contaminants. Some local communities have adopted additional restrictions for oil and gas activities, such as requiring greater setbacks, and some groups are petitioning local governments to ban hydraulic fracturing. If additional regulatory measures are adopted that ban or restrict production of natural gas through hydraulic fracturing, our customers could experience delays, limitations, or prohibitions on their activities. Such delays, limitations, or prohibitions could result in decreased demand for our services.

Litigation risks are also increasing, as a number of cities, local governments and other plaintiffs have sued companies engaged in the exploration and production of fossil fuels in state and federal courts, alleging various legal theories to recover for the impacts of alleged global warming effects, such as rising sea levels. Many of these suits allege that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts. Although a number of these lawsuits have been dismissed, others remain pending and the outcome of these cases remains difficult to predict.

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 Paris Agreement went into effect on November 4, 2016. While 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~~withdrew from the Paris Agreement ~~or renegotiate more favorable terms. However,~~on November 4, 2020, President Biden issued an executive order on January 20, 2021 recommitting the United States to the Paris ~~Agreement stipulates that participating countries must wait four years before withdrawing from the agreement. Despite the planned withdrawal,~~Agreement. In addition, 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 ~~greenhouse gas~~GHG legislation, regulation, agreements or initiatives will impact our business, any legislation or regulation of ~~greenhouse gas~~GHG emissions that may be imposed in areas in which we conduct business or on the assets we operate, including a carbon tax or cap and trade program, 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 EIA estimates that oil and gas will continue to represent a major share of energy use through 2050. 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 ~~the earth’s~~Earth’s atmosphere may produce climate changes that have significant ~~physical~~weather-related effects, such as increased frequency and severity of storms, droughts, ~~and~~ 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 U.S. 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 required, to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak at

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such facilities. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Our compression operations do not generate process wastewaters that are discharged to waters of the U.S. In any event, our customers assume responsibility under 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 ~~the~~ property by filling wetlands. ~~Considerable legal uncertainty exists surrounding~~On April 21, 2020, the EPA and the U.S. Army Corps of Engineers issued a rule streamlining the standard for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the CWA. ~~A 2015 rulemaking by~~Lawsuits have been filed challenging the ~~EPA~~rule, and on January 20, 2021, President Biden issued an executive order directing the heads of all agencies to ~~revise~~immediately review all

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regulatory actions taken between January 20, 2017 and January 20, 2021, including the standard was stayed nationwide by the U.S. Court of Appeals for the Sixth Circuit and stayed for certain primarily western states by a U.S. District Court in North Dakota. For now, the EPA and the Army Corps of Engineers (“Corps”) will continue to apply the existing standard for what constitutes a water of the U.S. as determined by the Supreme Court in the ~~Rapanos~~ ~~case and post-Rapanos~~ ~~guidance.~~April 2020 rule. Should the ~~2015~~April 2020 rule ~~take effect,~~be rescinded or ~~should~~ a different rule ~~expanding~~promulgated that expands the ~~definition of what constitutes a water~~jurisdictional reach of the ~~U.S. be promulgated as a result of the EPA and the Corps’ rulemaking process,~~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~~.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. ~~Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production.~~ Legislation to amend the Safe Drinking Water Act (“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 from time to time 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 also has 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 ~~the development of new interpretations of those requirements by~~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 ~~would~~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 may impose strict, joint and several liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner and operator of a disposal site where a hazardous substance release occurred and any company

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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~~the Resource Conservation and Recovery Act 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 ~~the~~ Title III of CERCLA and similar state statutes require that we organize and, as necessary, disclose information about hazardous materials used or produced in our operations to various federal, state and local agencies, as well as employees.

~~Employees~~

Human Capital Management

USA Compression Management Services, LLC (“USAC ~~Management,~~Management”), a wholly owned subsidiary of ~~our general partner,~~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, ~~2017,~~2020, USAC Management had ~~426~~742 full time employees. None of our employees are subject to collective bargaining agreements. We consider our employee relations to be good.

Our employees are our greatest asset, and we seek to attract and retain top talent by fostering a culture that is guided by our four pillars of people, culture, equipment and service. These four pillars guide our values in a manner that respects all people with a commitment to safety and the environments where we operate.

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Ethics and Values. We are committed to operating our business in a manner that honors and respects all people and the communities in which we do business. We recognize that people are our most critical resource, and we are committed to hiring and investing in our employee base. We value employees for what they bring to our organization by embracing those from diverse backgrounds, cultures, and experiences. We believe that one of the keys to our successes over time has been the cultivation of an atmosphere of inclusion and respect. These are the principles upon which we build and strengthen relationships among our people, our unitholders, our customers, and those within the communities we support.

We believe strict adherence to our Code of Business Conduct and Ethics is not only right, but is in our best interest and the best interest of our unitholders, our customers, and the industry in general. In all instances, our policies require that the business of the Partnership be conducted in a lawful and ethical manner. Every employee acting on behalf of the Partnership must adhere to our policies. Please refer to Part III, Item 10 “Directors, Executive Officers and Corporate Governance” for additional information on our Code of Business Conduct and Ethics.

Commitment to Safety and the Environment. We have a strong commitment to safety and the environment. We provide continuous training opportunities for employees, including training that is required by applicable laws, regulations, standards, and permit conditions. Our safety standards and expectations are clearly communicated to all operations employees with the expectation that each individual has the obligation to make safety their highest priority. Our safety culture promotes an open environment for discovering, resolving, and sharing safety challenges. We strive to eliminate unwanted safety events and support our safety culture through a comprehensive program that includes a dedicated field operations based safety team, monthly employee safety meetings and safety audits, among other things. A portion of our senior management bonuses and field management bonuses are dependent on our safety performance. We promote employee empowerment, leadership, communication, personal responsibility to comply with standard operating procedures and regulatory requirements, effective risk reduction processes, and personal wellness. Our goal is operational excellence, which includes maintaining an injury- and incident-free workplace. To achieve this, we strive to hire and maintain the most qualified and dedicated workforce in the industry and make safety and safety accountability part of our daily operations. The OSHA Total Recordable Incident Rate (“TRIR”) is a key performance indicator by which we evaluate the success of our safety program. TRIR provides a measure of occupational safety performance for the year by calculating the number of recordable incidents compared to the total number of hours worked by all employees. Out of more than 1,850,000 hours worked, our TRIR was 0.32 for 2020, compared to 0.84 in 2019, versus the industry average for 2020 which was 0.90. We believe our low TRIR and our 2,000,000 hours worked without a lost time event speaks to our investment in and focus on safety.

Regarding COVID-19, as an essential business providing critical energy infrastructure, the safety of our employees and the continued operation of our assets are our top priorities, and we continue to follow and operate in accordance with federal, state and local health guidelines and safety protocols. We also continue to follow the U.S. Center for Disease Control guidance and provide employees with training and direction to help maintain the health and safety of our workforce.

Available Information

Our website address is usacompression.com. We make available, free of charge at the “Investor Relations” ~~portion~~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 ~~Securities and Exchange Commission (“SEC”).~~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. Any materials we file with the SEC also may be read or copied at the SEC’s Public Reference Room at 100 F Street, NE, Washington, DC 20549. Information concerning the operation of the Public Reference Room may be obtained by calling the SEC at (800) 732-0330.

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ITEM 1A.Risk Factors

As described in Part I ~~(“Disclosure~~“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 ~~occur,~~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 ~~grow~~increase the level of such distributions in the future, and the trading price of our common units could decline.

Risk Factor Summary

Risks Related to Our Business

•The ongoing global COVID-19 pandemic and recent oil market developments have had and may continue to have an adverse effect on our business and results of operations.

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•We may not ~~have~~generate sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to ~~our general partner,~~the General Partner, to enable us to make cash distributions aton our ~~current distribution rate to our unitholders.~~

In order to make cash distributions at our current distribution rate of $0.525 per unit per quarter, or $2.10 per unit per year, we will require available cash of $33.1 million per quarter, or $132.2 million per year, based on the number of common units ~~and~~at the 1.2% general partner interest outstanding as of February 8, 2018. 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 locations where we provide compression services;~~

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

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

~~the ability to effectively integrate any assets or businesses we acquire, including the CDM Acquisition;~~

~~the level of competition from other companies; and~~

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

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

~~the levels of our maintenance capital expenditures and expansion capital expenditures;~~

~~the level of our operating costs and expenses;~~

~~our debt service requirements and other liabilities;~~

~~fluctuations in our working capital needs;~~

~~restrictions contained in our revolving credit facility;~~

~~the cost of acquisitions;~~

~~fluctuations in interest rates;~~

~~the financial condition of our customers;~~

~~our ability to borrow funds and access the capital markets; and~~

current level.

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~~the amount of cash reserves established by our general partner.~~

•A long-term reduction in the demand for, or production of, natural gas or crude oil could adversely affect the demand 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.

•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.

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

•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.

•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.

•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.

•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.

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

•The terms of the Credit Agreement and the Indentures 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.

•A prolonged or severe sudden downturn in the economic environment, such as the severe impact of the COVID-19 pandemic, could cause an impairment of identifiable intangible assets and reduce our earnings.

•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.

Risks Related to Governmental Legislation and Regulation

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

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

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.

•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.

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

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

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

•We may issue additional limited partner interests without the approval of unitholders, subject to certain Preferred Unit approval rights, which would dilute 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 General Partner has a call right that may require you to sell your common units at an undesirable time or price.

•Unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.

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

•Our Partnership Agreement designates the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our general partner’s directors, officers or other employees.

Tax Risks to Common Unitholders

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

•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.

•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.

•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.

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

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

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

•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 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.

•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.

Risks Related to Our Business

The ongoing global COVID-19 pandemic and recent oil market developments have had and may continue to have an adverse effect on our business and results of operations.

The COVID-19 pandemic that began in early 2020 has caused volatility in the capital markets and negatively impacted the worldwide economy, including the oil and gas industry. Demand for crude oil and natural gas has declined due in part to the COVID-19 outbreak and associated government imposed restrictions and decreased consumer demand, which have had, and may continue to have, a negative impact on many of our customers involved in the domestic exploration and production of crude oil and natural gas.

In addition, turmoil between the members of OPEC+ in 2020 resulted in Saudi Arabia discounting its price and increasing its supply of oil into the global marketplace in early 2020. The dual forces of increased supply and reduced demand due to COVID-19 caused oil prices to fall substantially, adversely affecting some of our customers. As a result, some producers chose to delay, or shut-in, production.

While the extent of the impact these events will have on our results of operations and financial condition is uncertain, they are examples of events that caused a reduction in the demand for, price of and level of production of natural gas and crude oil in the regions where we provide compression services, which potentially could cause:

•a negative impact on our results of operations and financial condition;

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•the deterioration of the financial condition of our customers, suppliers and vendors;

•a hindrance on our ability to pay distributions, service our debt and other liabilities, and comply with certain restrictive financial covenants in the Credit Agreement and the Indentures (the “Indentures”) governing the Senior Notes 2026 and Senior Notes 2027 (collectively, the “Senior Notes”);

•renegotiation of our service contracts at lower rates; and

•additional costs to us, which could be significant, in connection with litigation and bankruptcies resulting from customer financial deterioration.

Furthermore, market volatility could increase our cost of capital and block our access to the equity and debt capital markets, which could eventually impede our ability to grow, make distributions to our unitholders at current levels and comply with the terms of our debt agreements.

Additionally, if COVID-19 were to significantly spread into our workforce, this could hinder our ability to provide services and otherwise perform our contractual obligations to our customers. The duration of the COVID-19 pandemic and the magnitude of its repercussions cannot be reasonably estimated at this time, and depending on its duration and severity, it could materially adversely affect our financial condition and results of operations.

We may not generate 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 $50.9 million per quarter, or $203.7 million per year, based on the number of common units outstanding as of February 11, 2021.

Furthermore, our Second Amended and Restated Agreement of Limited Partnership (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;

•state sales and use taxes that may be levied upon us by the states in which we operate;

•fluctuations in our working capital needs;

•restrictions contained in the Credit Agreement or the Indentures;

•the cost of acquisitions;

•fluctuations in interest rates;

•the financial condition of our customers;

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•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, global health pandemics (such as COVID-19), governmental regulation and ~~general~~the overall demand for energy. Any ~~prolonged, substantial~~further or extended reduction in the demand for natural gas or crude oil would likely further 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~~one million British thermal units (“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~~had decreased to 404 rigs on May 20, 2016, and at that time, Henry Hub natural gas spot prices were ~~$1.92~~$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

Following disputes between the members of OPEC+ about production levels and the price of oil and amid the outbreak of COVID-19, the price of oil declined rapidly beginning in March 2020. As of the end of December ~~2017,~~2020, the North American rig count was ~~929~~351 rigs, asthe price of WTI crude oil ~~spot prices hovered near their highest level since the summer of 2015 at $60.46~~was $48.35 per barrel and Henry Hub natural gas spot prices were ~~$2.81~~$2.36 per MMBtu. ~~Although~~The current decline in commodity prices and crude oil and natural gas production has resulted in a decline in the demand for our ~~utilization~~compression services, which resulted in a reduction of our revenues and our cash available for distribution. In addition, any future decreases in the rate at which crude oil and natural gas reserves are developed, whether due to increased ~~during 2016~~governmental regulation, limitations on exploration and ~~2017, the increased~~production activity ~~resulting from such increased commodity prices may not continue~~ or ~~the trend of increasing commodity prices may reverse.~~other factors, could have a material adverse effect on our business. 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~~periods of low crude oil prices, we ~~experienced~~typically experience pressure on service rates from our customers in gas lift ~~applications; if commodity prices decline from current levels,~~applications, and we ~~may~~have started to experience ~~pressure on service rates.~~

such effects.

Additionally, ~~an increasing percentage of natural gas and crude oil production comes from~~ unconventional sources, such as shales, tight sands and ~~coalbeds. Such sources~~coalbeds, 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 bebecome uneconomic to drill and produce, which ~~could in turn~~has negatively impacted, and may continue to negatively impact, the demand for our services. Further, if demand for our services decreases going forward, 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 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 ten largest customers accounted for approximately ~~43%~~35%, 33% and 33% of our revenue for ~~each of~~ the years ended December 31, ~~2017~~2020, 2019 and ~~2016.~~2018, 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, such as during the COVID-19 pandemic, 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

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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. ~~In addition, in~~

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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, including as a result of the ~~course~~COVID-19 pandemic, has had and could reduce the liquidity of our ~~business we hold accounts receivable~~customers, suppliers or vendors, making it more difficult for them to meet their obligations to us. We are therefore subject to heightened risks of loss resulting from nonpayment or nonperformance by our ~~customers.~~customers, suppliers and vendors. Severe financial problems encountered by our customers, suppliers and vendors 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 ~~such customer~~of our customers was to enter into bankruptcy, we could lose all or a portion of the amounts owed to us by such ~~outstanding accounts receivable associated with that customer. Further, if a~~ customer, ~~was~~and we may be forced to ~~enter into bankruptcy, it could also result in the cancellation of~~cancel all or a portion of our service contracts with such customer at significant expense to us.

For example, as of December 31, 2020, two customers accounted for 13% and 11% of our trade account receivables, net balance, respectively. If either of these customers was to enter bankruptcy or failed to pay us, it could adversely affect our business, results of operations, financial condition and cash flows.

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. All of the above may be exacerbated in the future as the COVID-19 outbreak and the governmental responses thereto continue. These factors, combined with volatile prices of oil and natural gas, may precipitate a continued economic slowdown and/or a recession.

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 ~~as well as~~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, ~~that~~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 ~~reduce our~~ cash available for distribution.

Our customers may choose to vertically integrate their operations by purchasing and operating their own compression fleet, ~~expanding~~increasing the ~~amount~~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 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 ~~applicable~~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~~For the year ended December 31, ~~2017,~~2020, approximately ~~51%~~30% 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.~~contracts. These customers can generally terminate their month-to-month compression services contracts on ~~30-days’~~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.

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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 ~~continue to grow the~~maintain or increase our per common unit distribution ~~on our units~~ 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;~~

•develop new business and enter into service contracts with new customers;

~~retain our existing customers and maintain or expand the services we provide them;~~

•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;~~

•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;~~

•recruit and train qualified personnel and retain valued employees;

~~expand our geographic presence;~~

•expand our geographic presence;

~~effectively manage our costs and expenses, including costs and expenses related to growth;~~

•effectively manage our costs and expenses, including costs and expenses related to growth;

~~consummate accretive acquisitions;~~

•consummate accretive acquisitions;

~~obtain required debt or equity financing on favorable terms for our existing and new operations; and~~

•obtain required debt or equity financing on favorable terms for our existing and new operations; and

~~meet customer specific contract requirements or pre-qualifications.~~

•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 toon our ~~unitholders,~~common units, in which event the market price of our common units will likely ~~decline materially.~~

decline.

We may be unable to grow successfully through acquisitions, ~~and we~~which may ~~not be able to integrate effectively the businesses we may acquire, which may~~negatively impact our operations and limit our ability to maintain or increase the level of distributions toon our ~~unitholders.~~

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. ~~In addition,~~

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, 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;

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•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 in 2018 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 ~~any future~~ acquisitions ~~including the CDM Acquisition,~~ into our existing operations within our anticipated time frame, which may result in unforeseen operational difficulties or diminished financial performance or require a disproportionate amount of our management’s attention. ~~Even if we are successful in integrating~~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 ~~acquisitions into our existing~~results of operations we may not derive the benefits, such as operational or administrative synergies, that we expected from such acquisitions, which may result in the commitment of our capital resources without the expected returns on such capital. Furthermore, competition for acquisition opportunities may escalate, increasing our cost of making acquisitions or causing us to refrain from making acquisitions. Our inability to make acquisitions, or to integrate acquisitions successfully into our existing operations, may adversely impact our operations and limit our ability to increase distributions to our unitholders.

could be negatively impacted.

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

~~Our partnership agreement~~

The Partnership Agreement requires us to distribute ~~to our unitholders~~ all of our available cash ~~which excludes~~to our unitholders (excluding prudent operating ~~reserves.~~reserves). We expect that we will rely primarily upon cash generated by operating activities and, where necessary, borrowings under ~~our revolving credit facility~~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 ~~externally,~~through external sources, our ability to maintain or increase the level of distributions toon our ~~unitholders~~common units could be significantly impaired. In addition, because we distribute all of our available cash, ~~which excludes~~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 ~~including the Preferred Units described in Item 1 (“Business—Recent Developments”),~~and preferred units, the payment of distributions on those additional ~~units~~securities may increase the risk that we will be unable to maintain or increase our per common unit distribution level. ~~There are no limitations in~~Similarly, our ~~partnership agreement on our ability to issue additional units, including units ranking senior to the common units, subject to certain~~

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~~restrictions in our partnership agreement that will take effect when the Preferred Units are issued. Similarly, the~~ incurrence of borrowings or other debt ~~by us~~ to finance our growth strategy would ~~result in~~increase our interest expense, which in turn would ~~affect~~decrease our cash available for distribution.

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

We have a $1.1 billion revolving credit facility that matures in January 2020. In addition, we have the option to increase the amount of total commitments under the revolving credit facility by $200 million, subject to receipt of lender commitments and satisfaction of other conditions.

As of December 31, ~~2017,~~2020, we had $1.9 billion of total debt, net of amortized deferred financing costs, outstanding comprised of our Credit Agreement and Senior Notes.

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. As of December 31, 2020, we had outstanding borrowings under the Credit Agreement of ~~$782.9~~$473.8 million, ~~with a leverage ratio~~$1.1 billion of ~~4.65x,~~ borrowing base availability ~~(based on our borrowing base) of $272.1 million~~ and, subject to compliance with the applicable financial covenants, available borrowing capacity ~~under the revolving credit facility~~ of ~~$101.6~~$284.2 million. ~~Financial covenants permit a maximum leverage ratio~~

As of ~~(A)~~ ~~5.25 to 1.0 as of the end of the fiscal quarter ending~~ December 31, ~~2017 and (B) 5.00 to 1.0 thereafter. As of February 8, 2018,~~2020, we had $725.0 million and $750.0 million aggregate principal amount outstanding ~~borrowings~~on our Senior Notes 2026 and Senior Notes 2027, respectively. The Senior Notes 2026 and Senior Notes 2027 accrue interest at the rate of ~~$815.0 million.~~

6.875% per year.

Our ability to incur additional debt is also subject to limitations in ~~our revolving credit facility,~~the Credit Agreement, including certain financial covenants. As of December 31, 2020, our leverage ratio under the Credit Agreement was 5.03x. Financial covenants in the Credit Agreement permit a maximum leverage ratio of (i) 5.75 to 1.00 for the fiscal quarters ending September 30, 2020 and December 31, 2020, (ii) 5.50 to 1.00 for the fiscal quarters ending March 31, 2021 and June 30, 2021 and (iii) 5.25 to 1.00 for

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the fiscal quarters ending September 30, 2021 and December 31, 2021 (reverting back to 5.00 to 1.00 for each fiscal quarter thereafter). As of February 11, 2021, we had outstanding borrowings under the Credit Agreement of $498.2 million.

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;

•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

•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.~~

•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.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service our debt under the ~~revolving credit facility~~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 ~~movements~~changes in market interest ~~rate markets.~~rates. A substantial increase in the interest rates 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 ~~reducing~~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.

~~Restrictions in~~

The terms of the Credit Agreement and the Indentures restrict our ~~revolving credit facility~~current and future operations, particularly our ability to respond to changes or to take certain actions, may limit our ability to ~~make~~pay distributions ~~to our unitholders~~ and may limit our ability to capitalize on ~~acquisition~~acquisitions and other business opportunities.

The Credit Agreement and the Indentures contain a number of restrictive covenants that impose significant operating and financial restrictions on us and ~~covenants in our revolving credit facility and any future financing agreements could restrict~~may limit our ability to ~~finance future operations or capital needs or to expand or pursue~~engage in acts that may be in our ~~business activities. Our revolving credit facility restricts or limits~~long-term best interest, including restrictions on our ability ~~(subject~~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 ~~exceptions) to:~~

~~grant liens;~~

~~make certain loans or investments;~~

~~incur additional indebtedness or guarantee other indebtedness;~~

~~enter into transactions with affiliates;~~

pay dividends; and

•consolidate, merge or sell all or substantially all of our assets.

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~~merge or consolidate;~~

~~sell our assets; or~~

~~make certain acquisitions.~~

~~Furthermore, our revolving credit facility~~In addition, the Credit Agreement contains certain operating and financial ~~covenants.~~covenants and requires us to maintain specified financial ratios and satisfy other financial condition tests. Our ability to comply with ~~these~~those covenants and ~~restrictions may~~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 ~~economic~~ conditions deteriorate, our ability to comply with these covenants may be impaired. ~~If we violate any~~

A breach of the covenants or restrictions ~~covenants, ratios~~under the Credit Agreement or ~~other tests~~the Indentures could result in ~~our revolving credit facility,~~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 ~~such revolving credit facility,~~

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the Credit Agreement, or if we are, any subsequent replacement of ~~our revolving credit facility~~the Credit Agreement or any new indebtedness could ~~have similar~~be equally or ~~greater restrictions.~~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 financing. Please read Part II, Item 7 ~~(“Management’s~~“Management’s Discussion and Analysis of Financial Condition and Results of ~~Operations—~~Operations – Liquidity and Capital ~~Resources—Description of~~Resources – Revolving Credit ~~Facility”)~~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 our common units 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, or $97.50 per Preferred Unit per year. 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 in accordance with the terms of the Partnership Agreement by the holders of the Preferred Units or by us in certain circumstances, beginning April 2, 2021. 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 in Part II, Item 8 “Financial Statements and Supplementary Data.”

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

The operating and financial restrictions and covenants in ~~our partnership agreement~~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. ~~If the Preferred Units are issued, our partnership agreement will restrict~~The Partnership Agreement restricts or ~~limit~~limits our ability (subject to certain exceptions) to:

pay distributions on any junior securities, including the common units, prior to paying the quarterly distribution payable to the holders of the Preferred Units, including any previously accrued and unpaid distributions;

•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 or severe sudden downturn in the economic environment, such as the severe impact of the COVID-19 pandemic, could cause an ~~unlimited number of securities ranking junior to the Preferred Units, including junior preferred units and common units; and~~

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

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

We have recorded ~~$35.9~~$333.8 million of ~~goodwill and $71.7 million of other~~identifiable intangible assets, net, as of December 31, 2017. 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.2020. Any event that causes a reduction in demand for our services could result in a reduction of our estimates of future cash flows and growth rates in our business. These events could cause us to record impairments of ~~goodwill or other~~identifiable intangible assets. For the year ended December 31, 2020, we recognized a goodwill impairment of $619.4 million.

If we determine that any of our ~~goodwill or other~~identifiable intangible assets are impaired, we will be required to take an immediate charge to earnings with a corresponding reduction of partners’ capital resulting in an increase in balance sheet leverage as measured by debt to total capitalization. There was no impairment recorded for goodwill or other intangible assets for the years ended December 31, 2017 and 2016. For the year ended December 31, 2015, we recognized a $172.2 million impairment of goodwill due primarily to the decline in our unit price, the sustained decline in global commodity prices, expected reduction in the capital budgets of certain of our customers and the impact these factors have on our expected future cash flows (see Note 2 of our consolidated financial statements). There was no impairment recorded for other intangible assets for the year ended December 31, 2015.

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

We have a significant ~~amount~~number of long-lived assets on our consolidated balance sheet. Under GAAP, ~~long-lived assets~~we are required to ~~be reviewed~~review our long-lived assets for impairment when events or circumstances indicate that ~~its~~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~~for the ~~fiscal~~ years ended December 31, ~~2017~~2020, 2019 and ~~2016,~~2018, we evaluated the future deployment of our idle fleet under ~~then-current~~current market conditions and determined to retire 37, 33 and ~~either sell or re-utilize the key components of 40 and 29~~103 compressor units, orrespectively, for a total of approximately 15,000, 11,000 and ~~15,000~~33,000 horsepower, respectively, that were previously used to provide compression services in our business. As a result, we ~~recognized~~recorded impairments of ~~$5.0~~compression equipment of $8.1 million, $5.9 million and ~~$5.8~~$8.7 million ~~during~~for the years ended December 31, ~~2017~~2020, 2019 and ~~2016,~~2018, respectively.

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. The~~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 ~~good,~~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 ~~S&R,~~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 ~~units.~~

compression units to us.

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 ETO in connection therewith, but there may be unknown and contingent liabilities of which we are currently unaware. ETO 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, and certain of ETO’s indemnification obligations lapsed in late 2019. 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.

Risks Related to Governmental Legislation and Regulation

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

We are subject to stringent and complex federal, state and local laws and regulations, including laws and regulations regarding the discharge of materials into the environment, ~~emission~~emissions controls and other environmental protection and occupational health and safety concerns, as discussed in detail in Item 1 ~~(“Business~~“Business – Our Operations – Environmental and

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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

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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 ~~emission~~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 inunder various permits or other authorizations. We could be subject to penalties for any noncompliance in the future.

Additionally, some states have also passed legislation or regulations regarding hydraulic fracturing. For example, in 2019, Colorado passed Senate Bill 181, which delegates authority to local governments to regulate oil and gas activities and requires the Colorado Oil and Gas Conservation Commission to minimize emissions of methane and other air contaminants. Some local communities have adopted additional restrictions for oil and gas activities, such as requiring greater setbacks, and some groups are petitioning local governments to ban hydraulic fracturing. If additional regulatory measures are adopted that ban or restrict production of natural gas through hydraulic fracturing, our customers could experience delays, limitations, or prohibitions on their activities. Such delays, limitations, or prohibitions could result in decreased demand for our services.

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~~“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 (“ppb”).~~billion. In December 2020, the EPA announced its decision to retain, without changes, the 2015 NAAQS. After the EPA revises a NAAQS standard, the states are expected to establish revised attainment/non-attainment regions. State implementation of the ~~revised~~2015 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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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 ~~these~~ methane gas and ~~volatile organic compound~~VOC emissions. These Subpart OOOOa standards ~~will expand~~would have expanded 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

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stations. However, in September 2020, the EPA ~~announced in April 2017~~issued a final rule that ~~it intends to reconsider certain aspects of~~removed the transmission and storage segment from the 2016 New Source Performance Standards, rescinded VOCs and ~~in May 2017,~~methane emissions standards for the transmission and storage segment, and rescinded methane emissions standards for the production and processing segments. Various states and industry and environmental groups are separately challenging the EPA’s 2016 standards and its September 2020 final rule. Notwithstanding the current court challenges, on January 20, 2021, President Biden issued an executive order directing the EPA ~~issued an administrative stay of key provisions of~~to consider publishing for notice and comment a proposed rule suspending, revising, or rescinding the September 2020 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~~which could result 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.~~

~~If implemented, Subpart OOOOa and any~~more stringent methane emission rulemaking.

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

costs and restrictions on our customers’ operations.

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.~~gases (“GHGs”). In recent years, the U.S. Congress has considered legislation to reduce ~~emissions of greenhouse gases. It presently appears unlikely~~GHG emissions. President Biden could seek to pursue legislative, regulatory or executive initiatives that ~~comprehensive climate legislation will be passed by either house of Congress in the near future, although~~restrict GHG emissions. Other energy legislation and ~~other~~ initiatives ~~are expected~~could include a carbon tax or cap and trade program. Independent of Congress, and as discussed in detail in Item 1 “Business – Our Operations – Environmental and Safety Regulations”, the EPA has taken to ~~be proposed that may be relevant to greenhouse gas~~adopt regulations controlling GHG emissions ~~issues. However, almost half of the~~under its existing CAA authority. Further, although Congress has not passed such legislation, many states have begun to address ~~greenhouse gas~~GHG emissions, primarily through the planned development of ~~emission~~emissions inventories or regional ~~greenhouse gas~~GHG cap and trade programs. Depending on the particular program, we could be required to control ~~greenhouse gas~~GHG emissions or to purchase and surrender allowances for ~~greenhouse gas~~GHG emissions resulting from our operations.

~~Independent~~

Federal and possibly state governments may impose significant restrictions on fossil-fuel exploration, production and use such as limitations or bans on hydraulic fracturing of ~~Congress,~~oil and ~~as discussed in detail in Item 1 (“Business Environmental~~gas wells, bans or restrictions on new leases for production of minerals on federal properties, and ~~Safety Regulations”), the EPA undertook to adopt regulations controlling greenhouse gas emissions under its existing CAA authority.~~imposing restrictive requirements on new pipeline infrastructure or fossil-fuel export facilities. For example, ~~in 2015,~~on January 27, 2021, President Biden issued an executive order directing the EPA published standards of performance for greenhouse gas emissions from new power plants. The final rule establishes a performance standard for integrated gasification combined cycled units and utility boilers based on the useSecretary of the ~~best system~~Interior to pause approval of emission reduction that 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, 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 Clean Power Plan, which will remain in effect throughout the pendency of the appeals process including at the United States Court of Appeals of 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. Additionally, in October 2017 EPA proposed to repeal the CPP, although the final outcome of this action and the pending litigation regarding the CPP is uncertain at this time. In connection with the proposed repeal, EPA issued an Advance Notice of Proposed Rulemaking (“ANPRM”) in December 2017 regarding emission guidelines to limit GHG emissions from existing electricity utility generating units. The ANPRM seeks comment regarding what the EPA should include in a potential new existing-source regulation under the Clean Air Act of GHG emissions from electric utility generating units that it may propose. If the effort to repeal the rules is unsuccessful and the rules are upheld at the conclusion of this appellate process and enforced in their current form, or if the ANPRM results in a different proposal to control GHG emissions from electric utility generating units, demand for the oil and natural gas ~~our customers produce may decrease.~~

leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. Litigation risks are also increasing, as a number of cities, local governments and other plaintiffs have sued companies engaged in the exploration and production of fossil fuels in state and federal courts, alleging various legal theories to recover for the impacts of alleged global warming effects, such as rising sea levels. Many of these suits allege that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts. Although a number of these lawsuits have been dismissed, others remain pending and the outcome of these cases remains difficult to predict.

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.

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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

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under pressure into the rock formation to stimulate gas production. ~~Legislation to amend the Safe Drinking Water Act (“SDWA”) to repeal the exemption for~~Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure or waste restrictions that may restrict or prohibit hydraulic ~~fracturing from the definition~~fracturing. In addition, members 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~~are and a number of federal agencies historically have been requested to ~~consider legislation~~review, and under the Biden administration, may be requested to ~~amend the SDWA. Scrutiny~~review again, a variety 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” activitiesissues associated with hydraulic fracturing, which may ~~impact drinking water resources “under some circumstances,” noting that the following~~lead to new or more strict regulation. Any new laws or regulations regarding hydraulic fracturing ~~water cycle activities and local- or regional-scale factors are more likely than others~~could negatively impact our customers’ ability 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.

produce natural gas, which could adversely impact our revenue.

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 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~~U.S. 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.

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

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

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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 certain types of insurance 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 as a result of terrorism or war could also affect our ability to raise capital.

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

In connection with the closing of our initial public offering, we became subject to the public reporting requirements of the Exchange Act. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. We continue to 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, among other things, to review and report annually on the effectiveness of our internal control over financial reporting. We were required to comply with Section 404(a) beginning with our fiscal year ended December 31, 2013. In addition, our independent registered public accountants will be required to assess the effectiveness of internal control over financial reporting at the end of the fiscal year after we are no longer an “emerging growth company” under the Jumpstart Our Business Startups Act, which will occur at the end of 2018. 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 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 units.

Risks Inherent in an Investment in Us

Holders of our common units have limited voting rights and are not entitled to elect ~~our general partner~~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. ~~Unitholders~~Common unitholders have no right to elect ~~our general partner~~the General Partner or ~~its~~the board of ~~directors. USA Compression Holdings~~directors of the General Partner (the “Board”). ETO is the sole member of ~~our general partner~~the General Partner and has the right to appoint ~~our general partner’s entire board~~the majority of ~~directors,~~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, ET LP 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 ~~the~~our common unitholders are dissatisfied with the General Partner’s performance, ~~of our general partner,~~ they have little ability to remove the General Partner. Common unitholders are currently unable to remove the General Partner because the General Partner and its affiliates own sufficient number of our ~~general partner.~~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. As a result of these limitations, the price of our common units may ~~be diminished~~decline because of the absence or reduction of a takeover premium in the trading price.

Furthermore, ~~our partnership agreement also~~the Partnership Agreement contains provisions limiting the ability of common unitholders to call meetings or to ~~acquire~~obtain information about our operations, as well as other provisions limiting ~~the~~our common unitholders’ ability to influence the manner or direction of management. ~~If the GP Purchase is completed, all of the risks relative to USA Compression Holdings in this paragraph will subsequently apply to the Energy Transfer Parties.~~

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~~The owner of our general partner~~ETO owns and controls the General Partner, and the General Partner has sole responsibility for conducting our business and managing our operations. ~~Our general partner~~The General Partner and its affiliates, including ~~the owner thereof,~~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.

~~USA Compression Holdings, which is principally owned and controlled by Riverstone,~~

ETO owns and controls ~~our general partner~~the General Partner and ~~appointed~~appoints all of the officers and a majority of the directors of ~~our general partner,~~the General Partner, some of whom are also officers and directors of ~~USA Compression Holdings.~~ETO. Although ~~our general partner~~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 ~~our general partner~~the General Partner also have a fiduciary duty to manage ~~our general partner~~the General Partner in a manner that is beneficial to its owner. Conflicts of interest will arise between ~~our general partner~~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, ~~our general partner~~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 our partnership agreement nor any other agreement requires the owner of our general partner to pursue a business strategy that favors us;~~

~~our general partner is allowed to take into account the interests of parties other than us, such as its owner, in resolving conflicts of interest;~~

our partnership agreement limits the liability of and reduces the fiduciary duties owed by our 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, our general partner has the power and authority to conduct our business without unitholder approval;~~

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

our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a 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 and to our general partner;

~~our general partner determines which costs incurred by it are reimbursable by us;~~

~~our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if~~ ~~the purpose or effect of the borrowing is to make incentive distributions;~~

our partnership agreement permits us to classify up to $36.6 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions as operating surplus from non-operating sources to our general partner in respect of its General Partner Interest (as defined under Part II, Item 5 (“Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities”) or the incentive distribution rights (or “IDRs”);

our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

~~our general partner intends to limit its liability regarding our contractual and other obligations;~~

•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;

~~Table~~•the General Partner is allowed to take into account the interests of ~~Contents~~

parties other than us, such as its owner, in resolving conflicts of interest;

~~our general partner may exercise its right to call and purchase all of~~•the Partnership Agreement limits the ~~common units not owned by it and its affiliates if they own more than 80% of the common units;~~

~~our general partner controls the enforcement of the obligations that it and its affiliates owe to us;~~

~~our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and~~

our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to the IDRs without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

~~Our general partner’s~~ liability ~~regarding~~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;

•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.

~~Our general partner~~

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 ~~our general partner~~the General Partner or its assets. ~~Our general partner~~The General Partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to ~~our general partner. Our partnership agreement~~it. The Partnership Agreement provides that any action taken by ~~our general partner~~the General Partner to limit its liability is not a breach of ~~our general partner’s~~the General Partner’s fiduciary duties, even if we could have obtained more favorable terms without ~~the~~such limitation on liability. In addition, we are obligated to reimburse or indemnify ~~our general partner~~the General Partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce ~~the~~our amount of cash otherwise available for distribution.

~~Our partnership agreement~~

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

~~Our partnership agreement~~

The Partnership Agreement contains provisions that modify and reduce the fiduciary standards to which ~~our general partner~~the General Partner would otherwise be held by state fiduciary duty law. For example, ~~our partnership agreement~~the Partnership Agreement permits ~~our general partner~~the General Partner to make a number of decisions in its individual capacity, as opposed to its capacity as ~~our general partner,~~the General Partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles ~~our general partner~~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 ~~our general partner~~the General Partner may make in its individual capacity include:

~~how to allocate business opportunities among us and its affiliates;~~

•how to allocate business opportunities among us and its affiliates;

~~whether to exercise its limited call right;~~

•whether to exercise its limited call right;

~~how to exercise its voting rights with respect to the units it owns;~~

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

~~whether to elect to reset target distribution levels; and~~

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

~~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 inof the ~~partnership agreement,~~Partnership Agreement, including the provisions discussed above.

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

The unitholders are currently unable to remove our general partner because our general partner and its affiliates own sufficient units to be able to prevent its removal. The vote of the holders of at least 662/3~~% of all outstanding common units is required to remove our general partner. USA Compression Holdings currently owns over 33~~1/3~~% of our~~

~~Table of Contents~~

outstanding common units and, after giving effect to the CDM Acquisition and the other transactions described in Item 1 (“Business—Recent Developments”), the Energy Transfer Parties will own over 331/3~~% of our outstanding common units.~~

~~Our partnership agreement~~Partnership Agreement restricts the remedies available to ~~holders of~~ our ~~common units~~unitholders for actions taken by ~~our general partner~~the General Partner that might otherwise constitute breaches of fiduciary duty.

~~Our partnership agreement~~

The Partnership Agreement contains provisions that restrict the remedies available to unitholders for actions taken by ~~our general partner~~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 ~~partnership agreement:~~

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 whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any higher standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

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

•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:

provides that our 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 our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

•approved by the conflicts committee of the Board, although the General Partner is not obligated to seek such approval;

provides that our 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:

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

~~(a)~~

~~approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;~~

•on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

~~(b)~~

~~approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;~~

•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.

~~(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 ~~connection with~~ a situation involving a transaction with an affiliate or a conflict of interest, any determination by ~~our general partner~~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 of directors of our general partner~~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) and (d)~~the last two bullets above, then it will conclusively be deemed that, in making its decision, the ~~board of directors of our general partner~~Board acted in good faith.

~~USA Compression Holdings, Argonaut~~ETO and the ~~Energy Transfer Parties~~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 ~~the~~our common units.

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

ITEM 4.Mine Safety Disclosures

None.

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~~None.~~

PART II

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

Our Partnership Interests

As of February ~~8, 2018,~~11, 2021, we had ~~outstanding 62,194,405~~96,996,304 common units ~~a 1.2% general partner interest (“~~outstanding. ETO owns 100% of the membership interests in the General Partner ~~Interest”)~~ and, ~~the IDRs. USA Compression Holdings owns a 100% membership interest in our general partner. As~~as of February ~~8, 2018, USA Compression Holdings owned~~11, 2021, beneficially owns approximately ~~40%~~47% of our outstanding common units. ~~Our general~~

As of February 11, 2021, we had outstanding 500,000 Preferred Units representing limited partner ~~currently owns~~interests in the ~~General Partner Interest in us and~~Partnership, all of which were held by Preferred Unitholders. The Preferred Units rank senior to the ~~IDRs. As discussed below under “Selected Information from Our~~common units with respect to distributions and rights upon liquidation. The Preferred Unitholders are entitled to receive cumulative quarterly cash distributions equal to $24.375 per Preferred Unit.

The Preferred Units are convertible, at the option of the Preferred Unitholders, into common units in accordance with the terms of the Partnership ~~Agreement—General Partner Interest~~Agreement as follows: one third on or after April 2, 2021, two thirds on or after April 2, 2022, and ~~IDRs,”~~ the ~~IDRs represent~~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 ~~receive increasing percentages,~~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 ~~a maximum of 48%, of the cash we distribute from operating surplus (as defined below)~~50% in ~~excess of $0.4888 per unit per quarter.~~ 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.”

The following table sets forth high and low sales prices per common unit and cash distributions per common unit to common unitholders for the periods indicated. The last reported sales price for our common units on February 8, 2018, was $17.47.

Cash



Distribution

Price Range

Declared Per

Period

High

Low

Common Unit

Date Paid

First Quarter 2016

$
11.89

$
7.03

$
0.525

May 13, 2016

Second Quarter 2016

$
16.42

$
10.50

$
0.525

August 12, 2016

Third Quarter 2016

$
18.90

$
14.02

$
0.525

November 14, 2016

Fourth Quarter 2016

$
19.33

$
15.41

$
0.525

February 14, 2017

First Quarter 2017

$
19.78

$
16.13

$
0.525

May 12, 2017

Second Quarter 2017

$
17.85

$
14.30

$
0.525

August 11, 2017

Third Quarter 2017

$
17.84

$
14.55

$
0.525

November 10, 2017

Fourth Quarter 2017

$
17.64

$
15.48

$
0.525

February 14, 2018

Holders

~~Holders~~

At the close of business on February ~~8, 2018,~~11, 2021, based on information received from the transfer agent of the common units, we had 5470 holders of record of our common units. The number of record holders does not include holders of common units held in “street ~~names”~~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 – Note 12 – Partners’ Capital”.

Selected Information from ~~our~~the Partnership Agreement

Set forth below is a summary of the significant provisions of ~~our partnership agreement~~the Partnership Agreement that relate to available ~~cash and the General Partner Interest and the IDRs.~~

cash.

Available Cash

~~Our partnership agreement~~

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. Our partnership agreement~~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

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borrowings made after the end of the quarter less the amount of reserves established by ~~our general partner~~the General Partner to provide for the proper conduct of our business, comply with applicable law, ~~our revolving credit facility~~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.

~~General Partner Interest and IDRs~~

Our partnership agreement provides that our general partner is entitled to its General Partner Interest of all distributions that we make. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its General Partner Interest if we issue additional units. Our general partner’s General Partner Interest, and the percentage of our cash distributions to which it is entitled, will be proportionately reduced if we issue additional units in the future (other than the issuance of common units upon a reset of the IDRs) and our general partner does not contribute a proportionate amount of capital to us in order to maintain its General Partner Interest. Our partnership agreement does not require that our general partner fund its capital contribution with cash and our general partner may fund its capital contribution by the contribution to us of common units or other property.

The IDRs represent the right to receive increasing percentages (13.0%, 23.0% and 48.0%) of quarterly distributions of available cash from operating surplus after the target distribution levels have been achieved. Our general partner currently holds the IDRs, but may transfer these rights separately from its General Partner Interest without the consent of our limited partners.

On January 15, 2018, our general partner entered into an agreement pursuant to which it agreed to, among other things, convert the General Partner Interest into a non-economic general partner interest and cancel the IDRs. The transactions are expected to close in the first half of 2018. See Item 1 (“Business—Recent Developments”) for more information.

Issuer Purchases of Equity Securities

None.

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

None.

Equity Compensation Plan

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

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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, ~~2017,~~2020, which has been derived from our audited consolidated financial ~~statements.~~statements for the years ended December 31, 2020, 2019, 2018, 2017 and 2016. USA Compression Predecessor has been determined to be the historical predecessor of the Partnership for financial reporting purposes because ET LP controlled the USA Compression Predecessor prior to the CDM Acquisition and obtained control of the Partnership through its acquisition of the General Partner. 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~~Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of ~~Operations~~Operations” and ~~the Financial Statements contained in~~ Part II, Item 7.

8 “Financial Statements and Supplementary Data”.

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~~“Management’s Discussion and Analysis of Financial Condition and Results of

~~Table of Contents~~

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~~“Risk Factors”) of this report. Additionally, Note 2 – ~~Summary~~Basis of Presentation and Significant Accounting Policies and Note 1317 – Commitments and Contingencies under Part II, Item 8 ~~(“Financial~~“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 ~~measure~~measures of Adjusted gross ~~operating~~ margin, Adjusted EBITDA and Distributable Cash Flow (or “DCF”). For definitions of Adjusted gross ~~operating~~ margin, Adjusted EBITDA and DCF, and

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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.

Year Ended December 31,

2017

2016

2015

2014

2013

(in thousands, except per unit amounts)

Revenues:

Contract operations

$
264,315

$
246,950

$
263,816

$
217,361

$
150,360

Parts and service

15,907

18,971

6,729

4,148

2,558

Total revenues

280,222

265,921

270,545

221,509

152,918

Costs of operations, exclusive of depreciation and amortization:

Cost of operations

92,591

88,161

81,539

74,035

48,097

Gross operating margin (1)

187,631

177,760

189,006

147,474

104,821

Other operating and administrative costs and expenses:

Selling, general and administrative

47,483

44,483

40,950

38,718

27,587

Depreciation and amortization

98,603

92,337

85,238

71,156

52,917

Loss (gain) on disposition of assets

(507)

772

(1,040)

(2,233)

284

Impairment of compression equipment

4,972

5,760

27,274

2,266

203

Impairment of goodwill

—

—

172,189

—

—

Total other operating and administrative costs and expenses

150,551

143,352

324,611

109,907

80,991

Operating income (loss)

37,080

34,408

(135,605)

37,567

23,830

Other income (expense):

Interest expense, net

(25,129)

(21,087)

(17,605)

(12,529)

(12,488)

Other

27

35

22

11

9

Total other expense

(25,102)

(21,052)

(17,583)

(12,518)

(12,479)

Income (loss) before income tax expense

11,978

13,356

(153,188)

25,049

11,351

Income tax expense

538

421

1,085

103

280

Net income (loss)

11,440

12,935

(154,273)

24,946

11,071

Adjusted EBITDA (1)

$
155,703

$
146,648

$
153,572

$
114,409

$
81,130

DCF (1)

$
118,330

$
118,329

$
120,850

$
85,927

$
56,210

Basic and diluted net income (loss) per common unit:

$
0.16

$
0.27

$
(3.15)

$
0.60

$
0.32

Cash distributions declared per common unit

$
2.10

$
2.10

$
2.09

$
2.01

$
1.73

Other Financial Data:

Capital expenditures

$
129,490

$
48,665

$
265,798

$
404,429

$
175,393

Cash flows provided by (used in):

Operating activities

$
124,644

$
103,697

$
117,401

$
101,891

$
68,190

Investing activities

$
(105,231)

$
(50,831)

$
(278,158)

$
(380,523)

$
(153,946)

Financing activities

$
(19,431)

$
(52,808)

$
160,758

$
278,631

$
85,756

Balance Sheet Data (at period end):

Working capital (2)

$
3,118

$
16,558

$
(8,455)

$
(44,064)

$
(24,177)

Total assets

$
1,492,087

$
1,472,412

$
1,509,771

$
1,516,482

$
1,185,884

Long-term debt

$
782,902

$
685,371

$
729,187

$
594,864

$
420,933

Partners' equity

$
633,853

$
729,517

$
718,288

$
839,520

$
707,727

~~(1)~~

~~Please refer to “—Non-GAAP Financial Measures” section below.~~

~~(2)~~

~~Working capital is defined as current assets minus current liabilities.~~

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Year Ended December 31,
2020 2019 2018 2017 2016
(in thousands, except per unit amounts)
Revenues:
Contract operations $ 644,194 $ 664,162 $ 546,896 $ 249,346 $ 239,143
Parts and service 11,117 14,236 20,402 10,085 7,921
Related party 12,372 19,967 17,054 17,240 16,873
Total revenues 667,683 698,365 584,352 276,671 263,937
Costs and expenses:
Costs of operations, exclusive of depreciation and amortization 205,939 227,303 214,724 125,204 112,898
Depreciation and amortization 238,968 231,447 213,692 166,558 155,134
Selling, general and administrative 59,981 64,397 68,995 24,944 22,739
Loss (gain) on disposition of assets 146 940 12,964 (367) 120
Impairment of compression equipment 8,090 5,894 8,666 — —
Impairment of goodwill 619,411 — — 223,000 —
Total costs and expenses 1,132,535 529,981 519,041 539,339 290,891
Operating income (loss) (464,852) 168,384 65,311 (262,668) (26,954)
Other income (expense):
Interest expense, net (128,633) (127,146) (78,377) — —
Other 86 80 41 (223) (153)
Total other expense (128,547) (127,066) (78,336) (223) (153)
Net income (loss) before income tax expense (benefit) (593,399) 41,318 (13,025) (262,891) (27,107)
Income tax expense (benefit) 1,333 2,186 (2,474) 1,843 (163)
Net income (loss) (594,732) 39,132 (10,551) $ (264,734) $ (26,944)
Less: distributions on Preferred Units (48,750) (48,750) (36,430)
Net loss attributable to common and Class B unitholders’ interests (1) $ (643,482) $ (9,618) $ (46,981)
Basic and diluted net loss per common unit (1) $ (6.65) $ (0.02) $ (0.43)
Basic and diluted net loss per Class B Unit (1) $ — $ (2.13) $ (2.33)
Cash distributions declared per common unit (1) $ 2.10 $ 2.10 $ 1.575
Other financial data:
Gross margin $ 222,776 $ 239,615 $ 155,936 $ (15,091) $ (4,095)
Adjusted gross margin (2) $ 461,744 $ 471,062 $ 369,628 $ 151,467 $ 151,039
Adjusted EBITDA (2) $ 413,898 $ 419,640 $ 320,475 $ 130,348 $ 131,686
DCF (2) $ 220,766 $ 221,868 $ 177,757 $ 109,326 $ 123,442
Capital expenditures $ 118,856 $ 199,928 $ 241,179 $ 175,508 $ 59,234
Cash flows provided by (used in):
Operating activities $ 293,198 $ 300,580 $ 226,340 $ 135,956 $ 130,063
Investing activities $ (105,099) $ (144,490) $ (779,663) $ (142,458) $ (36,767)
Financing activities $ (188,107) $ (156,179) $ 549,409 $ (3,666) $ (90,367)
Balance sheet data (at period end):
Working capital (3) $ 29,283 $ 41,548 $ 68,141 $ 27,091 $ 62,424
Total assets $ 2,948,700 $ 3,730,407 $ 3,774,649 $ 1,718,953 $ 1,960,416
Long-term debt, net $ 1,927,005 $ 1,852,360 $ 1,759,058 $ — $ —
Partners’ capital and predecessor parent company net investment $ 337,655 $ 1,180,598 $ 1,378,856 $ 1,664,870 $ 1,929,223

________________________

(1)Net loss attributable to common and Class B unitholders’ interests and net loss per unit are not applicable to the USA Compression Predecessor as the USA Compression Predecessor had no outstanding common or Class B units prior to the Transactions. On July 30, 2019, 6,397,965 Class B Units automatically converted into common units on a one-for-one basis, resulting in the issuance of 6,397,965 common units to ETO. Following the conversion, there are no longer Class B Units outstanding.

(2)Please refer to “Non-GAAP Financial Measures” below.

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

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Non-GAAP Financial Measures

Adjusted Gross ~~Operating~~ Margin

~~The table above includes~~

Adjusted 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 Adjusted gross ~~operating~~ margin as revenue less cost of operations, exclusive of depreciation and amortization expense. We believe that Adjusted gross ~~operating~~ margin is useful as a supplemental measure to investors of our operating profitability. ~~Gross operating~~Adjusted gross 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~~Adjusted gross margin should not be considered an alternative to, or more meaningful than, ~~operating income (loss)~~gross margin or any other measure of financial performance presented in accordance with GAAP. Moreover, Adjusted 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 Adjusted gross ~~operating~~ margin as a measure of our performance, we believe that it is important to consider ~~operating income (loss)~~gross margin determined under GAAP, as well as Adjusted gross ~~operating~~ margin, to evaluate our operating profitability.

The following table reconciles Adjusted gross margin to gross margin, its most directly comparable GAAP financial measure, for each of the periods presented (in thousands):


	Year Ended December 31,
	2020		2019		2018		2017		2016
Total revenues	$	667,683	$	698,365	$	584,352	$	276,671	$	263,937
Cost of operations, exclusive of depreciation and amortization	(205,939)		(227,303)		(214,724)		(125,204)		(112,898)
Depreciation and amortization	(238,968)		(231,447)		(213,692)		(166,558)		(155,134)
Gross margin	$	222,776	$	239,615	$	155,936	$	(15,091)	$	(4,095)
Depreciation and amortization	238,968		231,447		213,692		166,558		155,134
Adjusted gross margin	$	461,744	$	471,062	$	369,628	$	151,467	$	151,039

Adjusted EBITDA

We define EBITDA as net income (loss) before net interest expense, depreciation and amortization expense, and income tax ~~expense.~~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, ~~management fees,~~ severance charges, certain transaction ~~fees,~~expenses, loss (gain) on disposition of assets and other. We view Adjusted EBITDA as one of management’s primary tools for evaluating our ~~primary management tools,~~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 to 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 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 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~~

•the ability of our assets to generate cash sufficient to make debt payments and to pay 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.~~

•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 ~~provides~~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, loss (gain) on disposition of assets and the interest cost of acquiring compression equipment are also necessary elements of our costs. ~~Expense~~Unit-based compensation

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expense related to ~~unit-based compensation expense associated with~~ equity awards to employees is also a necessary component of our business. Therefore, measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income (loss) and net cash provided by operating activities determined under GAAP, as well as

~~Table of Contents~~

Adjusted EBITDA, to evaluate 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 comparable GAAP measures, understanding the differences between the measures and incorporating this knowledge into ~~management’s~~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,


2017

2016

2015

2014

2013
Net income (loss)

$
11,440

$
12,935

$
(154,273)

$
24,946

$
11,071
Interest expense, net

25,129

21,087

17,605

12,529

12,488
Depreciation and amortization

98,603

92,337

85,238

71,156

52,917
Income tax expense

538

421

1,085

103

280
EBITDA

$
135,710

$
126,780

$
(50,345)

$
108,734

$
76,756
Impairment of compression equipment (1)

4,972

5,760

27,274

2,266

203
Impairment of goodwill (2)

—

—

172,189

—

—
Interest income on capital lease

1,610

1,492

1,631

1,274

—
Unit-based compensation expense (3)

11,708

10,373

3,863

3,034

1,343
Riverstone management fee (4)

—

—

—

—

49
Transaction expenses for acquisitions (5)

1,406

894

—

1,299

2,142
Severance charges

314

577

—

—

—
Other

490

—

—

—

—
Loss (gain) on disposition of assets and other

(507)

772

(1,040)

(2,198)

637
Adjusted EBITDA

$
155,703

$
146,648

$
153,572

$
114,409

$
81,130
Interest expense, net

(25,129)

(21,087)

(17,605)

(12,529)

(12,488)
Income tax expense

(538)

(421)

(1,085)

(103)

(280)
Interest income on capital lease

(1,610)

(1,492)

(1,631)

(1,274)

—
Non-cash interest expense and other

2,186

2,108

1,702

1,189

1,839
Riverstone management fee

—

—

—

—

(49)
Transaction expenses for acquisitions

(1,406)

(894)

—

(1,299)

(2,142)
Severance charges

(314)

(577)

—

—

—
Other

(490)

—

—

—

—
Changes in operating assets and liabilities

(3,758)

(20,588)

(17,552)

1,498

180
Net cash provided by operating activities

$
124,644

$
103,697

$
117,401

$
101,891

$
68,190


	Year Ended December 31,
	2020		2019		2018		2017		2016
Net income (loss)	$	(594,732)	$	39,132	$	(10,551)	$	(264,734)	$	(26,944)
Interest expense, net	128,633		127,146		78,377		—		—
Depreciation and amortization	238,968		231,447		213,692		166,558		155,134
Income tax expense (benefit)	1,333		2,186		(2,474)		1,843		(163)
EBITDA	$	(225,798)	$	399,911	$	279,044	$	(96,333)	$	128,027
Interest income on capital lease	383		672		709		—		—
Unit-based compensation expense (1)	8,400		10,814		11,740		4,048		3,539
Transaction expenses (2)	136		578		4,181		—		—
Severance charges	3,130		831		3,171		—		—
Loss (gain) on disposition of assets	146		940		12,964		(367)		120
Impairment of compression equipment (3)	8,090		5,894		8,666		—		—
Impairment of goodwill (4)	619,411		—		—		223,000		—
Adjusted EBITDA	$	413,898	$	419,640	$	320,475	$	130,348	$	131,686
Interest expense, net	(128,633)		(127,146)		(78,377)		—		—
Non-cash interest expense	8,402		7,607		5,080		—		—
Income tax (expense) benefit	(1,333)		(2,186)		2,474		(1,843)		163
Interest income on capital lease	(383)		(672)		(709)		—		—
Transaction expenses	(136)		(578)		(4,181)		—		—
Severance charges	(3,130)		(831)		(3,171)		—		—
Other	4,230		2,426		(2,030)		24		(748)
Changes in operating assets and liabilities	283		2,320		(13,221)		7,427		(1,038)
Net cash provided by operating activities	$	293,198	$	300,580	$	226,340	$	135,956	$	130,063

~~(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 we recognized for the year ended December 31, 2015, please refer to Item 7 (“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Goodwill Impairment Assessments”).

(1)For the years ended December 31, 2020,2019 and 2018, unit-based compensation expense included $3.2 million, $2.5 million and $1.3 millionof cash payments related to quarterly payments of DERs on outstanding phantom unit awards, respectively, and $0.5 million, $0.6 million and $3.7 million related to the cash portion of any settlement of phantom unit awards upon vesting, respectively. The remainder of the unit-based compensation expense for all periods was related to non-cash adjustments to the unit-based compensation liability.

~~(3)~~

For the years ended December 31, 2017, 2016, 2015, 2014 and 2013, unit-based compensation expense included $2.5 million, $2.8 million, $0.9 million, $0.5 million and $0, respectively, of cash payments related to quarterly payments of distribution equivalent rights on outstanding phantom unit awards and $0.4 million, $0.1 million, $0.2 million, $0.3 million and $0, respectively, related to the cash portion of any settlement of phantom unit awards upon vesting. The remainder of the unit-based compensation expense for 2017, 2016, 2015 and 2014 is related to non-cash adjustments to the unit-based compensation liability, and for 2013 is related to the non-cash amortization of unit-based compensation in equity.

(2)Represents certain expenses related to potential and completed transactions and other items. We believe it is useful to investors to exclude these expenses.

~~(4)~~

Represents management fees paid to Riverstone for services performed during 2013. We are no longer responsible for these fees following the closing of our initial public offering in January 2013. As such, we believe it is useful to investors to view our results excluding these fees.

(3)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.

~~(5)~~

~~Represents certain transaction expenses related to potential acquisitions and other items. We believe it is useful to investors to exclude these fees.~~

(4)For further discussion of our goodwill impairment recorded for the year ended December 31, 2020, see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates – Goodwill – Impairment Assessments”.

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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,

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certain transaction ~~fees,~~expenses, severance charges, loss (gain) on disposition of assets, proceeds from insurance recovery and other, less distributions on Preferred Units and maintenance capital expenditures.

We believe DCF is an important measure of operating performance because it allows management, investors and others to compare basic cash flows we generate ~~(prior~~(after distributions on the Preferred Units but prior to any retained cash reserves established by ~~our general partner~~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, loss (gain) ~~loss~~ on disposition of assets, the interest cost of acquiring compression equipment and maintenance capital expenditures are necessary elements of our costs. ~~Expense~~Unit-based compensation expense related to ~~unit-based compensation expense associated with~~ equity awards to employees is also a necessary component of our business. Therefore, measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it 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 ~~management’s~~their decision making processes.

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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,


2017

2016

2015

2014

2013
Net income (loss)

$
11,440

$
12,935

$
(154,273)

$
24,946

$
11,071
Plus: Non-cash interest expense

2,186

2,108

1,702

1,224

2,201
Plus: Non-cash income tax expense

278

239

874

—

—
Plus: Depreciation and amortization

98,603

92,337

85,238

71,156

52,917
Plus: Unit-based compensation expense (1)

11,708

10,373

3,863

3,034

1,343
Plus: Impairment of compression equipment

4,972

5,760

27,274

2,266

203
Plus: Impairment of goodwill

—

—

172,189

—

—
Plus: Transaction expenses for acquisitions (2)

1,406

894

—

1,299

2,142
Plus: Severance charges

314

577

—

—

—
Plus: Other

490

—

—

—

—
Plus: Loss (gain) on disposition of assets and other

(507)

772

(1,040)

(2,198)

637
Plus: Proceeds from insurance recovery

—

73

1,157

—

—
Less: Maintenance capital expenditures (3)

(12,560)

(7,739)

(16,134)

(15,800)

(14,304)
DCF

$
118,330

$
118,329

$
120,850

$
85,927

$
56,210
Plus: Maintenance capital expenditures

12,560

7,739

16,134

15,800

14,304
Plus: Change in working capital

(3,758)

(20,588)

(17,552)

1,498

180
Less: Transaction expenses for acquisitions

(1,406)

(894)

—

(1,299)

(2,142)
Less: Other

(1,082)

(889)

(2,031)

(35)

(362)
Net cash provided by operating activities

$
124,644

$
103,697

$
117,401

$
101,891

$
68,190


	Year Ended December 31,
	2020		2019		2018		2017		2016
Net income (loss)	$	(594,732)	$	39,132	$	(10,551)	$	(264,734)	$	(26,944)
Non-cash interest expense	8,402		7,607		5,080		—		—
Depreciation and amortization	238,968		231,447		213,692		166,558		155,134
Non-cash income tax expense (benefit)	530		1,376		(2,663)		1,801		(155)
Unit-based compensation expense (1)	8,400		10,814		11,740		4,048		3,539
Transaction expenses (2)	136		578		4,181		—		—
Severance charges	3,130		831		3,171		—		—
Loss (gain) on disposition of assets	146		940		12,964		(367)		120
Impairment of compression equipment (3)	8,090		5,894		8,666		—		—
Impairment of goodwill (4)	619,411		—		—		223,000		—
Distributions on Preferred Units	(48,750)		(48,750)		(36,430)		—		—
Proceeds from insurance recovery	336		1,591		409		—		—
Maintenance capital expenditures (5)	(23,301)		(29,592)		(32,502)		(20,980)		(8,252)
DCF	$	220,766	$	221,868	$	177,757	$	109,326	$	123,442
Maintenance capital expenditures	23,301		29,592		32,502		20,980		8,252
Transaction expenses	(136)		(578)		(4,181)		—		—
Severance charges	(3,130)		(831)		(3,171)		—		—
Distributions on Preferred Units	48,750		48,750		36,430		—		—
Other	3,364		(541)		224		(1,777)		(593)
Changes in operating assets and liabilities	283		2,320		(13,221)		7,427		(1,038)
Net cash provided by operating activities	$	293,198	$	300,580	$	226,340	$	135,956	$	130,063

~~(1)~~

For the years ended December 31, 2017, 2016, 2015, 2014 and 2013, unit-based compensation expense includes $2.5 million, $2.8 million, $0.9 million, $0.5 million and $0, respectively, of cash payments related to quarterly payments of distribution equivalent rights on phantom unit awards and $0.4 million, $0.1 million, $0.2 million, $0.3 million and $0, respectively, related to the cash portion of any settlement of phantom units upon vesting. The remainder of the unit-based compensation expense for 2017, 2016, 2015 and 2014 is related to non-cash adjustments to the unit-based compensation liability, and for 2013 is related to the non-cash amortization of unit-based compensation in equity.

________________________

~~(2)~~

~~Represents certain transaction expenses related to potential acquisitions and other items. We believe it is useful to investors to exclude these fees.~~

~~(3)~~

Reflects 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, to replace partially or fully depreciated assets, or other capital expenditures that are incurred in maintaining our existing business and related operating income.

(2)Represents certain expenses related to potential and completed transactions and other items. We believe it is useful to investors to exclude these expenses.

(3)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.

(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 cash flow.

Coverage Ratios

DCF Coverage Ratio is defined as DCF ~~less cash distributions to be paid to our general partner and IDRs in respect of such period,~~ divided by distributions declared to ~~limited partner~~common unitholders in respect of such period. Cash Coverage Ratio is defined as DCF ~~less cash distributions to be paid to our general partner and IDRs in respect of such period,~~ divided by cash distributions expected to be paid to ~~limited partner~~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 ~~limited partner~~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.

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

Year Ended December 31,

2017

2016

2015

2014

2013
DCF

$
118,330

$
118,329

$
120,850

$
85,927

$
56,210
General partner interest in DCF

3,007

2,866

2,658

1,947

1,188
Pre-IPO DCF

—

—

—

—

2,323
DCF attributable to limited partner interest

$
115,323

$
115,463

$
118,192

$
83,980

$
52,699

Distributions for DCF coverage ratio (1)

$
129,657

$
115,881

$
101,266

$
85,098

$
55,961

Distributions reinvested in the DRIP (2)

16,592

24,441

55,489

52,556

36,694

Distributions for Cash Coverage Ratio (3)

$
113,065

$
91,440

$
45,777

$
32,542

$
19,267

DCF Coverage Ratio (4)

0.89

1.00

1.17

0.99

0.94

Cash Coverage Ratio (5)

1.02

1.26

2.58

2.58

2.74


	Year Ended December 31,
	2020			2019			2018 (4)			2017 (5)		2016 (5)
DCF	$	220,766		$	221,868		$	177,757		$	109,326	$	123,442

Distributions for DCF Coverage Ratio (1)	$	203,409		$	196,144		$	141,699

Distributions reinvested in the DRIP (2)	$	2,064		$	1,045		$	688

Distributions for Cash Coverage Ratio (3)	$	201,345		$	195,099		$	141,011

DCF Coverage Ratio	1.09		x	1.13		x	1.25		x

Cash Coverage Ratio	1.10		x	1.14		x	1.26		x

~~(1)~~

Represents distributions to the holders of our limited partnership units, after giving effect to the weighted average common units outstanding, due to our December 2016, September 2015 and May 2014 equity offerings and an acquisition we completed in August 2013 for the years ended December 31, 2016, 2015, 2014 and 2013, as applicable. Without giving effect to the weighted average common units outstanding due to our December 2016, September 2015 and May 2014 equity offerings and an acquisition we completed in August 2013 for the years ended December 31, 2016, 2015, 2014 and 2013, actual distributions to holders of our limited partnership units were $118.1 million, $103.1 million, $86.5 million and $58.2 million, respectively.

________________________

~~(2)~~

~~Represents distributions to holders enrolled in the DRIP as of the record date for each period.~~

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

~~(3)~~

Represents cash distributions declared for our limited partnership units not participating in the DRIP, after giving effect to the weighted average of limited partnership units outstanding for each period due to our December 2016, September 2015 and May 2014 equity offerings and an acquisition we completed in August 2013 for the years ended December 31, 2016, 2015, 2014 and 2013, as applicable.

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

~~(4)~~

For the years ended December 31, 2016, 2015, 2014 and 2013, the DCF Coverage Ratio based on actual limited partnership units outstanding as of the respective record dates was 0.98x, 1.15x, 0.97x and 0.91x, respectively.

(3)Represents cash distributions declared for common units not participating in the DRIP.

~~(5)~~

For the years ended December 31, 2016, 2015, 2014 and 2013, the Cash Coverage Ratio based on actual limited partnership units outstanding as of the respective record dates was 1.23x, 2.48x, 2.46x and 2.74x, respectively.

(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 were 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

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~~“Disclosure Regarding Forward-Looking Statements”) and Part I, Item 1A ~~(“Risk~~“Risk Factors”).

Discussion and analysis of our operating highlights and financial results of operations for the year ended December 31, 2019 compared to the year ended December 31, 2018 is included under the headings in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Operating Highlights, Financial Results of Operations, Liquidity and Capital Resources, and Critical Accounting Policies and Estimates” in our Annual Report on Form 10-K filed for the year ended December 31, 2019 with the SEC on February 18, 2020.

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. ~~The demand~~Demand for our services is driven by the domestic production of natural gas and crude ~~oil; as~~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”),~~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.~~term. 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 ~~the flexibility of our compression units positions us well~~we are well-positioned to meet these changing operating ~~conditions.~~ conditions due to the operational design flexibility inherit in our compression units.

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an existing producing well, ~~thus reducing~~in order to reduce the hydrostatic pressure and ~~allowing~~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.

Recent Developments

Credit Agreement Amendment

The Credit Agreement was amended on August 3, 2020 (the “Amendment Effective Date”) to amend, among other things, the requirements of certain covenants and the date on which certain covenants in the Credit Agreement must be met beginning on the Amendment Effective Date until the last day of the fiscal quarter ending December 31, 2021 (the “Covenant Relief Period”).

The amendment, among other items, increases the maximum funded debt to EBITDA ratio to (i) 5.75 to 1.00 for the fiscal quarters ending September 30, 2020 and December 31, 2020, (ii) 5.50 to 1.00 for the fiscal quarters ending March 31, 2021 and June 30, 2021 and (iii) 5.25 to 1.00 for the fiscal quarters ending September 30, 2021 and December 31, 2021 (reverting back to 5.00 to 1.00 after the Covenant Relief Period).

In addition, during the Covenant Relief Period, the applicable margin for Eurodollar borrowings is increased from a range of 2.00% – 2.75% to a range of 2.25% – 3.00%.

Please see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Revolving Credit Facility” for additional information regarding the amendment to our Credit Agreement.

General Trends and Outlook

~~While our business does not have direct exposure to commodity prices, the general activity levels of our customers can be affected by commodity prices.~~

A significant amount of our assets are utilized in natural gas infrastructure applications typically located in shale plays, primarily in centralized ~~natural gas~~ gathering systems and processing ~~facilities.~~facilities utilizing large horsepower compression units. Given the ~~project~~infrastructure nature of these applications and long-term investment horizon of our customers, we have generally experienced stability in service rates and higher sustained utilization ~~rates~~ relative to other businesses more directly tied to drilling activity and wellhead economics. In addition to ~~assets utilized in~~our natural gas infrastructure applications, a ~~small~~ portion of our fleet is used in connection with gas lift applications on crude oil production ~~using~~targeted by horizontal drilling ~~techniques.~~

~~The~~techniques and can be accomplished by both small and large horsepower compression equipment.

Domestic natural gas production generally occurs in either primarily natural gas basins, such as the Marcellus, Utica and Haynesville Shales, or in basins where natural gas is produced alongside crude oil, also known as “associated” gas, such as the Permian and Delaware Basins, Eagle Ford and the Mid-Continent. Over the recent past, relative ~~increase~~stability in ~~and stabilization of,~~ commodity prices ~~during the second-half of 2016 and throughout 2017 has allowed our customers to increase their capital budgets~~encouraged investment in ~~regards to crude oil~~domestic exploration and production ~~activities~~(“E&P”) and midstream infrastructure across the ~~build-out~~energy industry, particularly in the low-cost basins characterized by associated gas and crude oil production. The development of ~~large-scale~~these basins producing both commodities has created additional incremental demand for natural gas ~~infrastructure projects, particularly~~compression over the recent past as it is a critical method to transport associated gas volumes or enhance crude oil production through gas lift.

However, certain 2020 events have impacted, and may continue to impact, our operations in areas driven by associated gas and crude oil production. For example, in March 2020 the collapse of discussions among members of Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with ~~favorable economics. These projects increased~~OPEC and other allied producing countries, “OPEC+”), combined with Saudi Arabia’s announcement that it would be discounting its price, and increasing its supply, of crude oil into the global market created downward pressure on crude oil prices worldwide. Recent events, including reports of decreasing domestic crude oil inventory in storage as well as OPEC’s general compliance to agreed-upon production cuts and Saudi Arabia’s leadership in taking on further production cuts may be indicators of improving longer-term crude oil fundamentals which may positively impact basins where associated gas volumes are produced. Further, the ongoing global impact, both real and perceived, on crude oil demand from the COVID-19 pandemic created uncertainty regarding the demand for compression services in our operating areas driven by associated gas and crude oil production. While our business is focused on providing compression services and does not have any direct exposure to commodity prices, we have indirect exposure to commodity prices as overall levels of activity across the energy industry are influenced by the commodity price environment. As the price of crude oil fluctuated during 2020, certain of our customers reduced their demand for our ~~compression services throughout 2017 as~~services. Accordingly, we ~~saw~~have reduced our horsepower utilization increase from 87.1% at December 31, 2016 to 94.8% at December 31, 2017, while also increasing the horsepower in our fleet from 1,720,547 at December 31, 2016 to 1,799,781 at December 31, 2017.

planned capital spending significantly for 2021.

The ~~U.S. Energy Information Administration~~EIA’s January ~~2018~~2021 Short-Term Energy Outlook (“EIA Outlook”) ~~expects dry natural gas~~estimates that annual U.S. crude oil production ~~to rise by 6.9 billion cubic feet~~averaged 11.3 million barrels per day (“~~Bcf/day”~~bpd”) in ~~2018~~2020, down 1.0 million bpd from 2019 reflecting the impact of well curtailments and ~~by 2.6 Bcf/day~~a decrease in ~~2019. If achieved,~~drilling activity related to low crude oil prices. While the ~~forecasted 6.9 Bcf/day increase in 2018 would be~~price of crude oil rebounded during the ~~highest on record for any single year. The EIA Outlook expects growth to be concentrated in Appalachia’s Marcellus~~second quarter of 2020 and ~~Utica regions, along with~~remained relatively stable during the ~~Permian Basin region, all regions in which we provide compression services. Much~~third and fourth quarters of ~~the expected increase in natural gas production is the result of increasing pipeline takeaway capacity out of the Marcellus~~2020, and Utica producing regions to end-use markets. Additionally, EIA Outlook projects liquefied natural gas (“LNG”) gross exports will average 3.0 Bcf/day in 2018, up from 1.9 Bcf/day in 2017. The EIA Outlook expects U.S. liquefaction capacity will continue to expand as several new projects are expected to enter service during 2018 and 2019. Also from the EIA Outlook, natural gas pipeline exports to Mexico through October increased by 0.4 Bcf/day in 2017 compared to the same period in 2016. A relatively low natural

rig counts have

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~~gas export price, rising demand from Mexico’s power sector, and~~ increased ~~pipeline capacity in both~~modestly since the ~~U.S. and Mexico have led to increased exports.~~

~~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~~recent bottom during summer 2020, many E&P companies, including some of ~~new natural gas fields. As such, we expect demand for~~ our ~~compression services to~~customers, continue to ~~increase throughout 2018~~ ~~although we cannot predict any possible changes in such demand with reasonable certainty~~.

~~We intend~~take a cautious approach to ~~prudently deploy~~development plans and budget for reduced capital for new compressor units in 2018. We have already entered into commitments to purchase most of our large horsepower compressor units in 2018, as the lead time to build these units is approximately one year or shorter. Most of our 2018 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.

expenditure forecasts. The EIA Outlook forecasts total U.S. crude oil production in 2021 to ~~average 10.3~~decline again, averaging 11.1 million ~~barrels per day~~bpd, before increasing to 11.5 million bpd in ~~2018, up 1.0 million barrels per day from 2017. If achieved, forecasted 2018~~2022. Taking into account an approximate six-month lag between changes in crude oil prices and changes in crude oil production, ~~would be the highest annual average on record, surpassing the previous record of 9.6 million barrels per day set in 1970. According to~~ the EIA Outlook expects production from the Lower 48 states to decline through February 2021 before showing steady increases throughout the remainder of 2021; ending 2021 with an aggregate 3% decline in ~~2019,~~Lower 48 production. We expect the reduction in capital spending during 2020 to result in a decrease in new production, in turn negatively affecting the demand for new compression services in the near term. Further, while the Permian and Delaware Basins, one of our largest operating areas on a horsepower basis, still benefit from favorable geology as well as technological and operational improvements that have benefited operators in the region; overall reduced drilling activity and the typically steep well decline curves are expected to have an impact on production. As an example, the EIA Outlook expects two-thirds of U.S Lower 48 onshore growth in 2022 to come from the Permian. However, cost of capital and capital allocation policies are expected to continue to force operators to be disciplined in their spending.

While we expect new activity to generally be reduced in 2021, the impact from these events on existing production of crude oil ~~production~~and natural gas, however, is ~~forecast~~far less certain. Variables such as takeaway capacity, flaring considerations, reservoir pressure and flow rates, high switching costs associated with large horsepower compressors (borne by our customers), and specific company dynamics may all factor into producers’ decisions with respect to ~~rise to an average of 10.8 million barrels per day~~their existing production. For example, as wells age, and the ~~Permian region~~reservoir pressures naturally continue to decline, more horsepower may be required to meet the customer’s operational needs. In contrast, small horsepower gas lift applications have historically been more susceptible to commodity price swings, and we have experienced, and may continue to experience, some pressure on service rates and utilization in small horsepower gas lift applications. We cannot predict with reasonable certainty the effect on utilization of our assets servicing existing production in these regions.

Unlike crude oil, natural gas production and prices have been influenced by different drivers over the recent past, as there is no OPEC+ equivalent in the global natural gas market and therefore the price of natural gas is generally determined by market forces of supply and demand rather than by a centralized market coordinator. Over the past several years, increased gas production in the U.S. driven by large volumes of gas produced from shale sources has been a main driver of an overall drop in natural gas prices. This sustained low natural gas price environment has helped create relatively resilient baseload demand for natural gas for domestic use in power generation and for industrial purposes such as chemical plants and other types of manufacturing. Also, the development of long-term export infrastructure has continued to occur alongside the low natural gas price environment and the U.S. became a net exporter of natural gas into global markets in 2017. For example, while the EIA expects a decline in natural gas production for 2021 due to a decrease in the usage of natural gas in the electric power generation sector, as a result of relatively higher natural gas prices (versus coal) and increased power generation from renewables, these decreases are expected to be partially offset by other uses, including increased liquefied natural gas exports as well as increased pipeline exports to Mexico. While the EIA expects an overall decline in natural gas production in 2021, monthly production is expected to ~~produce 3.6 million barrels per day~~bottom out in March 2021 and then increase through the rest of ~~crude oil~~2021, followed by continued increase in 2022. We expect the ~~end of 2019 which would represent about 32% of U.S. crude oil production that year. With the large geographic area of the Permian region and stacked plays, the EIA Outlook estimates that operators can~~baseload natural gas demand previously described will continue to ~~develop multiple tight oil layers~~support long-term domestic natural gas production.

In addition to the relatively stable supply, demand and price fundamentals of natural gas, we believe that the geographic diversity and portability of our assets should help mitigate the impact of market volatility or regional uncertainty. While reduced production of associated gas impacted demand for our services in certain regions beginning in the first quarter of 2020, such reduction in production had a positive impact on both natural gas prices as well as the utilization of our assets in other regions primarily tied to natural gas prospects, such as the Marcellus, Utica and Haynesville shales. Given these producing regions primarily contain natural gas, if natural gas prices remain resilient we believe it is reasonable to expect that these areas could see additional capital inflows to take advantage of relatively more attractive economics, which could increase ~~production, even~~demand for our services in these shales. The design flexibility of our compression units allow us to make rapid reconfigurations and relocate units to these areas. On the whole, we believe the longer-term outlook for natural gas fundamentals remains positive, as market signs, including natural gas futures market, point to a more balanced gas market through 2021.

In summary, while the outlook for commodity prices stabilized over the course of 2020, continued uncertainty with ~~sustained~~respect to demand could have a varying impact on our business. Whereas several factors, including uncertain future demand, caused volatility in crude oil prices ~~lower~~during 2020, on the natural gas side, relatively more moderate demand destruction coupled with associated gas production decreases have in part helped to support natural gas prices. The overall outlook for our compression services will depend, in part, on the strength and duration of recovery in the commodity markets, and we believe as natural gas experienced a recovery more quickly than ~~$50 per barrel. As of February 8, 2018, the WTI~~ crude oil, ~~spot price was $61.15 per barrel. WTI crude oil spot~~the continued market dynamics should help support our business activities and overall utilization and pricing.

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While we anticipate that the combination of commodity prices ~~are forecast within~~and demand may likely have an impact on activity levels in both the ~~EIA Outlook~~upstream and midstream sectors, we cannot predict the ultimate magnitude of that impact on our business and expect it to ~~average $56 per barrel in 2018~~be varied across our operations, depending on the region, customer, nature of compression application, contract term and ~~$57 per barrel in 2019. Daily~~other factors. We believe our customers’ mid- to long-term expectations regarding commodity prices and ~~monthly average crude oil prices could vary significantly from annual average forecasts due~~the cost they would incur to ~~global economic developments and geopolitical events~~return our large horsepower equipment will provide an incentive for our customers to keep our equipment 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 adherence to, the current Organization~~field following expiration of the ~~Petroleum Exporting Countries (“OPEC”) production cuts,~~primary term, whereas we believe there is likely to be continued pressure on utilization and pricing with respect to our smaller horsepower equipment.

Ultimately, the extent to which ~~could influence prices in either direction.~~

~~We believe~~our business will be impacted by the ~~relative increase in, and stabilization of, crude oil prices in the second half of 2016 and throughout 2017 has led to an increase in drilling activity, and combined~~factors described above, as well as future developments beyond our control, cannot be predicted with the continued development of horizontal drilling technology, operators are able to produce new volumes of crude oil from tight, high pressure reservoirs. Due in part to these higher initial pressures, the increase in demand for gas lift compression in these new areas of drilling could be delayed until reservoir pressures decline to a point where compression is beneficial to the economics of a particular well or basin.reasonable certainty. However, we ~~have experienced an increase in~~continue to believe that overall the long-term demand for our ~~smaller horsepower units engaged~~compression services will continue given the necessity of compression in facilitating the transportation and processing of natural gas ~~lift applications~~as well as the production of crude oil.

COVID-19 Update

Beginning in the first quarter of 2020, the COVID-19 pandemic prompted several states and ~~expect that~~municipalities in which we operate to ~~continue.~~

take extraordinary and wide-ranging actions to contain and combat the outbreak and spread of the virus, including mandates for many individuals to substantially restrict daily activities and for many businesses to curtail or cease normal operations. These mandates and restrictions have varied across jurisdictions and, over time, have been rescinded and reinstated as the severity of the pandemic fluctuated. For as long as COVID-19 continues or worsens, governments may impose additional similar restrictions or reinstate previously lifted ones. To date, our field operations have continued largely uninterrupted as the U.S. Department of Homeland Security designated our industry part of our country’s critical infrastructure. Thus far, remote work and other COVID-19 related conditions have not significantly impacted our ability to maintain operations or caused us to incur significant additional expenses; however, we are unable to predict the duration or ultimate impact of current and potential future COVID-19 mitigation measures.

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Operating Highlights

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

Year Ended December 31,

Percent Change

Operating Data:

2017

2016

2015

2017

2016

Fleet horsepower (at period end) (1)

1,799,781

1,720,547

1,712,196

4.6
%
0.5
%
Total available horsepower (at period end) (2)

1,950,301

1,730,547

1,712,196

12.7
%
1.1
%
Revenue generating horsepower (at period end) (3)

1,624,377

1,387,073

1,424,537

17.1
%
(2.6)
%
Average revenue generating horsepower (4)

1,505,657

1,377,966

1,408,689

9.3
%
(2.2)
%
Average revenue per revenue generating horsepower per month (5)

$
15.07

$
15.41

$
15.90

(2.2)
%
(3.1)
%
Revenue generating compression units (at period end)

2,830

2,552

2,737

10.9
%
(6.8)
%
Average horsepower per revenue generating compression unit (6)

554

534

517

3.7
%
3.3
%
Horsepower utilization (7):

At period end

94.8
%

87.1
%

89.2
%
8.8
%
(2.4)
%
Average for the period (8)

92.0
%

87.4
%

90.5
%
5.3
%
(3.4)
%
presented and excludes certain gas treating assets for which horsepower is not a relevant metric.


	Year Ended December 31,						Percent
	2020			2019			Change
Fleet horsepower (at period end) (1)	3,726,181			3,682,968			1.2	%
Total available horsepower (at period end) (2)	3,726,181			3,709,468			0.5	%
Revenue generating horsepower (at period end) (3)	2,997,262			3,310,024			(9.4)	%
Average revenue generating horsepower (4)	3,139,732			3,279,374			(4.3)	%
Average revenue per revenue generating horsepower per month (5)	$	16.71		$	16.65		0.4	%
Revenue generating compression units (at period end)	3,968			4,559			(13.0)	%
Average horsepower per revenue generating compression unit (6)	746			720			3.6	%
Horsepower utilization (7):
At period end	82.8		%	93.7		%	(11.6)	%
Average for the period (8)	86.8		%	94.1		%	(7.8)	%

~~(1)~~

________________________

~~(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.

(1)Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order).

~~(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.~~

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

~~(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.

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

(5)Calculated as the average of the result of dividing the contractual monthly rate, excluding standby or other temporary rates, 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.

~~(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 90.3%, 80.6% and 83.2% at December 31, 2017, 2016 and 2015, respectively.

(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.

~~(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 85.9%, 80.3% and 85.1% for the years ended December 31, 2017, 2016 and 2015, respectively.

(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 80.4% and 89.9% at December 31, 2020 and 2019, 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 84.5% and 89.8% for the years ended December 31, 2020 and 2019, respectively.

The ~~4.6%~~1.2% increase in fleet horsepower as of December 31, ~~2017 over the fleet horsepower as of~~2020 compared to December 31, ~~2016~~2019 was attributable to ~~new~~ compression units added to our fleet ~~to meet then expected~~primarily for specific customer demand for our compression services, partially offset by ~~new and~~compression units impaired during the current ~~customers for compression services.~~period. The ~~17.1% increase~~9.4% decrease in revenue generating horsepower as of December 31, ~~2017 over~~2020 compared to December 31, ~~2016~~2019 was due to returns of compression units from our customers which also caused a 13.0% decrease in revenue generating compression units over the same period. The returns of compression units from our customers are primarily due to ~~organic growth~~a decrease in ~~our active fleet~~demand for compression services driven by a decline in U.S. crude oil and ~~redeployment of previously idle equipment.~~ natural gas activity.

The ~~3.7%~~3.6% increase in average horsepower per revenue generating compression unit aswas driven primarily by the composition of ~~December 31, 2017 over December 31, 2016 was primarily due to the addition of large horsepower~~ compression ~~units in the operating fleet. The 2.2% decrease~~unit returns. The 0.4% increase in average revenue per revenue generating horsepower per month for the year ended December 31, ~~2017 over December 31, 2016 was primarily due~~2020 compared to (1) reduced pricing in the small horsepower portion of our fleet in the current period and (2) 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.

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The 0.5% increase in fleet horsepower as of December 31, 2016 over the fleet horsepower as of December 31, 2015 was attributable to new compression units added to our fleet to meet then expected demand by new and current customers for compression services. The 2.6% decrease in revenue generating horsepower as of December 31, 2016 over December 31, 2015 was primarily due to an increase in the amount of time required to contract services for new compression units and an increase in the amount of compression units returned to us. The 3.3% increase in average horsepower per revenue generating compression unit as of December 31, 2016 over December 31, 2015 was primarily due to the addition of large horsepower compression units in the operating fleet and the decline in utilization of small horsepower units over the year ended December 31, ~~2016. The 3.1% decrease in average revenue per revenue generating horsepower per month for the year ended December 31, 2016 over December 31, 2015~~2019 was primarily due to ~~(1)~~contracts on new compression units and selective price increases on our existing large horsepower fleet, partially offset by reduced pricing in ~~the~~our small horsepower ~~portion~~fleet.

Horsepower utilization decreased to 82.8% as of December 31, 2020 compared to 93.7% as of December 31, 2019. The 11.6% decrease in horsepower utilization is primarily due to (1) a 10.8% increase in our ~~fleet in the current period~~idle horsepower from compression units returned to us and (2) ~~an increase~~a 2.0% decrease in ~~the average~~ horsepower ~~per revenue generating compression unit in the current period, resulting from an increase in the number~~that is on-contract or pending-contract but not yet active. Average

Table of ~~large horsepower compression units which typically generate lower average revenue per revenue generating horsepower than do small horsepower compression units.~~

~~Average~~ Contents

horsepower utilization ~~increased~~decreased to ~~92.0%~~86.8% during the year ended December 31, ~~2017~~2020 compared to ~~87.4%~~94.1% during the year ended December 31, ~~2016.~~2019. The ~~4.6% increase~~7.8% decrease in average horsepower utilization ~~was~~is primarily ~~attributable~~due to ~~the following changes as a percentage of total available horsepower:~~ (1) a 6.9% increase in ~~horsepower that is under contract but not yet generating revenue and (2) a 1.9% decrease in~~ our average ~~fleet of~~idle horsepower from compression units returned to us not yet under contract, offset by (3) a 4.0% decrease in idle horsepower under repair, which is excluded from the average horsepower utilization calculation until such repair is complete. We believe the increase in average horsepower utilization is the result of increased demand for our services commensurate with increased operating activity in the oil and gas industry. The above noted fluctuation in utilization components also describes the changes in period end horsepower utilization as of December 31, 2017 compared to December 31, 2016.

Average horsepower utilization decreased to 87.4% during the year ended December 31, 2016 compared to 90.5% during the year ended December 31, 2015. The 3.1% decrease in average horsepower utilization was primarily attributable to the following changes as a percentage of total available horsepower: (1) a 3.7% increase in our average fleet of compression units returned to us not yet under contract and (2) a ~~1.0%~~3.0% decrease in horsepower that ~~was~~is on-contract or pending-contract but not yet active. The ~~decrease~~decreases in period end and average horsepower utilization ~~was offset~~are primarily due to a decrease in demand for compression services driven by a ~~2.6% increase~~decline in idle horsepower under repair, which is excluded from the average horsepower utilization calculation until such repair is complete. We believe the decrease in average horsepower utilization was the result of a delay in planned projects of certain of our customers, continued optimization of existing compression service requirements by our customersU.S. crude oil and our selective pursuit of what we deemed to be the most attractive opportunities. The above noted fluctuation in utilization components also describes the changes in period end horsepower utilization, except that we experienced a 1.2% increase in horsepower that was on-contract or pending-contract but not yet active as of December 31, 2016 compared to December 31, 2015.

~~Average horsepower~~natural gas activity.

Horsepower utilization based on revenue generating horsepower and fleet horsepower ~~increased~~decreased to ~~85.9% during the year ended~~80.4% as of December 31, ~~2017~~2020 compared to ~~80.3% during the year ended~~89.9% as of December 31, ~~2016.~~2019. The ~~5.6% increase was primarily attributable to the following changes as a percentage of total fleet horsepower: (1) a 4.0%~~10.6% decrease in idle horsepower under repair and (2) a 2.0% decrease in our average idle fleet composed of new compression units offset by (3) a 0.4% increase in our average idle fleet from compression units returned to us. The overall decrease in idle horsepower is the result of increased demand for our services commensurate with 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~~as of December 31, ~~2017 and the year ended December 31, 2016.~~

2020 was primarily attributable to an increase in our idle horsepower from compression units returned to us. Average horsepower utilization based on revenue generating horsepower and fleet horsepower decreased to ~~80.3% during~~84.5% for the year ended December 31, ~~2016~~2020 compared to ~~85.1% during~~89.8% for the year ended December 31, ~~2015.~~2019. The ~~4.8%~~5.9% decrease in average horsepower utilization based on revenue generating horsepower for the year ended December 31, 2020 was primarily attributable to ~~the following changes as a percentage of total fleet horsepower: (1) a 4.7%~~an increase in our average idle ~~fleet~~horsepower from compression units returned to ~~us and (2) a 2.6% increase in idle horsepower under repair offset by (3) a 2.4% decrease in our average idle fleet composed of new compression units.~~us. The ~~increase in units returned to us is believed to be a result of our customers’ optimization of their compression service requirements. These~~

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~~factors also describe the variances~~decreases in period end and average horsepower utilization based on revenue generating horsepower and fleet horsepower ~~between the year ended December 31, 2016~~are primarily due to a decrease in demand for compression services driven by a decline in U.S. crude oil and ~~the year ended December 31, 2015.~~

natural gas activity.

Financial Results of Operations

Year ended December 31, ~~2017~~2020 compared to the year ended December 31, ~~2016~~

2019

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


	Year Ended December 31,				Percent				Year Ended December 31,				Percent
	2017		2016		Change				2020		2019		Change
Revenues:								Revenues:
Contract operations	$	264,315	$	246,950		7.0	%	Contract operations	$	644,194	$	664,162	(3.0)	%
Parts and service		15,907		18,971		(16.2)	%	Parts and service	11,117		14,236		(21.9)	%
Related party								Related party	12,372		19,967		(38.0)	%
Total revenues		280,222		265,921		5.4	%	Total revenues	667,683		698,365		(4.4)	%
Costs and expenses:								Costs and expenses:
Cost of operations, exclusive of depreciation and amortization		92,591		88,161		5.0	%	Cost of operations, exclusive of depreciation and amortization	205,939		227,303		(9.4)	%
Gross operating margin		187,631		177,760		5.6	%
Other operating and administrative costs and expenses:
Depreciation and amortization								Depreciation and amortization	238,968		231,447		3.2	%
Selling, general and administrative		47,483		44,483		6.7	%	Selling, general and administrative	59,981		64,397		(6.9)	%
Depreciation and amortization		98,603		92,337		6.8	%
Loss (gain) on disposition of assets		(507)		772		165.7	%
Loss on disposition of assets								Loss on disposition of assets	146		940		(84.5)	%
Impairment of compression equipment		4,972		5,760		(13.7)	%	Impairment of compression equipment	8,090		5,894		37.3	%
Total other operating and administrative costs and expenses		150,551		143,352		5.0	%
Operating income		37,080		34,408		7.8	%
Impairment of goodwill								Impairment of goodwill	619,411		—		*
Total costs and expenses								Total costs and expenses	1,132,535		529,981		*
Operating income (loss)								Operating income (loss)	(464,852)		168,384		*
Other income (expense):								Other income (expense):
Interest expense, net		(25,129)		(21,087)		19.2	%	Interest expense, net	(128,633)		(127,146)		1.2	%
Other		27		35		(22.9)	%	Other	86		80		7.5	%
Total other expense		(25,102)		(21,052)		19.2	%	Total other expense	(128,547)		(127,066)		1.2	%
Income before income tax expense		11,978		13,356		(10.3)	%
Net income (loss) before income tax expense								Net income (loss) before income tax expense	(593,399)		41,318		*
Income tax expense		538		421		27.8	%	Income tax expense	1,333		2,186		(39.0)	%
Net income	$	11,440	$	12,935		(11.6)	%
Net income (loss)								Net income (loss)	$	(594,732)	$	39,132	*

________________________

*Not meaningful.

Contract operations revenue. ~~During 2017, we experienced a year-to-year increase~~The $20.0 million decrease in ~~demand for our compression services driven by increased operating activity in natural gas and crude oil production, resulting in a $17.4 million increase in our~~ contract operations ~~revenue. Average~~ revenue ~~generating horsepower increased 9.3% during the year ended December 31, 2017 over December 31, 2016 while average revenue per revenue generating horsepower per month decreased from $15.41~~ for the year ended December 31, ~~2016~~2020 compared to ~~$15.07~~the year ended December 31, 2019 was primarily due to a decline in demand for compression services driven by a decrease in U.S. crude oil and natural gas activity. This decline in demand resulted in a 4.3% decrease in average revenue generating horsepower for the year ended December 31, ~~2017,~~2020 compared to the year ended December 31, 2019, partially offset by a ~~decrease of 2.2%, attributable, in part, to reduced pricing in the current period in the small horsepower portion of our fleet. The decrease~~0.4% increase in average revenue per revenue generating horsepower per month which increased to $16.71 for the year ended December 31, 2020 compared to $16.65 for the year ended December 31, 2019. Our contract operations revenue was ~~also attributable to~~not

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materially impacted by any renegotiations of our contracts during the ~~3.7% increase in the~~period with our customers. Additionally, average horsepower per revenue generating compression unit in the current period, as large horsepower compression units typically generate lower average monthly revenue per revenue generating horsepower than do small horsepower compression units. ~~Average~~ revenue per revenue generating horsepower per month associated with our compression services provided on a month-to-month basis did not significantly differ from the average revenue per revenue generating horsepower per month associated with our compression services provided under contracts in ~~the~~their primary term~~. Our contract operations revenue was not materially impacted by any renegotiations of our contracts~~ during the ~~period with our customers.~~

period.

Parts and service revenue. ~~Parts and service revenue was earned primarily on the installation of equipment ancillary to compression operations.~~ The $3.1 million decrease in parts and service revenue for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily attributable to ~~(1) an $8.3 million decrease in revenue associated with installation services offset by (2)~~ a ~~$4.1 million increase~~reduction in maintenance work performed on units at our ~~customers'~~customers’ locations that are outside the scope of our core maintenance activities and ~~(3)~~offered as a ~~$1.4 million increase in~~courtesy to our customers, and freight and crane charges that are directly reimbursable by ~~our~~ customers. ~~We offer these~~

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~~services as a courtesy to our customers~~Demand for retail parts and ~~the demand~~services fluctuates from period to period based on the varying needs of our ~~customers~~.

customers.

Related party revenue. Related party revenue was earned through related party transactions in the ordinary course of business with various affiliated entities of ETO. The $7.6 million decrease in related party revenue for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily attributable to a decrease in parts and service revenue, as well as a decrease in contract operations revenue due to the expiration of contracts with various affiliated entities of ETO.

Cost of operations, exclusive of depreciation and amortization. The ~~$4.4~~$21.4 million ~~increase~~decrease in cost of operations for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily ~~attributable~~due to (1) ~~a $7.4~~an $11.5 million ~~increase~~ decrease in direct expenses, such as parts and fluids expenses, ~~and~~ (2) a ~~$2.4~~$6.2 million ~~increase~~decrease in direct labor expenses, ~~offset by~~ (3) a ~~$3.5~~$4.6 million decrease in retail parts and ~~service~~services expenses, which ~~have~~had a corresponding decrease in parts and service revenue, ~~and~~ (4) a ~~$2.7~~$3.1 million decrease in ~~property~~expenses related to our vehicle fleet and (5) a $1.7 million decrease in training and other ~~taxes.~~indirect expenses. The ~~increase~~decreases in ~~direct~~ parts, fluids, direct labor, vehicle expenses, training and ~~labor~~other indirect expenses are primarily driven by the ~~increase~~decrease in average revenue generating horsepower and reduced headcount during the current period.

~~Gross operating margin.~~ The ~~$9.9~~decreases were partially offset by (6) a $5.1 million increase in ~~gross operating margin was~~ad valorem tax expenses due primarily ~~due~~ to anrefunds received during the prior period.

Depreciation and amortization expense. The $7.5 million increase in ~~revenues, partially offset by an increase in operating expenses during~~depreciation and amortization expense for the year ended December 31, ~~2017.~~

2020 compared to the year ended December 31, 2019 was primarily related to compression units and other capital expenditures placed in service during 2019, to meet then existing demand by customers, that have a full year of depreciation expense recorded in 2020.

Selling, general and administrative expense. The ~~$3.0~~$4.4 million ~~increase~~decrease in selling, general and administrative expense for the year ended December 31, ~~2017 was primarily attributable~~2020 compared to ~~(1) a $1.3 million increase in unit-based compensation expense, (2) a $0.8 million increase in bad debt expense, due to a $1.1 million recovery of bad debt expense during~~ the year ended December 31, ~~2016 compared~~2019 was primarily due to (1) a ~~$0.3~~$2.4 million ~~recovery during the year ended December 31, 2017~~decrease in employee-related expenses, (2) a $2.4 million decrease in general corporate expenses, (3) a $2.4 million decrease in unit-based compensation expense and ~~(3) $0.5~~(4) a $1.1 million decrease in third-party professional fees. These decreases were offset by (5) a $2.7 million increase in ~~transaction~~the provision for expected credit losses and (6) a $1.6 million increase in severance charges.

The decreases in employee-related expenses, general corporate expenses and third-party professional fees are related to ~~potential acquisitions. Unit-based~~reduced headcount and cost saving measures. The decrease in unit-based compensation expense ~~increased~~is primarily due to ~~a greater fair value assigned~~the decrease in our unit price in the current period and the related mark-to-market change to our unit-based compensation liability. The change to the ~~2016 “Performance Units” that are subject~~provision for expected credit losses is related to ~~market criteria~~the potential negative impact to our customers of low crude oil prices driven by decreased demand due to the COVID-19 pandemic and ~~which were~~ ~~measured using~~ the ~~Monte Carlo simulation model as~~global oversupply of ~~December 31, 2017.~~

~~Depreciation and amortization expense~~.crude oil during the current period. The ~~$6.3 million~~ increase in ~~depreciation expense was~~severance charges is primarily related to ~~an increase in gross property and equipment balances~~the departure of one of our executives during the ~~year ended December 31, 2017 compared to gross balances during the year ended December 31, 2016.~~

~~Loss (gain) on disposition of assets. During the year ended December 31, 2017, the $0.5 million gain was primarily attributable to the sale of select compression equipment.~~ ~~During the year ended December 31, 2016, we abandoned certain assets and incurred a $1.0 million loss.~~

current period.

Impairment of compression equipment. The ~~$5.0~~$8.1 million and ~~$5.8~~$5.9 million ~~impairment charge~~impairments of compression equipment during the years ended December 31, ~~2017~~2020 and ~~2016,~~2019, respectively, were primarily athe result of our ~~evaluation~~evaluations of the future deployment of our ~~current~~ idle fleet under ~~the~~ current market conditions. ~~Our evaluation determined that~~The primary causes for these impairments 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 ~~impaired equipment,~~unit, such as ~~excessive maintenance costs and~~ the inability ~~of the equipment~~ to meet ~~then-current emission standards~~current quoting criteria without excessive retrofitting ~~this equipment was unlikely~~costs. These compression units were written down to ~~be accepted by customers under then-current market conditions.~~ their respective estimated salvage values, if any.

As a result of our ~~evaluation~~evaluations during the years ended December 31, ~~2017~~2020 and ~~2016,~~2019, we determined to retire 37 and ~~either sell or re-utilize the key components of 40 and 29~~33 compression units, respectively, with a total of approximately ~~11,000~~15,000 and ~~15,000~~11,000 horsepower, respectively, that had been previously used to provide compression services in our business.

~~Interest expense, net~~. ~~The $4.0 million increase~~

Impairment of goodwill. During the first quarter of 2020 certain potential impairment indicators were identified, specifically (i) the decline in ~~interest expense, net was primarily attributable to~~ the ~~impact~~market price of ~~an increase~~our common units, (ii) the decline in ~~our weighted average interest rate.~~ ~~Our revolving credit facility bore an interest rate of 3.46%~~global commodity prices, and ~~2.94% at December 31, 2017 and 2016, respectively, and a weighted-average interest rate of 3.14% and 2.55% during~~(iii) the ~~years ended December 31, 2017 and 2016, respectively. The impact~~COVID-19 pandemic; which together indicated the fair value of the ~~increase in interest rate~~reporting unit was ~~partially offset by~~less than its carrying amount as of

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March 31, 2020. We performed a quantitative goodwill impairment test as of March 31, 2020 and determined fair value using a weighted combination of the ~~impact~~income approach and the market approach and, as a result, recognized a goodwill impairment of ~~an $8.9 million decrease in average outstanding borrowings under our revolving credit facility. Average borrowings under the facility were $734.6~~$619.4 million for the year ended December 31, ~~2017~~2020. No impairment was recorded for the year ended December 31, 2019.

Interest expense, net. The $1.5 million increase in interest expense, net for the year ended December 31, 2020 compared to ~~$743.5~~the year ended December 31, 2019 was primarily due to a full year of interest expense incurred in the current period on the Senior Notes 2027 issued in March 2019, partially offset by reduced borrowings and lower weighted average interest rates under the Credit Agreement.

The weighted average interest rate applicable to borrowings under the Credit Agreement was 3.27% for the year ended December 31, 2020 compared to 4.84% for the year ended December 31, 2019. Average outstanding borrowings under the Credit Agreement were $455.7 million for the year ended December 31, ~~2016.~~

~~Income tax expense. This line item represents the Revised Texas Franchise Tax (“Texas Margin Tax”) and change in deferred tax liability, which is materially consistent between both periods.~~

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~~Year ended December 31, 2016~~2020 compared to ~~the year ended December 31, 2015~~

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

Year Ended December 31,

Percent


2016

2015

Change

Revenues:

Contract operations

$
246,950

$
263,816

(6.4)
%
Parts and service

18,971

6,729

181.9
%
Total revenues

265,921

270,545

(1.7)
%
Costs and expenses:

Cost of operations, exclusive of depreciation and amortization

88,161

81,539

8.1
%
Gross operating margin

177,760

189,006

(6.0)
%
Other operating and administrative costs and expenses:

Selling, general and administrative

44,483

40,950

8.6
%
Depreciation and amortization

92,337

85,238

8.3
%
Loss (gain) on disposition of assets

772

(1,040)

174.2
%
Impairment of compression equipment

5,760

27,274

(78.9)
%
Impairment of goodwill

—

172,189

*
%
Total other operating and administrative costs and expenses

143,352

324,611

(55.8)
%
Operating income (loss)

34,408

(135,605)

125.4
%
Other income (expense):

Interest expense

(21,087)

(17,605)

19.8
%
Other

35

22

59.1
%
Total other expense

(21,052)

(17,583)

19.7
%
Income (loss) before income tax expense

13,356

(153,188)

108.7
%
Income tax expense

421

1,085

(61.2)
%
Net income (loss)

$
12,935

$
(154,273)

108.4
%

* Not meaningful.

~~Contract operations revenue~~. During 2016, we experienced a year-to-year decrease in demand for our compression services driven by decreased operating activity in natural gas and crude oil production and continued optimization of existing compression service requirements, resulting in a 2.2% decrease in average revenue generating horsepower and a $16.9 million decrease in our contract operations revenue. Average revenue per revenue generating horsepower per month decreased from $15.90 for the year ended December 31, 2015 to $15.41 for the year ended December 31, 2016, a decrease of 3.1%, attributable, in part, to reduced pricing in the current period in the small horsepower portion of our fleet. The decrease in average revenue per revenue generating horsepower per month was also attributable to the 3.3% increase in the average horsepower per revenue generating compression unit in the current period, as large horsepower compression units generally generate lower average monthly revenue per revenue generating horsepower than do small horsepower compression units. Average revenue per revenue generating horsepower per month associated with our compression services provided on a month-to-month basis was somewhat higher than the average revenue per revenue generating horsepower per month associated with our compression services provided under contracts in the primary term due to pressure on service rates attributable to the small horsepower portion of our fleet. Because the demand for our services is driven primarily by production of natural gas, we focus our activities in areas of attractive growth, which are generally found in certain shale and unconventional resource plays, as discussed above under the heading “Overview.” Our contract operations revenue was not materially impacted by any renegotiations of our contracts during the period with our customers.

~~Parts and service revenue~~. Parts and service revenue was earned primarily on the installation of equipment ancillary to compression operations. During 2016, we recognized $15.7 million of revenue associated with installation services, which accounts for the $12.2 million year-over-year increase in parts and service revenue. The remaining component of our parts and service revenue, which was earned primarily on (1) freight and crane charges that are directly reimbursed by our customers, for which we earn little to no margin, and (2) maintenance work on units at our customers’ locations

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~~that are outside the scope of our core maintenance activities, for which we earn lower margins than our contract operations, decreased $3.5 million during the current period.~~

~~Cost of operations, exclusive of depreciation and amortization.~~ ~~The $6.6 million increase in cost of operations was primarily attributable to an $8.3 million increase in~~ retail parts and service expenses, which includes $11.9 million of additional costs associated with our installation services. Excluding these costs, retail parts and services expense decreased $3.6 million reflecting a corresponding decrease in this component of parts and services revenue. Additionally during the period, we experienced (1) a $2.1 million decrease in direct expenses, such as parts and fluids expenses, (2) a $0.6 million decrease in direct labor expenses and (3) a $0.5 million decrease in expenses related to our vehicle fleet, offset by (4) a $1.7 million increase in property and other taxes. The decrease in direct parts, fluids, labor and vehicle expenses are primarily driven by the decrease in average revenue generating horsepower during the current period.

~~Gross operating margin.~~ The $11.2 million decrease in gross operating margin was primarily due to a decrease in revenues, partially offset by a decrease in operating expenses and the $3.8 million of gross operating margin we earned from our installation services during the year ended December 31, 2016.

~~Selling, general and administrative expense~~. The $3.5 million increase in selling, general and administrative expense for the year ended December 31, 2016 was primarily attributable to a $6.5 million increase in unit-based compensation expense, partially offset by a $2.9 million decrease in bad debt expense. Unit-based compensation expense increased primarily due to (1) the increase in our unit price as of December 31, 2016 compared to December 31, 2015, (2) a greater number of outstanding phantom units as of December 31, 2016 compared to December 31, 2015 which resulted from a higher number of phantom unit grants during 2016 as compared to 2015 (reflecting our sharply lower unit price at the time the grants were made in 2016 versus our unit price at the time the grants were made in 2015), and (3) a greater number of phantom units outstanding on which distribution equivalent rights were paid as of each record date during the comparable periods. The decrease in bad debt expense was due primarily to a $1.1 million decrease in allowance for doubtful accounts during the year ended December 31, 2016 due in part to collections on accounts that had previously been reserved during the year ended December 31, 2015 as compared to a $1.8 million increase in the allowance for doubtful accounts during the year ended December 31, 2015.

~~Depreciation and amortization expense~~. The $7.1 million increase in depreciation expense was related to an increase in gross property and equipment balances during the year ended December 31, 2016 compared to gross balances during the year ended December 31, 2015. There is no variance in amortization expense between the periods, as intangible assets are amortized on a straight-line basis and there has been no change in gross identifiable intangible assets between the periods.

~~Loss (gain) on disposition of assets~~. During the year ended December 31, 2016, we abandoned certain assets and incurred a $1.0 million loss. The $1.0 million gain on sale of assets during the year ended December 31, 2015 was primarily attributable to $1.2 million cash insurance recoveries on previously impaired compression equipment received during the year and $1.1 million gain on sale of 18 units, or 7,200 horsepower, offset by $1.3 million of losses incurred in the disposal of various unit and non-unit assets.

~~Impairment of compression equipment~~. The $5.8 million and $27.3 million impairment charge during the years ended December 31, 2016 and 2015, respectively, were primarily a result of our evaluation of the future deployment of our current idle fleet under the 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 current emission standards without retrofitting, this equipment was unlikely to be accepted by customers under current market conditions. As a result of our evaluation during the years ended December 31, 2016 and 2015, we determined to retire and either sell or re-utilize the key components of 29 and 166 compression units, with a total of approximately 15,000 and 58,000 horsepower, respectively, that had been previously used to provide compression services in our business.

~~Goodwill impairment.~~ There was no impairment of goodwill for the year ended December 31, 2016. During the year ended December 31, 2015, we recorded a $172.2 million impairment of goodwill due primarily to the decline in our unit

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~~price, the sustained decline in global commodity prices, expected reduction in the capital budgets of certain of our customers and the impact these factors have on our expected future cash flows.~~

~~Interest expense, net~~. The $3.5 million increase in interest expense, net was primarily attributable to the impact of an approximately $20.2 million increase in average outstanding borrowings under our revolving credit facility, in which average borrowings were $743.5$493.3 million for the year ended December 31, ~~2016 compared to $723.3 million for the year ended December 31, 2015.~~ Our revolving credit facility had an interest rate of 2.94% and 2.26% at December 31, 2016 and 2015, respectively, and a weighted-average interest rate of 2.55% and 2.24% during the years ended December 31, 2016 and 2015, respectively.

2019.

Income tax ~~expense. This line item represents the Texas Margin Tax.~~expense. The $0.9 million decrease in income tax expense for the year ended December 31, ~~2016~~2020 compared to ~~December 31, 2015 was primarily associated with the establishment of a deferred tax liability reflecting the book/tax basis difference in our property and equipment during~~ the year ended December 31, ~~2015.~~

2019 was primarily related to deferred taxes associated with the Texas Margin Tax.

Other Financial Data

The following table summarizes other financial data for the periods presented (dollars in thousands):

Year Ended December 31,

Percent Change

Other Financial Data: (1)

2017

2016

2015

2017

2016

Gross operating margin

$
187,631

$
177,760

$
189,006

5.6
%
(6.0)
%
Gross operating margin percentage (2)

67.0
%

66.8
%

69.9
%
0.3
%
(4.4)
%
Adjusted EBITDA

$
155,703

$
146,648

$
153,572

6.2
%
(4.5)
%
Adjusted EBITDA percentage (2)

55.6
%

55.2
%

56.8
%
0.7
%
(2.8)
%
DCF (3)

$
118,330

$
118,329

$
120,850

0.0
%
(2.1)
%
DCF Coverage Ratio (3)

0.89
x

1.00
x

1.17

(11.0)
%
(14.5)
%
Cash Coverage Ratio (3)

1.02
x

1.26
x

2.58

(19.0)
%
(51.2)
%


	Year Ended December 31,						Percent
Other Financial Data: (1)	2020			2019			Change
Gross margin	$	222,776		$	239,615		(7.0)	%
Adjusted gross margin	$	461,744		$	471,062		(2.0)	%
Adjusted gross margin percentage (2)	69.2		%	67.5		%	2.5	%
Adjusted EBITDA	$	413,898		$	419,640		(1.4)	%
Adjusted EBITDA percentage (2)	62.0		%	60.1		%	3.2	%
DCF	$	220,766		$	221,868		(0.5)	%
DCF Coverage Ratio	1.09		x	1.13		x	(3.5)	%
Cash Coverage Ratio	1.10		x	1.14		x	(3.5)	%

~~(1)~~

~~Gross operating~~________________________

(1)Adjusted gross 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)~~

Definitions of DCF and DCF Coverage Ratio can be found under the caption “Non-GAAP Financial Measures” in Part II, Item 6. The DCF and DCF Coverage Ratios presented here are based on a weighted average of units outstanding. For the years ended December 31, 2016 and 2015, the DCF Coverage Ratio based on the actual units outstanding at the respective record dates was 0.98x and 1.15x, respectively, and the Cash Coverage Ratio based on actual units outstanding at the respective record dates for these same periods was 1.23x and 2.48x, respectively.

~~Adjusted EBITDA.~~ ~~The $9.1 million, or 6.2%, increase in~~ Adjusted EBITDA, ~~during~~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 “Selected Financial Data”.

(2)Adjusted gross margin percentage and Adjusted EBITDA percentage are calculated as a percentage of revenue.

Gross margin. The $16.8 million decrease in gross margin for the year ended December 31, ~~2017~~2020 compared to the year ended December 31, 2019 was ~~primarily attributable~~due to (1) a ~~$9.9~~$30.7 million decrease in revenues and (2) a $7.5 million increase in ~~gross operating margin~~depreciation and amortization, offset by ~~$0.9~~(3) a $21.4 million ~~higher~~decrease in cost of operations, exclusive of depreciation and amortization.

Adjusted gross margin. The $9.3 million decrease in Adjusted gross margin for the year ended December 31, 2020 compared to the year ended December 31, 2019 was due to a $30.7 million decrease in revenues, offset by a $21.4 million decrease in cost of operations, exclusive of depreciation and amortization.

Adjusted EBITDA. The $5.7 million decrease in Adjusted EBITDA for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to a $9.3 million decrease in Adjusted gross margin, partially offset by a $3.2 million decrease in selling, general and administrative expenses, excluding unit-based compensation expense, severance charges and transaction ~~expenses,~~expenses.

DCF. The $1.1 million decrease in DCF during the year ended December 31, ~~2017.~~

~~The $6.9 million, or 4.5%, decrease in Adjusted EBITDA during~~2020 compared to the year ended December 31, ~~2016~~2019 was primarily ~~attributable~~due to ~~an $11.2~~(1) a $9.3 million decrease in Adjusted gross ~~operating~~ margin and (2) a $0.7 million increase in cash interest expense, net, partially offset by ~~$4.4~~(3) a $6.3 million ~~lower~~decrease in maintenance capital expenditures and (4) a $3.2 million decrease in selling, general and administrative expenses, excluding unit-based compensation expense, severance charges and transaction ~~expenses, during~~expenses.

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Coverage Ratios. The decreases in DCF Coverage Ratio and Cash Coverage Ratio for the year ended December 31, ~~2016.~~

~~Distributable Cash Flow.~~ ~~DCF during~~2020 compared to the year ended December 31, ~~2017 was materially consistent with DCF during the year ended December 31, 2016~~2019 were primarily due to ~~$9.9 million increase~~additional distributions in ~~gross operating margin, offset by $4.8 million higher maintenance capital expenditures, $4.0 million higher cash interest expense, net and $0.9 million~~

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~~higher selling, general and administrative expenses, excluding unit-based compensation expense, severance charges and transaction expenses during the comparable period.~~

~~The $2.5 million, or 2.1%, decrease in DCF during the year ended December 31, 2016 was primarily~~2020 due to ~~$11.2 million decrease~~the conversion of 6,397,965 Class B Units, which did not participate in gross operating margin, $3.1 million higher cash interest expense, net and $1.1 million lower insurance recoveries received, offset by $8.4 million lower maintenance capital expenditures, $4.4 million lower selling, general and administrative expenses, excluding unit-based compensation expense, severance charges and transaction expenses during the comparable period.

~~Coverage Ratios. The decrease in DCF Coverage Ratio is due~~distributions, to ~~a greater number of~~ common units outstanding as of the respective record dates during the year ended December 31, 2017. The disproportionate decrease in Cash Coverage Ratio (as compared to DCF Coverage Ratio) is due to period-to-period decreases in DRIP participation.

on a one-for-one basis on July 30, 2019.

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 ~~our revolving credit facility~~the Credit Agreement and issuances of debt and equity securities, including common units under the DRIP.

We ~~believe~~typically utilize cash generated by operating activities and, where necessary, borrowings under ~~our revolving credit facility will be sufficient~~the Credit Agreement to service our debt, fund working capital, fund our estimated expansion capital expenditures, fund our maintenance capital expenditures and pay distributions ~~through 2018.~~ to our unitholders. In response to current market conditions, we have reduced our planned capital spending significantly for 2021. However, if market conditions related to COVID-19 persist, this could eventually reduce our cash generated by operating activities and increase our leverage. Covenants in the Credit Agreement and other debt instruments require that we maintain certain leverage ratios, and if we predict that we may violate those covenants in the future we could: (i) delay discretionary capital spending and reduce operating expenses; (ii) request an amendment to the Credit Agreement; (iii) reduce or suspend distributions to our unitholders; or (iv) issue equity securities, including under the DRIP.

The Credit Agreement was amended on August 3, 2020 to amend, among other things, the requirements of certain covenants and the date on which certain covenants in the Credit Agreement must be met beginning on the Amendment Effective Date until the last day of the fiscal quarter ending December 31, 2021. Please see “Revolving Credit Facility” below for additional information regarding the amendment.

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 ~~our revolving credit facility~~the Credit Agreement and issuances of debt and equity securities, including under the DRIP.

If the CDM Acquisition and other transactions described in Item 1 (“Business—Recent Developments”) are consummated, our capital expenditure requirements may increase significantly. We expect to fund any increase in capital expenditures with cash generated by operating activities and borrowings under our revolving credit facility.

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

~~Cash Flows~~

~~The following table summarizes our sources and uses of cash for the years ended December 31, 2017, 2016 and 2015 (in thousands):~~

Year Ended December 31,


2017

2016

2015
Net cash provided by operating activities

$
124,644

$
103,697

$
117,401
Net cash used in investing activities

(105,231)

(50,831)

(278,158)
Net cash provided by (used in) financing activities

(19,431)

(52,808)

160,758

~~Net cash provided by operating activities~~. The $20.9 million increase in net cash provided by operating activities for the year ended December 31, 2017 was due primarily to $9.9 million higher gross operating margin, adjustments to non-cash and other items and changes in our working capital.

The $13.7 million decrease in net cash provided by operating activities for the year ended December 31, 2016 was due primarily to $11.2 million lower gross operating margin, adjustments to non-cash and other items and changes in our working capital.

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~~Net cash used in investing activities. For the year ended December 31, 2017, net cash used in investing activities related primarily to purchases of new compression units, reconfiguration costs and related equipment.~~

For the year ended December 31, 2016, net cash used in investing activities related primarily to purchases of new compression units, reconfiguration costs and related equipment. We significantly reduced our purchases of new compression units during 2016 due to the reduced activity levels in the overall energy market.

For the year ended December 31, 2015, net cash used in investing activities related primarily to purchases of new compression units and related equipment in response to increased demand for our services and maintenance capital expenditures made to maintain or replace existing assets and operating capacity, partially offset by $1.7 million of proceeds from the disposition of equipment during 2015 and $1.2 million of proceeds from insurance recoveries on previously impaired compression units during 2015.

~~Net cash provided by financing activities~~. During 2017, we borrowed $97.5 million, on a net basis, on our revolving credit facility from which we borrow primarily to support our purchases of new compression units, reconfiguration costs and related equipment, as described above. Additionally, we made cash distributions to our unitholders of $114.1 million and paid $2.8 million in cash related to the net settlement of unit-based awards.

During 2016, we paid $43.8 million, on a net basis, on our revolving credit facility from which we borrow primarily to support our purchases of new compression units, reconfiguration costs and related equipment, as described above. During December 2016, we completed a public equity offering and utilized net proceeds of $80.9 million to reduce indebtedness outstanding under our revolving credit facility. Additionally, we paid various loan fees and incurred costs of $2.0 million related to an amendment to our revolving credit facility. During 2016, we made cash distributions to our unitholders of $87.7 million.

~~For the year ended December 31, 2015,~~ we borrowed $134.3 million, on a net basis, primarily to support our purchases of new compression units and related equipment, as described above. During 2015, we completed a public equity offering and a private placement and utilized combined net proceeds of $75.1 million to reduce indebtedness outstanding under our revolving credit facility. Additionally, in January 2015, we paid various loan fees and incurred costs of $3.4 million related to an amendment to our revolving credit facility. During 2015, we made cash distributions to our unitholders of $45.1 million.

~~Equity Offerings~~

On December 8, 2016, we closed a public offering of 5,175,000 common units at a price to the public of $16.25 per common unit. We used the net proceeds of $80.9 million (net of underwriting discounts and commission and offering expenses) to reduce the indebtedness outstanding under our revolving credit facility.

On September 15, 2015, we closed a public offering of 4,000,000 common units at a price to the public of $19.33 per common unit. We used the net proceeds of $74.4 million (net of underwriting discounts and commission and offering expenses) to reduce the indebtedness outstanding under our revolving credit facility.

On May 21, 2015, we issued 34,921 common units in a private placement for $0.7 million in a transaction that was exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as amended (the “Securities Act”). We used the proceeds from the private placement for general partnership purposes.

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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

•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.

•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, ~~2017~~2020 and ~~2016~~2019 were ~~$12.6~~$23.3 million and ~~$7.7~~$29.6 million, respectively. We currently plan to spend approximately ~~$15~~$22.0 million in maintenance capital expenditures during ~~2018,~~2021, 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 ~~current or~~ future acquisitions, we currently have budgeted between ~~$130~~$30.0 million and ~~$140~~$40.0 million in expansion capital expenditures during ~~2018.~~2021. Our expansion capital expenditures for the years ended December 31, ~~2017~~2020 and ~~2016~~2019 were ~~$116.9~~$95.6 million and ~~$40.9~~$170.3 million, respectively.

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Cash Flows

The following table summarizes our sources and uses of cash for the years ended December 31, 2020 and 2019 (in thousands):


	Year Ended December 31,
	2020		2019
Net cash provided by operating activities	$	293,198	$	300,580
Net cash used in investing activities	(105,099)		(144,490)
Net cash used in financing activities	(188,107)		(156,179)

Net cash provided by operating activities. The $7.4 million decrease in net cash provided by operating activities for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to a $5.3 million decrease in net income, as adjusted for non-cash items, and changes in other working capital.

Net cash used in investing activities. The $39.4 million decrease in net cash used in investing activities for the year ended December 31, 2020 compared to the year ended December 31, 2019 was due to (1) a $62.1 million decrease in capital expenditures for purchases of new compression units, related equipment and reconfiguration costs, offset by (2) a $19.8 million decrease in proceeds from disposition of property and equipment and (3) a $2.9 million decrease in insurance proceeds received for compression units previously damaged.

Net cash used in financing activities. The $31.9 million increase in net cash used in financing activities for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to (1) a $32.1 million decrease in net borrowings and (2) a $10.5 million increase in cash distributions paid on common units primarily due to the conversion of 6,397,965 Class B Units, which did not participate in distributions, to common units on a one-for-one basis on July 30, 2019. These changes were partially offset by a decrease in financing costs of $9.8 million due primarily to the issuance of the Senior Notes 2027 in March 2019.

Revolving Credit Facility

As of December 31, ~~2017,~~2020, we were in compliance with all of our covenants under ~~our revolving credit facility.~~the Credit Agreement. As of December 31, ~~2017,~~2020, we had outstanding borrowings under ~~our revolving credit facility~~the Credit Agreement of ~~$782.9~~$473.8 million, ~~$272.1 million~~$1.1 billion of borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of ~~$101.6~~$284.2 million. ~~The borrowing base consists~~

As of ~~eligible accounts receivable, inventory~~February 11, 2021, we had outstanding borrowings under the Credit Agreement of $498.2 million.

On the Amendment Effective Date, we amended the Credit Agreement to, among other things, increase the maximum funded debt to EBITDA ratio to (i) 5.75 to 1.00 for the fiscal quarters ending September 30, 2020 and ~~compression units. One of~~December 31, 2020, (ii) 5.50 to 1.00 for the ~~financial covenants under our revolving credit facility permits a maximum leverage ratio of (A)~~ fiscal quarters ending March 31, 2021 and June 30, 2021 and (iii) 5.25 to ~~1.0 as of~~1.00 for the ~~end of~~fiscal quarters ending September 30, 2021 and December 31, 2021 (reverting back to 5.00 to 1.00 after the Covenant Relief Period). In addition, the amendment provides that the 0.50 increase in maximum funded debt to EBITDA ratio applicable to certain future acquisitions (for the six consecutive month period in which any such acquisition occurs) is only available beginning with the fiscal quarter ending ~~December 31, 2017~~September 30, 2021, and ~~(B) 5.00~~in any case shall not increase the maximum funded debt to ~~1.0 thereafter~~EBITDA ratio above 5.50 to 1.00.

The amendment also provides that, during the Covenant Relief Period, the availability requirement in order to make restricted payments from capital contributions and from available cash are each increased from $100 million to $250 million and the availability requirement in order to make prepayments of our senior notes, any subordinated indebtedness or any other indebtedness for borrowed money is increased from $100 million to $250 million. In addition, during the Covenant Relief Period, the applicable margin for Eurodollar borrowings is increased from a range of 2.00% – 2.75% to a range of 2.25% – 3.00%. AsThe amendment further provides that the Partnership becomes guarantor of ~~February 8, 2018, we had outstanding borrowings~~the obligations of ~~$815.0 million.~~ all other guarantors under the Credit Agreement.

We expect to remain in compliance with our covenants under the Credit Agreement throughout ~~2018.~~2021. 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 ~~our revolving credit facility.~~

the Credit Agreement.

For a more detailed description of ~~our revolving credit facility~~the Credit Agreement including the covenants and restrictions contained therein, please refer to Note 710 to our consolidated financial ~~statements.~~

statements in Part II, Item 8 “Financial Statements and Supplementary Data”.

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~~Commitment Letter~~

~~In connection with~~Senior Notes

As of December 31, 2020, we had $725.0 million and $750.0 million aggregate principal amount outstanding on our Senior Notes 2026 and Senior Notes 2027, respectively.

The Senior Notes 2026 are due on April 1, 2026 and accrue interest at the ~~CDM Acquisition,~~rate of 6.875% per year. Interest on ~~January 15, 2018, we entered into a commitment letter with JPMorgan Chase Bank, N.A. and Barclays Bank PLC, as modified by~~ the ~~joinder to commitment letter and bridge fee letter entered into by the Partnership, JPMorgan Chase Bank, N.A. and Barclays Bank PLC with~~Senior Notes 2026 is payable semi-annually in arrears on each of ~~Regions Bank, Royal Bank~~April 1 and October 1.

The Senior Notes 2027 are due on September 1, 2027 and accrue interest at the rate of ~~Canada, Wells Fargo Bank, N.A., MUFG Union Bank, N.A., a member~~6.875% per year. Interest on the Senior Notes 2027 is payable semi-annually in arrears on each of ~~MUFG, a global financial group, The Bank of Nova Scotia~~March 1 and SunTrust Bank and certain affiliates of such parties (the “Commitment Letter”). The Commitment Letter provides for senior unsecured bridge loans in an aggregate amount up to $725 million (the “Bridge Loans”). The proceeds of such Bridge Loans may be used (a) to finance ~~a portion~~September 1.

For more detailed descriptions of the ~~purchase price of the CDM Acquisition~~Senior Notes 2026 and ~~(b)~~Senior Notes 2027, please refer to ~~pay fees~~Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and ~~expenses incurred in connection therewith. The availability of the borrowings is subject to the satisfaction of certain customary conditions.~~

~~Distribution Reinvestment Plan~~

Supplementary Data”.

DRIP

During the ~~year~~years ended December 31, ~~2017,~~2020 and 2019, distributions of ~~$20.3~~$1.9 million and $1.0 million, respectively, were reinvested under the DRIP resulting in the issuance of ~~1.2 million~~188,695 and 60,584 common ~~units.~~ units, respectively.

Such distributions are treated as non-cash transactions in the accompanying Consolidated Statements of Cash Flows included ~~under~~in Part ~~IV,~~II, Item 158 “Financial Statements and Supplementary Data” of this report.

~~For a more detailed description of the DRIP, please refer to~~

See Note 812 to our consolidated financial ~~statements.~~

statements in Part II, Item 8 “Financial Statements and Supplementary Data” for more information regarding the DRIP.

Total Contractual Cash Obligations

The following table summarizes our total contractual cash obligations as of December 31, ~~2017:~~

Payments Due by Period










More than

Contractual Obligations

Total

1 year

2 - 3 years

4 - 5 years

5 years

(in thousands)

Long-term debt (1)

$
782,902

$
—

$
782,902

$
—

$
—

Interest on long-term debt obligations (2)

54,622

27,088

27,534

—

—

Equipment/capital purchases (3)

122,156

119,656

2,500

—

—

Operating lease obligations (4)

2,946

1,517

1,357

72

—

Total contractual cash obligations

$
962,626

$
148,261

$
814,293

$
72

$
—

2020 (in thousands):


	Payments Due by Period
Contractual Obligations	Total		Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years
Long-term debt (1)	$	1,948,810	$	—	$	473,810	$	—	$	1,475,000
Interest on long-term debt obligations (2)	676,030		119,607		225,563		202,813		128,047

Operating and finance lease obligations (3)	31,235		4,808		8,253		6,910		11,264
Total contractual cash obligations	$	2,656,075	$	124,415	$	707,626	$	209,723	$	1,614,311

~~(1)~~

~~We assumed that the amount outstanding under our revolving credit facility at December 31, 2017 would be repaid in January 2020, the maturity date of the facility.~~

________________________

~~(2)~~

~~Represents future interest payments under our revolving credit facility based on the interest rate as of December 31, 2017 of 3.46%.~~

(1)We assumed that the amount outstanding under the Credit Agreement at December 31, 2020 would be repaid in April 2023, the maturity date of the facility. The $725.0 million aggregate principal amount of our Senior Notes 2026 outstanding is due April 1, 2026, and the $750.0 million aggregate principal amount of our Senior Notes 2027 outstanding is due September 1, 2027.

~~(3)~~

~~Represents commitments for new compression units that are being fabricated, and is a component of our overall projected expansion capital expenditures during 2018 of $130 million to $140 million.~~

(2)Represents future interest payments under the Credit Agreement based on outstanding borrowings as of December 31, 2020, and the effective interest rate and unused commitment fee as of December 31, 2020 of 2.95% and 0.375%, respectively, and interest payments on our $1.5 billion aggregate principal amount of the Senior Notes.

~~(4)~~

~~Represents commitments for future minimum lease payments on noncancelable leases.~~

(3)Represents commitments for future minimum lease payments on noncancelable operating and finance leases.

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

Off-Balance Sheet Arrangements

We have no off-balance sheet financing activities. Please refer to Note ~~13 of~~17 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” 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

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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,

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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 ~~using~~when obligations under the ~~following criteria: (i) persuasive evidence~~terms of ~~an arrangement; (ii) delivery has occurred~~a contract with our customer are satisfied; generally this occurs with the transfer of our services or goods. Revenue is measured as the amount of consideration we expect to receive in exchange for providing services ~~have been rendered; (iii)~~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 ~~customer’s price is fixed or determinable; and (iv) collectability is reasonably assured.~~

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 ~~compression~~ services are provided to our customers. ~~Compression~~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 ~~are~~ 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.~~month, and payment is generally due 30 days after receipt of our invoice. Amounts invoiced in advance are recorded as deferred revenue ~~on the balance sheet~~ until earned, at which time itthey 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 ~~as revenue.~~

~~Revenue~~at the point in time the part is transferred or service is provided and control is transferred to the ~~associated expense from installation services, which includes~~customer. At such time, the ~~installation~~customer has the ability to direct the use of ~~stations for~~the benefits of such part or service after we have performed our ~~customers,~~services. We bill upon completion of the service or transfer of the parts, and payment is ~~recorded using the percentage-of-completion method measured using the efforts-expended method. In applying the percentage-of-completion method, we use the percentage~~generally due 30 days after receipt of ~~total workflows to date that have been completed relative to estimated total workflows to be completed in order to estimate the progress towards completion to determine the~~our invoice. The amount of consideration we receive and revenue ~~and profit to~~we recognize is based upon the invoice amount. There are typically no material obligations for ~~each contract.~~

The percentage-of-completion method of revenue recognition requires us to make estimates of contract revenues and costs to complete our projects. In making such estimates, management judgments are required to evaluate significant assumptions including the cost of materials and labor, expected labor productivity, the impact of potential variances in schedule completion, the amount of net contract revenues and the impact of any penalties, claims, change orders,returns, refunds, or ~~performance incentives.~~

warranties. Our standard contracts do not usually include material variable or non-cash consideration.

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.

~~Goodwill—~~

Goodwill – Impairment Assessments

We evaluate goodwill for impairment annually on October 1 ~~of the fiscal year~~ 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

During the ~~growth assumptions embodied in the current year impairment testing prove inaccurate, we could incur an impairment charge in the future.~~

~~Table~~first quarter of ~~Contents~~

On October 1, 2017 and 2016, we performed our annual goodwill impairment test, wherein we compared the estimated fair value of our single reporting unit to its carrying value. The estimated fair value of our reporting unit, measured based on market capitalization, as of October 1, 2017 and 2016 exceeded its carrying value in excess of 20% and we concluded that our goodwill was not impaired. We recorded no goodwill impairment charges for the years ended December 31, 2017 and 2016. ~~We had approximately $35.9 million of goodwill recorded on the balance sheet as of December 31, 2017 and 2016.~~

~~On October 1, 2015, we performed our annual goodwill impairment test and concluded that our goodwill was not impaired. We updated our impairment test as of December 31, 2015 as~~2020 certain potential impairment indicators were identified, ~~during the fourth quarter,~~ specifically ~~(1)~~(i) the decline in the market price of our common units, ~~(2)~~(ii) the ~~sustained~~ decline in global commodity prices and ~~(3)~~(iii) the ~~decline in performance of the Alerian MLP Index,~~COVID-19 pandemic; which together indicated the reporting unit had a fair value that was less than its carrying value as of December 31, 2015. We prepared a quantitative assessment as of December 31, 2015 which indicated that the calculated fair value was less than the carrying value. We subsequently performed ~~“step two” impairment test for our reporting unit under which we treated our business as if it had been acquired in a business combination as of December 31, 2015 and assigned~~ the fair value of the reporting unit ~~to all~~was less than its carrying amount as of ~~our assets~~March 31, 2020.

We performed a quantitative goodwill impairment test as of March 31, 2020 and ~~liabilities. The carrying~~determined fair value using a weighted combination of the ~~goodwill was compared to~~income approach and the ~~new implied~~market approach. Determining fair value of ~~goodwill~~a reporting unit requires judgment and

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use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, EBITDA margins, weighted average costs of capital and future market conditions, among others. We believe the estimates and assumptions used 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 ~~was recognized~~is indicated. Under the income approach, we determined fair value based on estimated future cash flows, including estimates for capital expenditures, discounted to present value using the ~~amount~~risk-adjusted industry rate, which reflects the overall level of inherent risk of the ~~carrying~~Partnership. Cash flow projections were derived from four-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 market approach, we determined fair value by applying valuation multiples of comparable publicly-traded companies to the projected EBITDA of the Partnership and then averaging that estimate with similar historical calculations using a three-year average. In addition, we estimated a reasonable control premium representing the incremental value that ~~exceeded the implied fair value.~~ would accrue to us if we were to be acquired.

Based on ~~that step two~~the quantitative goodwill impairment test described above, our carrying amount exceeded fair value and as a result, we recognized a ~~non-cash~~goodwill impairment ~~charge~~ of ~~$172.2 million. We had approximately $35.9~~$619.4 million for the year ended December 31, 2020.

As of October 1, 2019, we performed a qualitative assessment of relevant events and circumstances potentially indicating the likelihood of goodwill ~~remaining on~~impairment. The qualitative assessment included weighting such factors as (i) macroeconomic conditions, (ii) industry and market considerations, (iii) cost factors, (iv) overall financial performance of the ~~balance sheet as~~reporting unit, (v) other relevant entity-specific events, and (vi) consideration of ~~December 31, 2015 following this impairment.~~

~~As discussed above, estimates~~whether there was a sustained decrease in the price of ~~fair value can be affected by a variety~~our units. Upon completion of ~~external and internal factors. Volatility in crude oil prices can cause disruptions in global energy industries and markets. Potential events or circumstances~~our qualitative assessment, we concluded that ~~could reasonably be expected to negatively affect the key assumptions we used in estimating~~it was not more likely than not that the fair value of our single reporting unit ~~include~~was less than its carrying value and that our goodwill was not impaired for 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 remaining $35.9 million 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.

year ended December 31, 2019.

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.

For the years ended December 31, 2020 and 2019, we evaluated the future deployment of our idle fleet under current market conditions and determined to retire 37 and 33 compressor units, respectively, for a total of approximately 15,000 and 11,000 horsepower, respectively, that were previously used to provide compression services in our business. As a result, we recorded impairments of compression equipment of $8.1 million and $5.9 million for the years ended December 31, 2020 and 2019, respectively. The primary causes for these impairments 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 current quoting criteria without excessive retrofitting costs. These compression units were written down to their respective estimated salvage values, if any.

Allowance for Credit Losses

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~~Allowances and Reserves~~

We maintain an allowance for ~~doubtful~~credit losses for our two financial assets, (i) trade accounts receivable and (ii) net investment in lease related to our sales-type lease, based on specific customer collection issues and historical experience. ~~The~~

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Our determination of the allowance for ~~doubtful accounts~~credit losses requires us to make estimates and judgments regarding our customers’ ability to pay amounts ~~due. On an ongoing basis, we conduct an evaluation~~due and is the same process for both of our financial assets as they have similar risk characteristics. We continuously evaluate the financial strength of our customers based on ~~payment history,~~collection experience, the overall business climate in which our customers operate and specific identification of customer ~~bad debt~~credit losses 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~~publicly available materials regarding our customers’ industries, including the solvency of various companies in the industry.

Recent Accounting Pronouncements

We qualify as an emerging growth company under Section 109 of the Jumpstart Our Business Startups, (“JOBS”) Act. An emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act

Please see Part II, Item 8 “Financial Statements and Supplementary Data”, Note 2 for ~~complying with new or revised accounting standards. In other words, an emerging growth company can delay~~discussion on the adoption of ~~certain accounting standards until those standards would otherwise apply to private companies. However, we have chosen to “opt out”~~Accounting Standards Update 2016-13 Financial Instruments – Credit Losses (“Topic 326”): Measurement of ~~such extended transition period,~~ Credit Losses on Financial Instrumentsand ~~as a result, are compliant with new or revised accounting standards on the relevant dates on which adoption of such standards is required~~Note 18 for non-emerging growth companies. Section 108 of the JOBS Act provides that our decision to opt out of the extended transition period for complying with new or revised accounting standards is irrevocable.

~~For more discussion on~~other specific recent accounting pronouncements affecting ~~us, please see Note 12 to our consolidated financial statements.~~

us.

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. ~~Lower~~Sustained low natural gas ~~prices~~ or crude oil prices over the long term could result in a decline in the production of natural gas or crude oil, 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%one percent decrease in average revenue generating horsepower ~~of our active fleet~~ during the year ended December 31, ~~2017~~2020 would have resulted in a decrease of approximately ~~$2.7~~$6.3 million and ~~$1.8~~$4.4 million in our revenue and Adjusted gross ~~operating~~ margin, respectively. ~~Gross operating~~Adjusted gross margin is a non-GAAP financial measure. For a reconciliation of Adjusted gross ~~operating~~ margin to ~~net income (loss),~~gross margin, its most directly comparable financial measure, calculated and presented in accordance with GAAP, please read Part II, Item 6 ~~(“—~~“Selected Financial Data – Non-GAAP Financial Measures”). Please also read Part I, Item 1A ~~(“Risk Factors—~~“Risk Factors – Risks Related to Our ~~Business—~~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”).~~

unitholders.”

Interest Rate Risk

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

Credit Agreement.

As of December 31, ~~2017,~~2020, we had ~~approximately $782.9~~$473.8 million of variable-rate outstanding indebtedness at a weighted-average interest rate of ~~3.14%~~2.95%. A 1%one percent increase or decrease in the effective interest rate on our variable-rate outstanding debt as of December 31, ~~2017~~2020 would result in an annual increase or decrease in our interest expense of approximately ~~$7.8~~$4.7 million.

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For further information regarding our exposure to interest rate fluctuations on our debt obligations, see Note 710 to our consolidated financial ~~statements.~~statements in Part II, Item 8 “Financial Statements and Supplementary Data”. 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. We cannot currently predict the duration or magnitude of the effects of the COVID-19 pandemic and crude oil market volatility on our customers and their ability to pay amounts due. If any significant customer of ours should have credit or financial problems resulting in a delay or failure to ~~repay~~pay the amount it owes us, it could have a material adverse effect on our business, financial condition, results of operations orand cash flows.

Please see Part II, Item 1A. “Risk Factors – Risk Related to Our Business – 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.”

ITEM 8.Financial Statements and Supplementary Data

The financial statements and supplementary information specified by this Item are presented in Part IV, Item ~~15.~~

15 “Exhibits and Financial Statement Schedules”.

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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 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, ~~2017~~2020 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, ~~2017.~~2020. 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, ~~2017,~~2020, our internal control over financial reporting was effective. ~~This report does not~~

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~~include~~Grant Thornton LLP, an ~~attestation report of the company’s~~independent registered public accounting firm ~~due to a transition period~~that audited our consolidated financial statements included herein, has also audited the effectiveness of our internal control over financial reporting as of December 31, 2020, 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, 2020, based on criteria established in the 2013 Internal Control—Integrated Framework issued by ~~rules~~the Committee of Sponsoring Organizations of the ~~SEC~~Treadway Commission (“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, 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 ~~emerging growth companies.~~

the year ended December 31, 2020, and our report dated February 16, 2021 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 Annual 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 16, 2021

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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

~~None.~~

None.

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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. ~~Our general partner~~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. ~~Our general partner has~~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 ~~that manages our business.~~

established by 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.

The ~~board of directors of our general partner~~Board is ~~currently~~ comprised of ~~eight~~nine members, ~~all~~eight of whom ~~have been~~were designated by ~~USA Compression Holdings~~ETO and ~~three~~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 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). EIG Management has designated Matthew S. Hartman to serve on the Board. Three members of the Board are independent as defined under the independence standards established by the ~~NYSE. The~~NYSE and the SEC. Although the NYSE does not require a ~~listed~~publicly traded limited partnership like us to have a majority of independent directors on the ~~board of directors of our general partner~~Board or to establish a compensation committee or a nominating ~~committee.~~

~~The non-management~~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 ~~our general partner’s board of directors regularly meet in executive session without~~ the ~~management members of our general partner’s board of directors. Mr.~~Board.

Eric D. Long, our President and Chief Executive Officer (“CEO”), is currently the only management member of ~~our general partner’s board~~the Board. The non-management members of ~~directors. Forrest E. Wylie~~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 ~~our general partners’ board of directors~~the Board by mail in care of the General Counsel and Secretary at USA Compression Partners, LP, ~~100~~111 Congress Avenue, Suite ~~450,~~2400, Austin, Texas 78701. Such communications should specify the intended recipient or recipients. Commercial solicitations or similar communications will not be ~~forwarded.~~

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 of directors of our general partner~~Board has determined that ~~Robert F. End, Jerry L. Peters,~~Matthew S. Hartman, Glenn E. Joyce and ~~Forrest E. Wylie~~William S. Waldheim are independent directors under the standards established by the NYSE and the Exchange Act. The ~~board of directors of our general partner~~Board considered all relevant facts and circumstances and applied the ~~independent~~independence guidelines of the NYSE and the Exchange Act in determining that none of these directors has any material relationship with us, our management, ~~our general partner~~the General Partner or its affiliates or our subsidiaries.

~~Effective October 15, 2017, John D. Chandler resigned from~~

Mr. Hartman is a Managing Director at EIG, and, since the board of directors of our general partner for personal reasons as he accepted a position with another publicly traded company. Mr. Chandler’s resignation did not arise from any disagreement with the general partner, its management or its Board of Directors on any matter relating to the general partner’s, or the Partnership’s, operations, policies or practices, the general directionTransactions Date, EIG owns over 80% of the ~~general partner or~~Preferred Units and Warrants in the ~~Partnership, or Mr. Chandler’s role on the~~Partnership. The Board determined that EIG’s ownership of Directors. Effective October 16, 2017, the board of directors of our general partner appointed Jerry L. Peters to serve as a director on the board of directors of our general partner to fill the vacancy created by Mr. Chandler’s resignation. As Mr. Chandler served as the chairman of the Audit Committee, Mr. Peters was appointed by the board of directors of our general partner to the audit committee of the board of directors of our general partnerPreferred Units and ~~to serve as the chairman of the audit committee.~~

In October 2014, Mr. Chandler was appointed to serve on the board of directors and the audit committee of one of our customers. During the period of Mr. Chandler’s directorship for the year ended December 31, 2017, subsidiaries of this customer made compression service payments to us of approximately $5.7 million. The board of directors of our general partner made a determination that the relationship with this customerWarrants did not preclude the independence of Mr. ~~Chandler.~~

~~Since September 2012, Mr. Peters has served~~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~~Board to significantly influence or control its decision making or materially influence the management or operation of ~~directors~~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.

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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 ~~one~~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 ~~customers. During~~policies brought to its attention on an ad hoc basis. Additionally, the ~~period of Mr. Peters’ directorship for~~Compensation Committee reviews our overall compensation program and its effectiveness at both linking executive pay to performance and aligning the ~~year ended December 31, 2017, subsidiaries of this customer made compression service payments to us of approximately $0.3 million. The board of directors~~interests of our ~~general partner made a determination that~~executives and our unitholders.

Committees of the ~~relationship with this customer did not preclude~~Board of Directors

Audit Committee. The Board appoints the ~~independence of Mr. Peters.~~

Audit Committee,~~. The board of directors of our general partner has appointed an audit committee~~ which is comprised solely of directors who meet the independence and experience standards established by the NYSE and the Exchange Act. The

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~~audit committee~~ Audit Committee consists of ~~Robert F. End, Jerry L. Peters~~Messrs. Hartman, Joyce and ~~Forrest E. Wylie.~~Waldheim, and Mr. ~~Peters~~Waldheim serves as chairman of the ~~audit committee.~~Audit Committee. The ~~board of directors of our general partner has~~Board determined that Mr. ~~Peters~~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. ~~End, Peters~~Hartman, Joyce and ~~Wylie~~Waldheim is “independent” within the meaning of the applicable NYSE and Exchange Act rules ~~regulating~~governing audit committee independence. The ~~audit committee~~Audit Committee assists the ~~board of directors of our general partner~~Board in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements ~~and~~as well as the effectiveness of our corporate policies and internal controls. The ~~audit committee~~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~~Audit Committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm ~~will be~~is given unrestricted access to the ~~audit committee. A copy of the~~Audit Committee.

The charter of the ~~audit committee~~Audit Committee (the “Audit Committee Charter”) is available under the Investor Relations tab on our website at usacompression.com. We ~~also~~ will provide a copy of the ~~charter of the audit committee~~Audit Committee Charter to any of our unitholders without charge upon written request to Investor Relations, ~~100~~111 Congress Avenue, Suite ~~450,~~2400, Austin, TX 78701.

Compensation ~~Committee~~.Committee. The NYSE does not require a listed limited partnership like us to have a compensation committee. However, the ~~board of directors of our general partner has~~Board established ~~a compensation committee~~the Compensation Committee to, among other things, oversee ~~the~~our compensation ~~plans~~program described below in Part III, Item 11 ~~(“Executive Compensation”).~~“Executive Compensation.” The ~~compensation committee~~Compensation Committee consists of ~~Robert F. End, William H. Shea, Jr.~~Messrs. Joyce and ~~Olivia C. Wassenaar.~~Waldheim and is chaired by Mr. Joyce. The ~~compensation committee~~Compensation Committee establishes and reviews general policies related to our compensation and ~~benefits. The compensation committee has the responsibility to determine~~benefits and ~~make~~is responsible for making recommendations to the ~~board of directors of our general partner~~Board with respect to the compensation and benefits of the ~~board of directors~~Board. In addition, the Compensation Committee administers the USA Compression Partners, LP 2013 Long-Term Incentive Plan, as amended and ~~executive officers of our general partner. A copy of~~as may be further amended or replaced from time to time (the “LTIP”).

Under the charter of the ~~compensation committee~~Compensation Committee (the “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 2020, 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 Compensation Committee Charter is available under the Investor Relations tab on our website at usacompression.com. We ~~also~~ will provide a copy of the ~~charter of the compensation committee~~Compensation Committee Charter to any of our unitholders without charge upon written request to Investor Relations, ~~100~~111 Congress Avenue, Suite ~~450,~~2400, Austin, TX 78701.

Conflicts ~~Committee~~.Committee. As set forth in the ~~limited liability company agreement of our general partner, our general partner~~GP LLC Agreement, the General Partner may, from time to time, establish a conflicts committee to which the ~~board of directors of our general partner~~Board will appoint independent directors and which may be asked to review specific matters that the ~~board of directors of our general partner~~Board believes may involve conflicts of interest between us, our limited partners and ~~USA Compression Holdings. The~~Energy Transfer. Such conflicts committee will determine the resolution of the conflict of interest in any ~~manner~~matter referred to it in good faith. The members of the conflicts committee may not be officers or employees of ~~our general partner~~the General Partner or directors, officers or employees of its affiliates, including ~~USA Compression Holdings,~~Energy Transfer, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on ~~an audit committee of a board of directors of our general partner,~~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 ~~our general partner~~the General Partner of any duties it may owe us or our unitholders.

~~Section 16(a) Beneficial Ownership Reporting Compliance~~

Section 16(a) of the Exchange Act requires the board of directors and executive officers of our general partner, and persons who own more than 10 percent of a registered class of our equity securities, to file with the SEC and any exchange or other system on which such securities are traded or quoted initial reports of ownership and reports of changes in ownership of our common units and other equity securities. Officers, directors and greater than 10 percent unitholders are required by the SEC’s regulations to furnish to us and any exchange or other system on which such securities are traded or quoted with copies of all Section 16(a) forms they filed with the SEC. To our knowledge, based solely on a review of the copies of such reports furnished to us, we believe that all reporting obligations of the officers and directors of our general partner and greater than 10 percent unitholders under Section 16(a) were satisfied during the year ended December 31, 2017.

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Corporate Governance Guidelines and Code of Ethics

The ~~board of directors of our general partner~~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 of directors of our general partner~~Board and its committees. The ~~board of directors of our general partner~~Board has also adopted a Code of Business Conduct and Ethics (the “Code”) that applies to ~~our general partner~~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. ~~Copies~~We intend to post any amendments to the Code, or waivers of ~~the Corporate Governance~~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 ~~also~~ will provide copies of the ~~Corporate Governance~~ Guidelines and the Code to any of our unitholders without charge upon written request to Investor Relations, ~~100~~111 Congress Avenue, Suite ~~450,~~2400, Austin, TX 78701.

~~Reimbursement of Expenses of Our General Partner~~

~~Our general partner will~~

Note that the preceding internet addresses are for informational purposes only and are not ~~receive any management fee~~intended to be hyperlinked. Accordingly, no information found on or ~~other compensation for its management of us. Our general partner and its affiliates will be reimbursed for all expenses incurred~~provided at those internet addresses or on our ~~behalf, including the compensation of employees of our~~website in general ~~partner~~is intended or ~~its affiliates that perform services on our behalf. These expenses include all expenses necessary or appropriate~~deemed to the conduct of our business and that are allocable to us. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. There is no cap on the amount that may be ~~paid or reimbursed to our general partner or its affiliates for compensation or expenses incurred on our behalf.~~

incorporated by reference herein.

Directors and Executive Officers

The following table shows information as of February ~~8, 2018~~11, 2021 regarding the current directors and executive officers of USA Compression GP, LLC.

Name

Age

Position with USA Compression GP, LLC

Eric D. Long

President and Chief Executive Officer and Director

~~William G. Manias~~

~~Vice President and Chief Operating Officer~~

Matthew C. Liuzzi

Vice President, Chief Financial Officer and Treasurer

Eric Scheller

Vice President and Chief Operating Officer

Christopher W. Porter

Vice President, General Counsel and Secretary

~~David A. Smith~~

~~Vice President and President, Northeast Region~~

Sean T. Kimble

Vice President, Human Resources

~~Jerry L. Peters~~

Christopher R. Curia

Director

~~Jim H. Derryberry~~

Matthew S. Hartman

Director

~~Robert F. End~~

Glenn E. Joyce

Director

~~William H. Shea, Jr.~~

Thomas E. Long

Director

~~Olivia C. Wassenaar~~

Thomas P. Mason

Director

~~Forrest E. Wylie~~

Matthew S. Ramsey

Director

~~Michael A. Wichterich~~

William S. Waldheim

Director

Bradford D. Whitehurst

Director

The directors of ~~our general partner~~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 of directors of our general partner.~~Board. There are no family relationships among any of the directors or executive officers of ~~our general partner.~~

the General Partner.

Eric D. Long has served as our President and ~~Chief Executive Officer~~CEO since September 2002 and has served as a director of ~~USA Compression GP, LLC~~the General Partner since June 2011. Mr. Long co-founded USA Compression in 1998 and has over 3540 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

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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 3540 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 of directors of our general partner.~~

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

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

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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.

Eric A. Scheller has served as our Vice President, Chief Operating Officer since June 2020. Prior to that, Mr. Scheller served as our Vice President—Fleet Operations since April 2018, and prior to that was our Vice President, Operations & Performance Management beginning in August 2015. Prior to joining us, Mr. Scheller was a Director at Sapient Global Markets since August 2013. Before Sapient, Mr. Scheller was a consultant in private practice advising midstream and chemicals firms from January 2012 to July 2013. Prior to that, he held several positions with Enterprise Products Partners LP from November 2004 to December 2011, most recently as Regional Director, Pipeline & Storage Services. Mr. Scheller holds a B.S. in Chemical Engineering (Math minor), a Masters of Chemical Engineering and an M.B.A., all from the University of Houston. Mr. Scheller is also a CFA ® charterholder.

Christopher W. Porterhas 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 ~~Kenyon~~ 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.

~~David A. Smith~~ has served as our President, Northeast Region since joining us in November 1998 and was appointed corporate Vice President in June 2011. Mr. Smith has approximately 20 years of experience in the natural gas compression industry, primarily in operations and sales. From 1985 to 1989, Mr. Smith was a sales manager for McKenzie Corporation, a 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 associates 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 ~~comes~~brings to us ~~with~~ over ~~twenty~~twenty-five years of human resources leadership experience. Prior to joining ~~the company,~~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.

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~~Jerry L. Peters~~ ~~has served as a director of USA Compression GP, LLC since October 2017. Additionally,~~ Mr. Peters serves as the chairman and financial expert of the Audit Committee of our general partner. Mr. Peters served as the Chief Financial Officer of Green Plains Inc., a publicly traded vertically-integrated ethanol producer, from June 2007 until his retirement in September 2017. In 2015, Mr. Peters was appointed Chief Financial Officer and Director of the general partner of Green Plains Partners LP, a publicly traded partnership engaged in fuel storage and transportation services. He retired from his role as Chief Financial Officer of the general partner of Green Plains Partners LP in September 2017, but remains on the board of directors. Prior to joining Green Plains, Mr. Peters served as Senior Vice President—Chief Accounting Officer for ONEOK Partners, L.P. from May 2006 to April 2007, as its Chief Financial Officer from July 1994 to May 2006, and in various senior management roles prior to that. Prior to joining ONEOK Partners in 1985, he was employed by KPMG LLP as a certified public accountant. Beginning September 2012, Mr. Peters serves on the board of directors, and as chairman of the audit committee, of the general partner of Summit Midstream Partners, LP, a publicly traded partnership focused on midstream energy infrastructure assets. Mr. Peters received his Master of Business Administration from Creighton University with a Finance emphasis and a Bachelor of Science degree in Business Administration fromKimble also completed the University of ~~Nebraska—Lincoln.~~

~~Mr. Peters’ experience serving on the board of directors of publicly traded limited partnerships, including as chairman of the audit committee,~~Michigan’s Strategic HR and ~~his financial expertise are key attributes, among others, that make him well qualified to serve on the board of directors of our general partner.~~

~~Jim H. Derryberry~~Strategic Collective Bargaining Programs.

Christopher R. Curia has ~~served as a director of USA Compression GP, LLC since January 2013. From February 2005 to October 2006, Mr. Derryberry~~ served on the ~~board of directors of Magellan GP, LLC, the general partner of Magellan Midstream Partners, L.P.~~Board since April 2018. Mr. Derryberry served as chief operating officer and chief financial officer of Riverstone Holdings, LLC until 2006 and currently serves as a special advisor. Prior to joining Riverstone, Mr. Derryberry was a managing director of J.P. Morgan, where he served as head of the Natural Resources and Power Group. Before joining J.P. Morgan, Mr. Derryberry was in the Goldman Sachs Global Energy and Power Group where he was responsible for mergers and acquisitions, capital markets financing and the management of relationships with major energy companies. He has also served as an advisor to the Russian government for energy privatization. Mr. Derryberry has served as a member of the Board of Overseers for the Hoover Institution at Stanford University and is a member of the Engineering Advisory Board at the University of Texas at Austin. He received his B.S. and M.S. degrees in engineering from the University of Texas at Austin and earned an M.B.A. from Stanford University.

Mr. Derryberry brings significant knowledge and expertise to the board of directors of our general partner from his service on other boards and his years of experience in our industry including his useful insight into investments and proven leadership skills as a managing director of Riverstone Holdings, LLC. As a result of his experience and skills, we believe Mr. Derryberry is a valuable member of the board of directors of our general partner.

~~Robert F. End~~ has served as a director of USA Compression GP, LLC since November 2012. Mr. End served as a director of Hertz Global Holdings, Inc. from December 2005 until August 2011. Mr. End was a Managing Director of Transportation Resource Partners, a private equity firm from 2009 through 2011. Prior to joining TRP in 2009, Mr. End had been a Managing Director of Merrill Lynch Global Private Equity Division (“MLGPE”), the private equity arm of Merrill Lynch & Co., Inc., where he served as Co-Head of the North American Region, and a Managing Director of Merrill Lynch Global Private Equity, Inc., the Manager of ML Global Private Equity Fund, L.P., a proprietary private equity fund which he joined in 2004. Previously, Mr. End was a founding Partner and Director of Stonington Partners Inc., a private equity firm established in 1994. Prior to leaving Merrill Lynch in 1994, Mr. End was a Managing Director of Merrill Lynch Capital Partners, Merrill Lynch’s private equity group. Mr. End joined Merrill Lynch in 1986 and worked in the Investment Banking Division before joining the private equity group in 1989. Mr. End received his A.B. from Dartmouth College and his M.B.A. from the Tuck School of Business Administration at Dartmouth College.

Mr. End brings significant knowledge and expertise to the board of directors of our general partner from his service on other boards and his years of experience with private equity groups, including his useful insight into investments and business development and proven leadership skills as Managing Director of MLGPE. As a result of this experience and resulting skills set, we believe Mr. End is a valuable member of the board of directors of our general partner.

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~~William H. Shea, Jr~~. has served as a director of USA Compression GP, LLC since June 2011. Mr. Shea served as the chairman of the board of directors, President and Chief Executive Officer of Niska Gas Storage Partners LLC from May 2014 to July 2016. Previously, Mr. Shea served as the President and Chief Operating Officer of Buckeye GP LLC and its predecessor entities (“Buckeye”), from July 1998 to September 2000, as President and Chief Executive Officer of Buckeye from September 2000 to July 2007, and Chairman from May 2004 to July 2007. From August 2006 to July 2007, Mr. Shea served as Chairman of MainLine Management LLC, the general partner of Buckeye GP Holdings, L.P., and as President and Chief Executive Officer of MainLine Management LLC from May 2004 to July 2007. Mr. Shea served as a director of Penn Virginia Corp. from July 2007 to March 2010, and as President and Chief Executive Officer of the general partner of Penn Virginia GP Holdings, L.P. from March 2010 to October 2013 and as Chief Executive Officer of the general partner of PVR Partners, L.P. (“PVR”), from March 2010 to October 2013. Mr. SheaCuria has also served as a director of Kayne Anderson Energy Total Return Fund, Inc., and Kayne Anderson MLP Investment Company since March 2008 and Niska Gas Storage Partners LLC from May 2010 to July 2016. Mr. Shea has an agreement with Riverstone, pursuant to which he has agreed to serve on the boards of certain Riverstone portfolio companies. Mr. Shea received his B.A. from Boston College and his M.B.A. from the University of Virginia.

Mr. Shea’s experiences as an executive with both PVR and Buckeye, energy companies that operate across a broad spectrum of sectors, including coal, natural gas gathering and processing and refined petroleum products transportation, have given him substantial knowledge about our industry. In addition, Mr. Shea has substantial experience overseeing the strategy and operations of publicly traded partnerships. As a result of this experience and resulting skill set, we believe Mr. Shea is a valuable member of the board of directors of our general partner.

~~Olivia C. Wassenaar~~ has served as a director of USA Compression GP, LLC since June 2011. Ms. Wassenaar was an Associate with Goldman, Sachs & Co. in the Global Natural Resources investment banking group from July 2007 to August 2008, where she focused on mergers, equity and debt financings and leveraged buyouts for energy, power and renewable energy companies. Ms. Wassenaar joined Riverstone in September 2008 as Vice President, and has served as a Principal from May 2010 to February 2014 and as a Managing Director since February 2014. In this capacity, she invests in and monitors investments in the midstream and exploration & production sectors of the energy industry. Ms. Wassenaar has also served on the board of directors of Northern Blizzard Resources Inc. from 2011 to 2017 and on the board of directors of the general partner of ~~Niska Gas Storage~~Sunoco LP (NYSE: SUN) since August 2014 and as its Executive Vice President-Human Resources since April 2015. Mr. Curia joined ETO in July 2008 and was appointed the Executive Vice President and Chief Human Resources Officer of the general partner 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 ~~LLC from July~~and is the co-head of EIG’s midstream investment team. In this capacity, he invests in and monitors energy midstream investments. Prior to joining EIG in 2014, ~~to July 2016,~~Mr. Hartman served in various roles within the Citigroup and UBS investment banking divisions, where he advised on mergers as well as ~~various private portfolio companies sponsored by Riverstone. Ms. Wassenaar~~equity and debt financings for midstream energy companies. Mr. Hartman also previously worked in Ernst & Young’s tax practice. Mr. Hartman received ~~her A.B., magna cum laude,~~a B.B.A. and B.P.A. from ~~Harvard College~~Oklahoma Baptist University and ~~earned~~ an M.B.A. from the ~~Wharton School~~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 ~~University~~international regions of ~~Pennsylvania.~~

~~Ms. Wassenaar’s~~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 ~~evaluating financial and strategic options and~~senior human resources leadership positions in the ~~operations~~energy industry.

Table of ~~companies in our industry and as an investment banker make her a valuable member of~~Contents

Thomas E. Long has served on the Board since April 2018. He has also served on the board of directors of ~~our general partner.~~

~~Forrest E. Wylie~~ ~~has served as a director of USA Compression GP, LLC since March 2013.~~ ~~Mr. Wylie is also a Senior Operating Partner at Stonepeak Infrastructure Partners and has served in such role since October 2013.~~ ~~Mr. Wylie served as the Non-Executive Chairman of the board of directors of Buckeye GP LLC,~~ the general partner of ~~Buckeye Partners, L.P.,~~Sunoco LP since May 2016. Mr. Long was appointed as Co-Chief Executive Officer of the general partner of ET LP effective January 2021. Mr. Long previously served as the Chief Financial Officer of the general partner of ET LP from February ~~2012 to August 2014. He served as Chairman of the Board, CEO and a director of Buckeye GP LLC from June 2007 to February 2012.~~2016 until January 2021. Mr. ~~Wylie~~Long has also served as a director of the general partner of ~~Buckeye~~ET LP since April 2019. Mr. Long also serves as Co-Chief Executive Officer of ETO’s general partner and was previously Chief Financial Officer of ETO’s general partner. Mr. Long also served as the Chief Financial Officer and as a director of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Long also served as Executive Vice President and Chief Financial Officer of Regency GP ~~Holdings L.P., the former parent company~~LLC from November 2010 to April 2015. From May 2008 to November 2010, Mr. Long served as Vice President and Chief Financial Officer of ~~Buckeye (“BGH”) from June 2007 until the merger of BGH with Buckeye Partners, L.P. on November 2010.~~Matrix Service Company. Prior to ~~his appointment,~~joining Matrix, he served as Vice President and Chief Financial Officer of DCP Midstream Partners LP, 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 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 became Executive Vice President and General Counsel of the general partner of ET LP in December 2015, and has served as the Executive Vice President, General Counsel and President - LNG of the general partner of ET LP since October 2018 following the merger of ET LP and ETO. Mr. Mason also served as a director of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Mason previously served as Senior Vice President, General Counsel and Secretary of ETO’s general partner from April 2012 to December 2015, as 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 was appointed as a director of the general partner of ET LP in July 2012 and as a director of ETO’s general partner in November 2015. Mr. Ramsey has been the Chief Operating Officer of the general partner of ET LP since October 2018 following the merger of ET LP and ETO, and currently serves as President and Chief Operating Officer of ETO’s general partner since November 2015. Mr. Ramsey also served as President and Chief Operating Officer and Chairman of ~~Pacific Energy Management LLC, an entity affiliated with Pacific Energy~~the board of directors of PennTex Midstream Partners, ~~L.P., a refined product and crude oil pipeline and terminal partnership,~~LP’s general partner from ~~March 2005 until Pacific Energy Partners, L.P. merged with Plains All American, L.P. in~~ November ~~2006.~~2016 to July 2017. Since August 2014, Mr. ~~Wylie was President and CFO of NuCoastal Corporation, a midstream energy company, from May 2002 until February 2005. From November 2006 to June 2007, Mr. Wylie was a private investor. Mr. Wylie~~Ramsey has served on the board of directors ~~and~~of the ~~audit committee~~general partner of ~~Coastal Energy Company, a publicly traded entity, until April 2011. Mr. Wylie also~~Sunoco LP, having served on board of directors and compensation and nominating and corporate governance committees of Eagle Bulk Shipping Inc. until May 2010. Mr. Wylie also currently serves as Executive Chairman of Ajax Resources LLC and a board member of Paradigm Energy Partners.

~~Mr. Wylie’s experience in the energy industry, through his prior position~~ as the ~~CEO of a publicly traded partnership and the past employment described above, has given him both an understanding of the midstream sector of the energy~~

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~~business and of the unique issues related to operating publicly traded limited partnerships that make him a valuable member~~chairman of the board of directors of ~~our~~the general ~~partner.~~

~~Michael A. Wichterich~~ ~~has~~partner of Sunoco LP since April 2015. Mr. Ramsey previously served as President of RPM Exploration, Ltd., a private oil and gas exploration partnership, and previously served as a director of USA Compression GP, LLC since October 2017. Mr. Wichterich has been in the oil and gas business for 23 years and currently serves as President of Three Rivers Operating Company. He founded the first Three Rivers entity in 2010. Prior to starting Three Rivers, Mr. Wichterich served as Chief Financial Officer of Texas American Resources, which operated wells throughout Texas, Colorado and Wyoming. Mr. Wichterich has also served as a director of Sabine Oil and Gas since July 2016,RSP Permian, Inc. where he ~~serves~~served on the audit and compensation committees. ~~He previously~~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 ~~Financial~~Executive Officer of ~~Mariner~~OEC Compression Corporation, Inc., a publicly traded oil field service company, providing gas compression services to a variety of energy clients. Previously, Mr. Ramsey served as Vice President of Nuevo Energy Company, an independent energy company. Additionally, he was employed by Torch Energy Advisors, Inc. ~~He spent seven years with Mariner gaining experience~~, a company providing management and operations services to energy companies including Nuevo Energy, last serving as Executive Vice President. Mr. Ramsey joined Torch Energy as Vice President of Land and was named Senior Vice President of Land in 1992. Mr. Ramsey holds a B.B.A. in Marketing from the University of Texas at ~~both offshore Gulf~~Austin and a J.D. from South Texas College of ~~Mexico and West Texas projects. Prior to that,~~Law. Mr. ~~Wichterich spent nine years with PWC in its energy auditing practices, leading engagements within the oil and gas industry. Mr. Wichterich~~Ramsey is a ~~Certified Public Accountant~~graduate of 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 isthe U.S. Court of Appeals for the Fifth Circuit. Mr. Ramsey formerly served as a ~~graduate~~director of Southern Union Company.

Mr. Ramsey was selected to serve on the ~~University~~Board in recognition of ~~Texas.~~

~~Mr. Wichterich’s experience in the energy industry, through~~ his ~~prior position as the CFO of multiple energy entities and the past employment described above, has given him a unique understanding~~vast knowledge of the energy ~~business that makes him a~~space and valuable ~~member of~~industry, operational and management experience.

William S. Waldheimhas served on the Board since April 2018. Mr. Waldheim has also served on the board of directors of Southcross Energy Partners GP, LLC since February 2020. 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

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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.

Bradford D. Whitehurst has served on the Board since April 2019. Mr. Whitehurst currently serves as the Chief Financial Officer of the general partner of ET LP, a position he has held since January 2021. Prior to that, Mr. Whitehurst served as the Executive Vice President and Head of Tax of LE GP since August 2014. Prior to joining Energy Transfer, Mr. Whitehurst was a partner in the Washington, DC office of Bingham McCutchen LLP and an attorney in the Washington, DC offices of both McKee Nelson LLP and Hogan & Hartson. Mr. Whitehurst has specialized in partnership taxation and has advised Energy Transfer in his role as outside counsel since 2006.

Mr. Whitehurst was selected to serve on the Board because of his strong background in the energy sector and specialized knowledge of the taxation structure and issues unique to partnerships.

Delinquent Section 16(a) Reports

Section 16(a) of the Exchange Act requires that the members of the Board, our ~~general partner.~~

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. To our knowledge and based solely on a review of Section 16(a) forms filed electronically with the SEC, we believe 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, 2020, with the exception of one late Form 4 filing on behalf of Mr. G. Tracy Owens reporting a vesting of phantom units.

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 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 ~~for many~~with publicly traded limited partnerships, we have no officers, directors or employees. Under the terms of ~~our partnership agreement,~~the Partnership Agreement, we are ultimately managed by ~~our general partner.~~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,~~Management”), a wholly owned subsidiary of ~~our general partner.~~

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 ~~Compensation~~

~~We are an “emerging growth company” as defined under the Jumpstart Our Business Startups (JOBS) Act. As such, we are permitted to meet the~~Officers

The following disclosure ~~requirements of Item 402 of Regulation S-K by providing the reduced disclosures required of a “smaller reporting company.”~~

~~Executive Summary~~

~~This Executive Compensation disclosure provides an overview of~~describes the executive compensation program for ~~our~~the named executive officers identified ~~below. Our general partner intends to provide our named executive officers with compensation that is significantly performance based.~~below (the “NEOs”). For the year ended December 31, ~~2017, our named executive officers (“NEOs”)~~2020, the NEOs were:

~~Eric D. Long, President and Chief Executive Officer;~~

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

~~Matthew C. Liuzzi, Vice President, Chief Financial Officer and Treasurer.~~

•Eric D. Long, President and CEO;

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

•Eric A. Scheller, Vice President and Chief Operating Officer;

•Christopher W. Porter, Vice President, General Counsel and Secretary;

•Sean T. Kimble, Vice President, Human Resources; and

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~~Summary~~ •William G. Manias, Former Vice President and Chief Operating Officer.

Mr. Manias left the Partnership effective June 1, 2020. Eric A. Scheller was appointed as our new Vice President and Chief Operating Officer effective June 2, 2020.

Compensation ~~Table~~

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 a competitive range at or near the 50th percentile of the market for aggregate compensation consisting of the three main components of our compensation program: base salary, annual discretionary cash bonus and long-term equity incentive awards. The Compensation Committee believes that a desirable balance of incentive-based compensation is achieved by: (i) the payment of annual discretionary cash bonuses that consider (a) the achievement of the financial and operational performance objectives for a fiscal year set at the beginning of such fiscal year and (b) the individual contributions of each NEO to our level of success in achieving the annual financial and operational 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.

The following ~~table sets forth certain information~~charts illustrate the level of at-risk incentive compensation we awarded in 2020 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 executive officers with ~~respect~~an industry-competitive total compensation package of competitive base salaries and significant incentive opportunities yielding a total compensation package in a competitive range 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;

•ensure that a significant portion of each executive officer’s compensation is 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

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compensation program with the Partnership’s compensation philosophy described above. 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, skills, experience and performance of an individual relative to his or her peers at the Partnership. The Compensation Committee does not assign a 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 ~~paid~~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 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.

The Compensation Committee regularly compares 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 reviews 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 uses this data as a reference point rather than a primary data source.

Periodically, we engage a third-party consultant to provide the Compensation Committee with market information about compensation levels at peer companies to assist in evaluating compensation levels for our executives, including the NEOs. In the latter part of 2019, the Compensation Committee engaged Longnecker & Associates (“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 “2019 Longnecker Report”). The Compensation Committee relied on the results of the 2019 Longnecker Report for information on base salary, bonus and general compensation items for 2020 for the NEOs. The long-term equity incentive awards granted to our NEOs in December 2020 were based on the then-determined 2021 base salaries of the NEOs.

In 2020, the Compensation Committee determined that the 2019 Longnecker Report was completed recently enough to be utilized as a data source in reviewing and setting 2021 NEO compensation levels.

In connection with its engagement of Longnecker in 2019, 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 ~~years ended December 31, 2017 and 2016.~~

All Other

Unit Awards

Compensation

Name and Principal Position

Year

Salary ($)

Bonus ($) (1)

($) (2)

($)

Total ($)
Eric D. Long

2017

625,233

721,436

1,953,127

755,233
(3)
4,055,029
President and Chief Executive Officer

2016

607,019

773,419

1,892,893

742,412

4,015,743
William G. Manias

2017

423,886

396,711

993,108

389,700
(4)
2,203,405
Vice President and Chief Operating Officer

2016

411,538

416,353

1,069,430

380,616

2,277,937
Matthew C. Liuzzi

2017

375,538

329,496

782,050

313,209
(5)
1,800,293
Vice President, Chief Financial Officer and Treasurer

2016

362,885

381,399

852,693

306,589

1,903,566

~~(1)~~

Represents the awards earned under annual cash incentive bonus program for the years ended December 31, 2017 and 2016, as applicable. For a discussion of the determination of the 2017 bonus amounts, see “—Annual Incentive Compensation for 2017” below.

~~(2)~~

~~On February 13, 2017 and February 11, 2016, each of our NEOs received an award of time-based and performance-based phantom units under our long-term incentive plan~~ (“LTIP”). Each phantom unit is the economic equivalent of one common unit, although the performance-based awards could be settled at 200% of target levels in the event that the performance goals are satisfied at such levels. The phantom unit values reflect the grant date fair value of the awards calculated in accordance with the ~~Financial Accounting Standards Board’s~~ (“FASB”) Accounting Standard Codification (“ASC”) Topic 718, disregarding the estimate of forfeitures. For a discussion of the assumptions utilized in determining the fair value of these awards, please see Note 9 to our consolidated financial statements. With respect to the performance-based awards, the value of the awards has been reflected at the probable outcome of performance conditions as of the grant date for accounting purposes. If the awards were to be reflected at maximum amounts, the year 2017 amounts reflected in the table above would be increased by the following amounts: Mr. Long, $450,907; Mr. Manias, $229,278; and Mr. Liuzzi, $180,540. The year 2016 amounts reflected in the table above would be increased by the following amounts: Mr. Long, $434,412; Mr. Manias, $245,430; and Mr. Liuzzi, $195,693.

~~(3)~~

Includes $710,538 of distribution equivalent rights (“DERs”), $18,000 of automobile allowance, $8,100 of employer contributions under the 401(k) plan, $3,843 of parking, $3,574 of club membership dues, $9,178 of personal administrative assistant support and $2,000 of personal tax support. Please see a description of the DERs under “—Discretionary Long-Term Equity Incentive Awards” below.

~~(4)~~

~~Includes $381,568 of DERs, $7,330 of employer contributions under the 401(k) plan and $801 of parking.~~

~~(5)~~

~~Includes $304,308 in DERs, $8,100 of employer contributions under the 401(k) plan and $801 of parking.~~

Compensation Committee did not raise any conflicts of interest.

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~~Narrative Disclosure to Summary~~Our peer group, as selected by the Compensation ~~Table~~

Committee in consultation with Longnecker, included the following companies for purposes of the 2019 Longnecker Report:


Company						Ticker
1. Antero Midstream Corporation						AM
2. Archrock, Inc.						AROC
3. Crestwood Equity Partners LP						CEQP
4. Genesis Energy, L.P.						GEL
5. Holly Energy Partners, L.P.						HEP
6. Martin Midstream Partners L.P.						MMLP
7. NuStar Energy, L.P.						NS
8. SemGroup Corporation						SEMG
9. Summit Midstream Partners, LP						SMLP
10. Tallgrass Energy, LP						TGE

Elements of the Compensation Program

Compensation for ~~our~~the NEOs consists primarily of the following elements and ~~their~~ corresponding ~~objectives, identified in the following table.~~

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.

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

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

Retirement savings (401(k)) plan	To provide an opportunity for tax-efficient savings.

Other elements of compensation and perquisites		To attract and retain talented executives in a cost-efficient manner by providing benefits ~~with high perceived values at relatively low cost.~~ comparable to those offered by similarly situated companies.

Base ~~Compensation For 2017 and 2018~~

Salary for 2020

Base salaries for ~~our~~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 ~~executive officers~~NEO and market conditions, each as assessed by the board of directors of our general partner or the chief executive officer (for non-chief executive officer compensation) in conjunction with the compensation committee. For 2017 and 2018, inconditions. In connection with determining base salaries for each of ~~our~~the NEOs for 2020, other than Mr. Scheller, the ~~board of directors of our general partner, compensation committee~~Compensation Committee and ~~chief executive officer worked with a compensation consultant~~CEO utilized the 2019 Longnecker Report to determine comparable salaries for ~~our peer group, which we identified based on a review of companies in our industry with similar characteristics.~~

~~Based upon discussions with the compensation consultant with respect to a review of base salary information of companies~~such executive roles within our peer group, and determined that the ~~board of directors of our general partner has determined to target~~NEOs’ base salaries ~~directly in-line~~were generally in line with ~~our peer group. For 2017~~the market, and ~~2018,~~provided a merit increase for each NEO for the ~~board of directors of our general partner determined that~~2020 year. Mr. Scheller’s base salary ~~should be set~~was determined in June 2020 in connection with his promotion to Vice President and Chief Operating Officer, based on available market data, including the 2019 Longnecker Report, and the role, contribution, skills, experience and performance of Mr. Scheller relative to his peers at ~~approximately~~ the 50th ~~percentile~~Partnership.

Table of ~~the peer group.~~ Contents

The ~~2017 and current 2018~~2020 base salaries (and 2019 base salaries, where applicable, for ~~our~~comparison purposes) for the NEOs, including ~~for~~ our ~~Chief Executive Officer,~~CEO, are set forth in the following table:

2017 Base Salary

Current 2018 Base Salary
Name and Principal Position

($)

($)
Eric D. Long, President and Chief Executive Officer

625,931

644,709
William G. Manias, Vice President and Chief Operating Officer

424,361

437,092
Matthew C. Liuzzi, Vice President, Chief Financial Officer and Treasurer

375,960

387,239


Name and Principal Position	2020 Base Salary ($)		2019 Base Salary ($)
Eric D. Long, President and Chief Executive Officer	664,050		644,709
Matthew C. Liuzzi, Vice President, Chief Financial Officer and Treasurer	412,000		400,000
Eric A. Scheller, Vice President and Chief Operating Officer	331,500	(1)	(3)
Christopher W. Porter, Vice President, General Counsel and Secretary	315,000		(3)
Sean T. Kimble, Vice President, Human Resources	316,900		307,670
William G. Manias, Former Vice President and Chief Operating Officer	450,205	(2)	437,091

________________________

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(1)The amount above reflects the base salary effective upon Mr. Scheller’s appointment as Vice President and Chief Operating Officer on June 2, 2020. Mr. Scheller’s base salary for 2020 in his prior position was $265,225. See “–Summary Compensation Table” below for the salary received by Mr. Scheller in 2020.

(2)Mr. Manias left the Partnership effective June 1, 2020. The amount above reflects his annualized base salary for 2020. See “– Summary Compensation Table” below for the salary received by Mr. Manias in 2020.

(3)Mr. Scheller and Mr. Porter were not NEOs in 2019; therefore, only their 2020 Base Salary is reported.

Annual Cash Incentive Compensation ~~For 2017~~

~~The board of directors of our general partner has~~for 2020

In February 2019, the Compensation Committee made several modifications to the Partnership’s previous annual cash incentive program and approved the ~~adoption of an~~USA Compression Partners, LP Amended and Restated Annual Cash Incentive Plan (the ~~“Cash~~“Bonus Plan”)., which replaced the previous annual cash bonus plan and was effective for fiscal year 2019. Each of ~~our~~the NEOs is entitled to participate in the ~~Cash~~Bonus Plan and their potential bonus is governed ~~both~~ by the ~~Cash~~Bonus Plan and, for Messrs. Porter and Kimble, also governed by their respective employment ~~agreement.~~agreements. The ~~compensation committee~~Compensation Committee acts as the administrator of the ~~Cash~~Bonus Plan under the supervision of the full ~~board of directors of our general partner,~~Board, and has the discretion to amend, modify or terminate the ~~Cash~~Bonus Plan at any time.

In February 2021, the Compensation Committee made the determination to pay annual cash bonus awards to executives, including the NEOs, under the Bonus Plan attributable to the year ended December 31, 2020. Although the Bonus Plan is generally based upon our satisfaction of certain performance measures that were previously established for the 2020 year, the Compensation Committee retains the authority to use its business judgement to make decisions or adjustments to the Bonus Plan’s funding pool or the individual bonus awards resulting from the guidelines set forth below. The Bonus Plan contains four payout factors and corresponding percentages that comprise the total annual target bonus for all eligible employees, including the NEOs (the “Annual Target Bonus Pool”), as shown in the following chart.


Bonus Plan Payout Factors
Payout Factor						% of Total Annual Target Bonus
Adjusted EBITDA Budget Target Factor						30%
Distributable Cash Flow Budget Target Payout Factor						30%
Leverage Ratio Budget Target Factor						30%
Safety Budget Target Payout Factor						10%

Each of the Adjusted EBITDA Budget Target Factor (the “Adjusted EBITDA Factor”) and the Distributable Cash Flow Budget Target Payout Factor (the “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.

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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

For the 2020 year, the Compensation Committee set the Adjusted EBITDA Budget Target at $426.4 million and the DCF Budget Target at $221.4 million.

The Leverage Ratio Budget Target Factor (the “Leverage Ratio Factor”) assigns payout factors based on the Partnership’s achievement of its budgeted Leverage Ratio (as defined in the Partnership’s Credit Agreement, provided that, for purposes of calculating the Leverage Ratio for the Bonus Plan, EBITDA attributable to the full plan year is used in lieu of any other time ~~upon approval~~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

For the 2020 year, the Compensation Committee set the Leverage Ratio Budget Target at 4.65x.

The Safety Budget Target Payout Factor (the “Safety Factor”) assigns payout factors based on the Partnership’s Total Recordable Incident Rate, or TRIR (as calculated by the ~~board of directors of our general partner. Although~~U.S. Occupational Safety and Health Administration) against the ~~Cash Plan uses both company and individual performance goals to determine bonus amounts, the Cash Plan is ultimately a discretionary annual bonus plan and awards are therefore reported~~Partnership’s TRIR target, as shown in the ~~“Bonus” column within~~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

For the ~~Summary~~2020 year, the Compensation ~~Table above.~~

Committee set the Safety Target at 0.90.

The ~~board~~establishment and amount of ~~directors~~the 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 ~~our general partner sets~~the NEOs, their bonus pool targets for the 2020 year range from 80% 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 the 2020 year, the Compensation Committee set a target bonus amount (the “Target Bonus”) for each NEO prior to ~~or during~~ the first quarter of the ~~calendar year.~~2020 year, which was set as a percentage of the NEO’s base salary. Mr. Scheller’s Target Bonus was determined in June 2020 in connection with his appointment as Vice President and Chief Operating Officer. For the bonus applicable to the 2020 year, ~~ended December 31, 2017,~~ the Target Bonus, ~~for each NEO was $625,934 for Mr. Long, $339,489 for Mr. Manias~~as a percentage of base salary and ~~$281,970 for Mr. Liuzzi. The Target Bonus~~as a dollar amount, is ~~generally subject to~~reflected in the ~~satisfaction~~table

Table of both a partnership performance goal and an individual performance goal. For the year ended December 31, 2017 seventy-five percent (75%) of the Target Bonus was subject to our achievement of our budgeted distributable cash flow level (“DCF”) for the year, as determined by our board of directors of our general partner. Payouts with respect to the portion of the bonus subject to DCF (the “DCF Bonus”) generally do not occur unless we have satisfied the threshold set for DCF. For 2017, the board of directors of our general partner set the budget for DCF at $115.7 million. The threshold, target and maximum requirements for the DCF target for the year ended December 31, 2017, as well as the portion of the DCF Bonus that could become payable if performance was satisfied for the year, are set forth below:

Contents

DCF as a

Percentage of

Percentage of

DCF

Levels of

Budgeted DCF

Bonus that would

DCF Bonus

for 2017

be Paid

Threshold

80%

50%

Target

100%

100%

Maximum

110%

200%

below.

If DCF performance falls in between threshold and target, or between target and maximum, the amounts payable are adjusted ratably using straight line interpolation. If DCF is satisfied above maximum levels, the potential payment of the DCF Bonus is capped at the maximum level of 200%.

For the year ended December 31, 2017, the remaining twenty-five percent (25%) of the Target Bonus was subject to individual objectives specific to each eligible individual’s role at USAC Management (the “Individual Bonus”). The individual objectives are agreed upon in advance between the NEO and his immediate supervisor (or, with respect to the chief executive officer, between the board of directors of our general partner and the chief executive officer) and such objectives address the key priorities for that NEO’s position. They may include key operating objectives as well as personal development criteria. The Individual Bonus is subject to a maximum payout of 100% of the targeted Individual Bonus amount, although the board of directors of our general partner has discretion to pay out smaller amounts ranging from 0% to 100%, at their sole discretion, after analyzing the individual’s personal performance for the year.


Name	Percentage of Base Salary		Amount ($)
Eric D. Long, President and Chief Executive Officer	125	%	830,063
Matthew C. Liuzzi, Vice President, Chief Financial Officer and Treasurer	105	%	432,600
Eric A. Scheller, Vice President and Chief Operating Officer (1)	85	%	281,775
Christopher W. Porter, Vice President, General Counsel and Secretary	80	%	252,000
Sean T. Kimble, Vice President, Human Resources	80	%	253,520
William G. Manias, Former Vice President and Chief Operating Officer	100	%	450,205

________________________

(1)In connection with his appointment as Vice President and Chief Operating Officer on June 2, 2020, the ~~Individual~~Compensation Committee increased Mr. Scheller’s Target Bonus from 60% of his base salary to 85% of his base salary and increased his base salary. The Percentage of Base Salary column reflects this increased Target Bonus and the value reflected in the Amount column assumes that Mr. Scheller’s increased Target Bonus and base salary were applicable for all of 2020. Mr. Scheller’s actual Target Bonus for 2020 approved by the ~~year ended December 31, 2017, each~~Compensation Committee was determined on a pro-rated basis, based on the amount of time he spent in his role as Vice President and Chief Operating Officer during 2020. Mr. Scheller’s Target Bonus based on the prorated formula is $230,675.

The annual cash bonus pool targets for 2020 were based on the determination of the ~~NEOs met~~Compensation Committee in consultation with ~~their immediate supervisor (or, with respect to~~Longnecker, and in consideration of the ~~chief executive officer, the board of directors of our general partner) to set individual objectives that reflected the responsibilities and priorities of their position.~~

~~For the year ended December 31, 2017, in the aggregate, the maximum amount payable with respect to a Target Bonus under the Plan is 175%, as the DCF Bonus is capped at 200% of target~~available compensation data and the ~~Individual Bonus is capped~~role, contribution, skills, experience and performance of an individual relative to his or her peers at ~~100% of target.~~ the Partnership.

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 into which the Target Bonus relates, but in any case no ~~case~~ later than March 15 of the year following the year into which the Target Bonus relates. For the year ended December 31, ~~2017,~~2020, we achieved (i) Adjusted EBITDA of $413,898,283, resulting in an Adjusted EBITDA Bonus Pool Payout Factor of 1.00; (ii) DCF ~~exceeded~~of $220,766,323, resulting in a DCF Bonus Pool Payout Factor of 1.00; (iii) Leverage Ratio, as calculated for the ~~target threshold by 2.2%, which resulted in the DCF portion~~purposes of the ~~Cash~~Bonus Plan, ~~(comprising seventy-five percent~~ of ~~the overall Bonus) being paid to each NEO at the rate~~4.78, resulting in a Leverage Ratio Bonus Pool Payout Factor of ~~122% for~~0.70; and (iv) a TRIR of 0.32 resulting in a Safety Bonus Pool Payout Factor of 1.0. Based on these payout factors, the ~~DCF Bonus. With respect to the Individual Bonus~~

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portion of the overall Bonus, each NEO was determined by his immediate supervisor (which in the case of the chief executive officer is the board of directors of our general partner) to have satisfied his individual objectives and therefore was entitled to receive 100% of the Individual Bonus. The awards made pursuant to the ~~Cash~~Bonus Plan with respect to the ~~2017~~ year ~~were:~~

Eric D. Long

$
721,436

William G. Manias

$
396,711

Matthew C. Liuzzi

$
329,496

~~Benefit Plans~~ended December 31, 2020 equal 91% of each NEOs Target Bonus and ~~Perquisites~~

~~We provide~~were as follows:


Name						Bonus ($)
Eric D. Long, President and Chief Executive Officer						755,357
Matthew C. Liuzzi, Vice President, Chief Financial Officer and Treasurer						393,666
Eric A. Scheller, Vice President and Chief Operating Officer (1)						209,914
Christopher W. Porter, Vice President, General Counsel and Secretary						229,320
Sean T. Kimble, Vice President, Human Resources						230,703
William G. Manias, Former Vice President and Chief Operating Officer (1)						—

________________________

(1)Mr. Manias left the Partnership effective June 1, 2020. Mr. Scheller was appointed as our ~~executive officers, including our NEOs, with certain personal benefits~~new Vice President and perquisites, which we do not consider to be a significant component of executive compensation but which we recognize are an important factor in attracting and retaining talented executives. Executive officers are eligible under the same plans as all other employees with respect to our medical, dental, vision, disability and life insurance plans and a defined contribution plan that is tax-qualified under Section 401(k) of the Internal Revenue Code and that we refer to as the 401(k) Plan. We also provide certain executive officers with an annual automobile allowance. We provide these supplemental benefits to our executive officers due to the relatively low cost of such benefits and the value they provide in assisting us in attracting and retaining talented executives. The value of personal benefits and perquisites we provide to each of our NEOs is set forth above in our “—Summary Compensation Table.”

~~Discretionary~~ Chief Operating Officer effective June 2, 2020.

Long-Term Equity Incentive Awards

The ~~board of directors of our general partner has~~Board adopted ~~an LTIP. The~~the LTIP, ~~was~~which is designed to promote our interests, as well as the interests of our unitholders, by rewarding ~~the~~our officers, ~~employees~~directors and ~~directors~~certain of ~~us,~~ our ~~subsidiaries and our general partner~~employees for delivering desired performance results, as well as by strengthening our ~~and our general partner’s~~ ability to attract, retain and motivate qualified individuals to serve as officers, ~~employees~~directors and ~~directors.~~employees. The LTIP provides for the grant, from time to time at the discretion of the ~~board of directors of our general partner,~~Compensation Committee, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, DERs and other common unit-based awards, although since our initial public offering in ~~2017,~~2013 the Board has only granted awards of phantom units with DERs under the LTIP. The Compensation Committee acts as ~~well as in 2016,~~ the ~~board~~administrator of ~~directors~~the LTIP. Each phantom unit (“Phantom Unit”) relates to one of our ~~general partner only granted phantom~~common units, and represents the right to receive (as applicable) a common unit ~~awards~~or an amount of cash equal to the fair market value of a common unit (or a combination thereof) upon the vesting of such Phantom Unit pursuant to the ~~LTIP.~~LTIP, the applicable award agreement thereunder (“Phantom Unit Agreement”) and as determined by the Compensation Committee in its discretion. The outstanding, unvested Phantom Units granted under the LTIP ~~awards~~and held by ~~our~~the NEOs are reflected below in “– Outstanding Equity Awards as of December 31, 2020.”

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Our current Phantom Unit Agreement (i) provides for incremental vesting over five years in two tranches ((a) 60% on the third December 5 following the grant and (b) 40% on the fifth December 5 following the grant), (ii) provides for vesting of 100% of the outstanding, unvested Phantom Units in the ~~table below.~~

~~During 2017~~event of (a) a Change in Control (as defined under the ~~board of directors of our general partner granted phantom unit awards to certain key employees, including our NEOs. With respect to our 2017~~LTIP and ~~2016 awards, twenty percent (20%~~set forth below under “Potential Payments upon Termination or Change in Control”) or (b) the death or Disability (as defined under the LTIP and set forth below under “Potential Payments upon Termination or Change in Control”) of the ~~phantom unit award~~NEO, (iii) provides for vesting of 40% of the outstanding, unvested Phantom Units if the NEO voluntarily retires between the ages of 65-68 and has been employed by us, our General Partner, or our or its affiliates for at least 10 years (with the remaining 60% being forfeited), and (iv) provides for vesting of 50% of the outstanding, unvested Phantom Units if the NEO voluntarily retires over the age 68 and has been employed by us, our General Partner, or our or its affiliates for at least 10 years (with the remaining 50% being forfeited). The vesting of the Phantom Units are subject, in each case, to the NEO’s continued employment with us until the relevant vesting date.

The target level of annual long-term incentive awards for each ~~individual~~of the NEOs is ~~subject~~expressed as a percentage of the NEO’s base salary. In determining the level of the December 2020 grants of Phantom Units to ~~a performance-based vesting formula~~the NEOs, the Compensation Committee, taking into account market data and the ~~remaining eighty percent (80%)~~role, contribution, skills, experience and performance of an NEO relative to his or her peers at the Partnership, determined each of the ~~phantom unit award is subject to time-based vesting restrictions. With respect~~NEOs’ long-term incentive targets. Due to the ~~time-based phantom unit~~fact that determinations were made in late 2020, the base salaries used for these calculations were the then-determined base salaries set for the 2021 calendar year. Each NEO’s grant value is shown in the following table:


Long-Term Incentive Target Amounts for the Year Ended December 31, 2020
Name (1)	Percentage of Base Salary		Grant Date Amount ($)
Eric D. Long, President and Chief Executive Officer	400	%	2,656,200
Matthew C. Liuzzi, Vice President, Chief Financial Officer and Treasurer	250	%	1,030,000
Eric A. Scheller, Vice President and Chief Operating Officer	175	%	612,500
Christopher W. Porter, Vice President, General Counsel and Secretary	175	%	577,500
Sean T. Kimble, Vice President, Human Resources	175	%	568,750

________________________

(1)Mr. Manias left the Partnership prior to the grant of the long-term incentive awards for 2020.

Under the ~~awards will vest~~LTIP, the Compensation Committee has the discretion to determine whether any portion of Phantom Units should be settled in ~~three equal annual installments, with~~cash upon vesting. On October 29, 2019, the ~~first installment vesting~~Compensation Committee approved the default settlement method for Phantom Units of 50% in cash (valued based on the ~~first anniversary~~closing price on the NYSE of the Partnership’s common units on the date of ~~grant. With respect~~vesting) and 50% in common units for all vesting of Phantom Units occurring during 2020. However, the Compensation Committee 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 ~~performance-based phantom unit awards,~~extent that the ~~awards will vest based upon our level of total unitholder return (“TUR”) relative to a group of peer companies over the period beginning December 31, 2016 and ending December 31, 2019~~cash portion is insufficient for the ~~2017 award,~~Partnership to withhold and ~~beginning December 31, 2015 and ending December 31, 2018 for~~pay such amounts on the ~~2016 award. The peer group companies are~~employee’s behalf), the ~~constituent companies~~Board approves in the Alerian Natural Gas MLP Index, as reported in the Alerian Capital Management or other relevant reporter. The performance-based phantom unit awards are granted at a “target” level, but will be eligible to vest from 0%-200% of the target level. Threshold levels (50% of target) are set at the 35th ~~percentile of the constituent companies, target levels (100% of target) are set at the 50~~th ~~percentile of the constituent companies, and maximum levels (200%) are set at the 90~~th ~~percentile of the constituent companies. The awards will be adjusted ratably using straight line interpolation for TUR results between threshold and target and between target and maximum.~~

advance such lesser cash settlement percentage.

Each ~~phantom unit~~Phantom Unit granted to an employee, including the NEOs, is granted in tandem with a corresponding DER, which ~~is paid~~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 ~~distribution date from~~Partnership’s common units for such quarter and (b) the ~~grant date until the earlier of the vesting or the forfeiture of the related phantom units. With respect to the performance-based phantom units, the DERs will only be granted~~quarterly distribution with respect to the ~~target level number,~~Partnership’s common units.

Awards granted pursuant to the LTIP are subject to certain clawback features, and ~~will~~the award may not ~~be adjusted up~~vest or ~~down depending on the actual TUR results. The DERs entitle~~settle if we determine that the recipient committed certain acts of misconduct, as more particularly described in the LTIP.

Retention Phantom Unit Awards

In 2018 the Compensation Committee approved an additional grant of Phantom Units to each of Messrs. Long, Liuzzi and Manias, and in 2019 approved an additional grant of Phantom Units to each of Messrs. Long and Liuzzi, in each case in recognition of the ~~award to a payment equivalent~~importance of such NEO to the ~~amount of~~Partnership’s long term success and to encourage their retention by providing additional time-based compensation. These Phantom Units are referred to as “Retention Units” and were issued pursuant to Retention Phantom Unit Agreements entered into between our General Partner and the ~~per common unit distribution payable to common unitholders following~~applicable NEO on the grant date of the award (the “Retention Agreements”). The Compensation Committee did not award any Retention Units to our NEOs in 2020. The Retention Units will vest incrementally, with 60% of the Retention Units vesting on the third December 5 following the grant and 40% on the fifth December 5 following the grant. The Retention Agreements also 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 (each as defined in the Retention Agreement and set forth below under “Potential Payments upon Termination or Change in Control”),

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(ii) a Change in Control (as defined under the LTIP and set forth below under “Potential Payments upon Termination or Change in Control”) or (iii) the death or Disability (as defined under the LTIP and set forth below under “Potential Payments upon Termination or Change in Control”) of the NEO. In addition, Mr. Long’s Retention Agreement provides for vesting of 40% of the outstanding, unvested Phantom Units if Mr. Long voluntarily retires at age 65 or older and has been employed by us, our General Partner, or our or its affiliates for at least 10 years (with the remaining 60% being forfeited). The vesting of the Retention Units are subject, in each case, to the NEO’s continued employment with us until the relevant vesting date.

For additional information regarding the Retention Agreements, please see “– Potential Payments upon Termination or Change in Control-Retention Phantom Unit Agreements” below.

Benefit Plans and Perquisites

We provide the NEOs with certain other benefits and perquisites, which we do not consider to be a significant component of our overall executive compensation program, but which we recognize as 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 (i) medical, dental, vision, disability and life insurance benefits and (ii) 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 (a) an annual automobile allowance; (b) club memberships; and (c) personal tax support. During 2020, we also provided one or more NEOs with 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 NEOs’ total compensation. The value of personal benefits and perquisites we provided to each of the NEOs in 2020 is set forth below in “– Summary Compensation Table.”

Employment Agreements

Each of Messrs. Porter and Kimble is party to an employment agreement with us (together, the “Employment Agreements”), each of which has 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. 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.

Each of Messrs. Long, Liuzzi and Manias entered into a Termination Agreement and Mutual Release with USAC Management (and, with respect to Mr. Long, USA Compression Partners, LLC) providing for (i) the termination, effective as of November 1, 2018, of the employment agreements to which each of Messrs. Long, Liuzzi and Manias had been party 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.

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 ~~DERs~~a way as to not encourage excessive risk-taking. Furthermore, all business groups and employees receive the similar 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 currently outstanding 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 GAAP, which requires us to estimate and record an expense for each ~~phantom unit~~equity award over the vesting period of the award. For employees, Phantom 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. 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.

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Because we are a partnership and the General Partner is a limited liability company, Section 162(m) of the Internal Revenue Code (the “Code”), which generally precludes public corporations from taking a tax deduction for individual compensation to certain of its executive officers in excess of $1 million, 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.

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 2020 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.

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Summary Compensation Table

The following table provides information concerning compensation of our NEOs for the fiscal years presented below, as applicable.


Name and Principal Position	Year	Salary ($)	Bonus ($) (1)	Unit Awards ($) (2)	Non-Equity Incentive Plan Compensation ($) (3)	All Other Compensation ($) (4)(5)	Total ($)
Eric D. Long	2020	688,846	—	2,656,189	755,357	1,053,015	5,153,407
President and Chief Executive Officer	2019	644,709	—	3,320,238	878,416	616,583	5,459,946
	2018	644,709	818,597	5,942,922	—	322,176	7,728,404

Matthew C. Liuzzi	2020	427,385	—	1,029,995	393,666	459,159	2,310,205
Vice President, Chief Financial Officer and Treasurer	2019	399,509	—	1,441,971	457,800	330,446	2,629,726
	2018	387,239	368,763	2,331,734	—	261,277	3,349,013

Eric A. Scheller	2020	314,384	—	612,496	209,914	114,911	1,251,705
Vice President and Chief Operating Officer

Christopher W. Porter	2020	326,154	—	577,490	229,320	150,872	1,283,836
Vice President, General Counsel and Secretary

Sean T. Kimble	2020	328,733	—	568,744	230,703	193,124	1,321,304
Vice President, Human Resources	2019	307,670	—	554,560	268,288	163,538	1,294,056
	2018	307,670	273,457	1,105,336	—	176,784	1,863,247

William G. Manias	2020	200,356	—	—	—	2,507,199	2,707,555
Former Vice President and Chief Operating Officer	2019	437,092	—	1,012,957	476,430	375,506	2,301,985
	2018	437,092	443,986	2,682,754	—	323,631	3,887,463

________________________

(1)Represents the awards earned under our previous bonus plan for the year ended December 31, 2018.

(2)The Phantom Unit values reflect the grant date fair value of the awards calculated in accordance with the Financial Accounting Standards Board’s (“FASB”) Accounting Standard Codification (“ASC”) Topic 718, disregarding the estimated likelihood of forfeitures. For a discussion of the assumptions utilized in determining the fair value of these awards, please see Note 15 in Part II, Item 8 “Financial Statements and Supplementary Data”. The awards reflected in the 2018 year row reflect both Phantom Units and performance-based Phantom Unit awards, which performance-based Phantom Unit awards were all accelerated in connection with the Transactions and are no longer outstanding.

(3)Represents the awards earned under the Bonus Plan for 2020 and 2019 for each of the NEOs. Amounts earned for the 2020 year will be paid after the Partnership’s audited financials are finalized.

(4)See the chart and footnote (5) below for a detailed breakdown of amounts reported in this column for 2020:

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Name	DERs		Automobile Allowance		Employer 401(k) Contributions		Club Membership Dues		Administrative Support		Tax Support		Parking
Mr. Long	$	998,957	$	18,000	$	14,250	$	11,808	$	2,461	$	0	$	7,540
Mr. Liuzzi	$	443,934	—		$	14,250	—		—		—		$	974
Mr. Scheller	$	101,457	—		$	12,480	—		—		—		$	974
Mr. Porter	$	133,532	—		$	14,250	—		—		—		$	3,090
Mr. Kimble	$	175,784	—		$	14,250	—		—		—		$	3,090
Mr. Manias	$	215,265	—		$	10,018	—		—		$	0	$	406

(5)Mr. Manias left the Partnership effective June 1, 2020. In connection with his departure, he received a separation payment of $1,340,997 and, pursuant to his Retention Agreement dated November 1, 2018, a release payment in the amount of $165,375. Additionally, 59,626 unvested Phantom Units granted to Mr. Manias under his Retention Agreement dated November 1, 2018 and his Employee Phantom Unit Agreement dated February 12, 2018 vested in connection with his departure, which units had a value of $775,138 on the date of Mr. Manias’s departure.

Grants of Plan-Based Awards during the Year Ended December 31, 2020

The below reflects awards granted to our NEOs under the LTIP and our Bonus Plan during 2020.

Name

Grant Date

Approval Date of Equity-Based
Awards

Estimated Possible Payouts Under Non-equity Incentive Plan Awards (1)

All Other Unit Awards: Number of Units
(#) (2) (3)

Grant Date Fair Value of Unit Awards
($) (4)

Target ($)

Maximum ($)

Eric D. Long

2/13/2020

830,063

979,474

President and Chief Executive Officer

12/5/2020

10/28/2020

213,520

2,656,189

Matthew C. Liuzzi

2/13/2020

432,600

510,468

Vice President, Chief Financial Officer and Treasurer

12/5/2020

10/28/2020

82,797

1,029,995

Eric A. Scheller

5/21/2020

230,675

272,197

Vice President and Chief Operating Officer

12/5/2020

10/28/2020

49,236

612,496

Christopher W. Porter

2/13/2020

252,000

297,360

Vice President, General Counsel and Secretary

12/5/2020

10/28/2020

46,422

577,490

Sean T. Kimble

2/13/2020

253,520

299,154

Vice President, Human Resources

12/5/2020

10/28/2020

45,719

568,744

William G. Manias (5)

2/13/2020

450,205

531,242

Former Vice President and Chief Operating Officer

________________________

(1)These awards were granted in 2020 pursuant to our Bonus Plan. The potential payout pursuant to these awards could be zero, thus we have not reflected a threshold amount in the table above. Actual amounts earned for the 2020 year have been reflected within the Summary Compensation Table above.

(2)The Phantom Units granted on December 5, 2020 to our NEOs were granted pursuant to our LTIP and will vest incrementally, with 60% of the Phantom Units vesting on December 5, 2023 and the remaining 40% of the Phantom Units vesting on December 5, 2025. These Phantom Units 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 the NEO retires after attaining the age of 65, 60% of his then-unvested Phantom Units granted on December 5, 2020 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 Phantom Units granted December 5, 2020 will be forfeited, and the remainder will vest, at the time of retirement.

(3)The Phantom Units granted on December 5, 2020 were granted in tandem with ~~such rights.~~

a corresponding DER.

(4)The reported grant date fair value of unit awards was calculated by multiplying $12.44, the closing price of the Partnership’s common units on December 4, 2020, the last business day prior to the date of grant (December 5, 2020), due to the grant date falling on a Saturday, by the number of units granted, as required by FASB ASC Topic 718.

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~~Mr. Long was also granted Class B Units of USA Compression Holdings at the time we were acquired by USA Compression Holdings in 2010.~~ (5)Mr. Manias ~~and Mr. Liuzzi were granted Class B Units of USA Compression Holdings at~~left the time of their employment. The grants the NEOs received had time-based vesting requirements (which, for Mr. Long, were satisfied in full as of December 31, 2013 and, for Mr. Manias and Mr. Liuzzi, were satisfied in full as of December 31, 2017) and are designed not only to compensate but also to motivate and retain the recipients by providing an opportunity for equity ownership by our NEOs. The grants to our NEOs also provide our NEOs with meaningful incentives to increase unitholder value over time. The Class B Units are profits interests that allow our NEOs to participate in the increase in value of USA Compression Holdings over and above an annual and cumulative preferred return hurdle. Available cash will be distributed to the USA Compression Holdings members at such times as determined by its board of managers, at which time the holders of Class B Units could receive distributions if the cash distributed reaches the required distribution hurdles. Distributions to the Class B Unitholders could also occur in connection with a sale or liquidation event of USA Compression Holdings. To date, our NEOs have not received distributions with respect to these awards.

Partnership effective June 1, 2020.

Outstanding Equity Awards as of December 31, ~~2017~~

2020

The following table provides information regarding Phantom Units granted to the NEOs pursuant to the LTIP in each of the years ended December 31, 2018, 2019 and 2020 that were outstanding as of December 31, 2020, as well as the scheduled vesting schedule for each outstanding award. Potential acceleration events or change in control treatment for the Phantom Units are described below in the section titled “Potential Payments Upon Termination or Change in Control.” None of the NEOs held any outstanding option awards as of December 31, 2020.


Name	Number of Outstanding Phantom Units (#)		Market Value of Outstanding Phantom Units ($) (7)
Eric D. Long, President and Chief Executive Officer
2018 Grants	266,874	(1)(2)	3,629,486
2019 Grants	208,820	(4)(5)	2,839,952
2020 Grant	213,520	(6)	2,903,872
Matthew C. Liuzzi, Vice President, Chief Financial Officer and Treasurer
2018 Grants	115,105	(1)(2)(3)	1,565,428
2019 Grants	90,690	(4)(5)	1,233,384
2020 Grant	82,797	(6)	1,126,039
Eric A. Scheller, Vice President and Chief Operating Officer
2018 Grants	15,947	(2)(3)	216,879
2019 Grant	31,446	(4)	427,666
2020 Grant	49,236	(6)	669,610
Christopher W. Porter, Vice President, General Counsel and Secretary
2018 Grants	30,718	(2)(3)	417,765
2019 Grant	31,698	(4)	431,093
2020 Grant	46,422	(6)	631,339
Sean T. Kimble, Vice President, Human Resources
2018 Grants	44,934	(2)(3)	611,102
2019 Grant	34,878	(4)	474,341
2020 Grant	45,719	(6)	621,778

________________________

(1)On November 1, 2018, Mr. Long and Mr. Liuzzi received a grant of 90,000 Retention Units and 35,000 Retention Units, respectively, pursuant to the LTIP and applicable Retention Agreement. The Retention Units vest incrementally, with 60% of the Retention Units vesting on December 5, 2021 and 40% of the Retention Units vesting on December 5, 2023.

(2)Includes Phantom Units granted pursuant to the LTIP on December 5, 2018 to each of the NEOs: 176,874 to Mr. Long; 68,587 to Mr. Liuzzi; 13,717 to Mr. Scheller; 27,846 to Mr. Porter; and 36,927 to Mr. Kimble. The Phantom Units granted on December 5, 2018 vest incrementally, with 60% of the Phantom Units vesting on December 5, 2021 and the remaining 40% of the Phantom Units vesting on December 5, 2023.

(3)Includes Phantom Units granted pursuant to the LTIP on February 12, 2018 that had not vested as of December 31, 2020. On February 15, 2021, the remaining unvested Phantom Units awarded on February 12, 2018 held by the NEOs vested as follows: 11,518 to Mr. Liuzzi; 2,230 to Mr. Scheller; 2,872 to Mr. Porter; and 8,007 to Mr. Kimble.

(4)Includes Phantom Units granted pursuant to the LTIP on December 5, 2019 to each of the NEOs: 167,056 to Mr. Long; 64,779 to Mr. Liuzzi; 31,446 to Mr. Scheller; 31,698 to Mr. Porter; and 34,878 to Mr. Kimble. The Phantom Units granted on December 5, 2019 vest incrementally, with 60% of the Phantom Units vesting on December 5, 2022 and the remaining 40% of the Phantom Units vesting on December 5, 2024.

(5)On December 5, 2019, Mr. Long and Mr. Liuzzi received a grant of 41,764 and 25,911 Retention Units, respectively, pursuant to the LTIP and applicable Retention Agreement. The Retention Units vest incrementally, with 60% of the Retention Units vesting on December 5, 2022 and 40% of the Retention Units vesting on December 5, 2024.

(6)Includes Phantom Units granted pursuant to the LTIP on December 5, 2020 to each of the NEOs: 213,520 to Mr. Long; 82,797 to Mr. Liuzzi; 49,236 to Mr. Scheller; 46,422 to Mr. Porter; and 45,719 to Mr. Kimble. The Phantom Units granted on December 5, 2020 vest

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incrementally, with 60% of the Phantom Units vesting on December 5, 2023 and the remaining 40% of the Phantom Units vesting on December 5, 2025.

(7)The market value of Phantom Units is calculated by multiplying $13.60, the closing price of the Partnership’s common units on December 31, 2020, by the number of Phantom Units outstanding.

Units Vested During the Year Ended December 31, 2020

The following table provides information regarding the ~~Class B~~vesting of Phantom Units ~~in USA Compression Holdings~~ held by the NEOs during 2020. There are no options outstanding on the Partnership’s common units. Mr. Long did not have any awards vest during the 2020 year.


Name	Number of Phantom Units Vested (#)		Value Realized on Vesting ($) (6) (7)
Eric D. Long, President and Chief Executive Officer	—		—
Matthew C. Liuzzi, Vice President, Chief Financial Officer and Treasurer	22,409	(1)	338,824
Eric A. Scheller, Vice President and Chief Operating Officer	3,679		55,626
Christopher W. Porter, Vice President, General Counsel and Secretary	4,682	(2)	70,792
Sean T. Kimble, Vice President, Human Resources	15,578	(3)	235,539
William G. Manias, Former Vice President and Chief Operating Officer	88,082	(4)(5)	1,205,393

________________________

(1)Mr. Liuzzi settled approximately 25% of his newly vested Phantom Units in cash in the amount of $84,717 (before taxes), which cash settlement was reported as a disposition of ~~December 31, 2017. None~~those Phantom Units. The remaining 16,806 Phantom Units vested following such cash settlement.

(2)Mr. Porter settled approximately 50% of ~~our NEOs held any option awards that were outstanding~~his newly vested Phantom Units in cash in the amount of $35,396 (before taxes), which cash settlement was reported as a disposition of ~~December 31, 2016~~those Phantom Units. The remaining 2,341 Phantom Units vested following such cash settlement.

(3)Mr. Kimble settled approximately 50% of his newly vested Phantom Units in cash in the amount of $117,785 (before taxes), which cash settlement was reported as a disposition of those Phantom Units. The remaining 7,788 Phantom Units vested following such cash settlement.

(4)Mr. Manias settled approximately 50% of his newly vested Phantom Units in cash in the amount of $602,696 (before taxes), which cash settlement was reported as a disposition of those Phantom Units. The remaining 44,041 Phantom Units vested following the applicable cash settlement.

(5)Pursuant to the terms of Mr. Manias’s Retention Agreement dated November 1, 2018 and ~~2017. Also reflected within the table are the outstanding phantom units that were~~Phantom Unit Agreement dated February 12, 2018, 59,626 unvested Phantom Units granted to ~~our NEOs from~~Mr. Manias under such agreements vested in connection with his departure on June 1, 2020.

(6)The value realized on vesting of Phantom Units for Messrs. Liuzzi, Scheller, Porter and Kimble was calculated by multiplying $15.12, the ~~LTIP during~~closing price of the ~~years ended December 31, 2015, 2016~~Partnership’s common units on February 14, 2020, the last business day prior to the date of vesting (February 15, 2020), which vesting date fell on a Saturday, by the number of Phantom Units vesting.

(7)The value realized on vesting of Phantom Units for Mr. Manias was calculated by adding the following amounts: (i) the amount determined by multiplying $15.12, the closing price of the Partnership’s common units on February 14, 2020, the last business day prior to the date of vesting (February 15, 2020), which vesting date fell on a Saturday, by the number of Phantom Units vesting on February 15, 2020, and ~~2017, respectively.~~

Unit Awards

Equity Incentive Plan Awards


Number of

Number of

Market

Number of Unearned

Market Value Of

Class B Units

Outstanding

Value of

Units That Have

Unearned Units That

That Have Vested but

Phantom Units

Outstanding

Not Vested

Have Not Vested

Are Still Outstanding

(Time-Based)

Phantom Units

(Performance-Based)

(Performance-Based)
Name

(#)(1)

(#)

($) (5)

(#)

($) (5)
Eric D. Long

481,250

2015 Grant

25,176
(2)
416,411

2016 Grant

134,484
(3)
2,224,365

100,862
(6)
1,668,257
2017 Grant

81,598
(4)
1,349,631

40,800
(7)
674,832
William G. Manias

125,000

2015 Grant

12,168
(2)
201,259

2016 Grant

75,979
(3)
1,256,693

56,984
(6)
942,515
2017 Grant

41,490
(4)
686,245

20,746
(7)
343,139
Matthew C. Liuzzi

62,500

2015 Grant

9,843
(2)
162,803

2016 Grant

60,580
(3)
1,001,993

45,436
(6)
751,511
2017 Grant

32,673
(4)
540,411

16,336
(7)
270,197
(ii) the amount determined by multiplying $13.00, the closing price of the Partnership’s common units on June 1, 2020, by the number of Phantom Units vesting on that date.

~~(1)~~

Represents the number of Class B Units in USA Compression Holdings that became vested but had not been settled as of December 31, 2017. These Class B Units vested 25% on the one-year anniversary of the date of grant and 1/36 monthly thereafter; provided that 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.

~~(2)~~

Represents the number of phantom units issued on February 19, 2015 pursuant to the LTIP that had not vested as of December 31, 2017. Each phantom unit is the economic equivalent of one common unit. The phantom units are scheduled to vest in three equal annual installments on each subsequent February 15th ~~with the first installment vesting on February 15, 2016. In the event of cessation of the NEO’s service for any reason, all phantom units that have not vested prior to~~Potential Payments upon Termination or ~~in connection with such cessation of service shall automatically be forfeited.~~

~~(3)~~

Represents the number of time-based phantom units issued on February 11, 2016 pursuant to the LTIP that had not vested as of December 31, 2017. Each phantom unit is the economic equivalent of one common unit. The phantom units are scheduled to vest in three equal annual installments on each subsequent February 15th ~~with the first installment vesting on February 15, 2017. In the~~

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~~event of cessation of the NEO’s service for any reason, all phantom units that have not vested prior to or in connection with such cessation of service shall automatically be forfeited.~~

~~(4)~~

Represents the number of time-based phantom units issued on February 13, 2017 pursuant to the LTIP that had not vested as of December 31, 2017. Each phantom unit is the economic equivalent of one common unit. The phantom units are scheduled to vest in three equal annual installments on each subsequent February 15th with the first installment vesting on February 15, 2018. In the event of cessation of the NEO’s service for any reason, all phantom units that have not vested prior to or in connection with such cessation of service shall automatically be forfeited.

~~(5)~~

~~Market value is calculated using the value of $16.54, which was the closing price of our common units on December 29, 2017 (as December 31, 2017 was not a trading day).~~

~~(6)~~

Represents the number of performance-based phantom units granted on February 11, 2016 pursuant to the LTIP that had not vested as of December 31, 2017. The number of performance-based phantom units was determined by calculating the level of TUR performance that would have been achieved as of December 31, 2017 with respect to our constituent companies, and reflecting the next highest level of achievement within the table above, which was the maximum level. The performance period for these awards will end on December 31, 2018 and will vest, if at all, based upon the level of TUR performance achieved at that time. Events that could result in accelerated vesting are described below under the heading “Severance and Change in Control Arrangements.”

~~(7)~~

Represents the number of performance-based phantom units granted on February 13, 2017 pursuant to the LTIP that had not vested as of December 31, 2017. The number of performance-based phantom units was determined by calculating the level of TUR performance that would have been achieved as of December 31, 2017 with respect to our constituent companies, and reflecting the next highest level of achievement within the table above, which was the maximum level. The performance period for these awards will end on December 31, 2019 and will vest, if at all, based upon the level of TUR performance achieved at that time. Events that could result in accelerated vesting are described below under the heading “Severance and Change in Control Arrangements.”

~~Severance and~~ Change in Control ~~Arrangements~~

~~Our~~

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

Retention Phantom Unit Agreements

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. Also, on December 5, 2019, each of Messrs. Long and Liuzzi entered into a Retention Agreement providing for a grant of Retention Units that will vest incrementally, with 60% of the

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Retention Units vesting on December 5, 2022 and 40% of the Retention Units vesting on December 5, 2024. For the purposes of the following description, the “Company” means USA Compression ~~Holdings.~~

~~Each NEO currently has an employment agreement with USAC Management that provides~~GP, LLC. The Retention Agreements provide for ~~severance benefits~~the vesting of 100% of the then-unvested Retention Units upon a(i) the NEO’s termination of ~~employment. On January 1, 2013, we entered into~~employment without Cause or for Good Reason (each as defined in the ~~services agreement~~Retention Agreement and described below), (ii) a Change in Control (as defined under the LTIP and as described below) or (iii) the death or Disability (as defined under the LTIP and as described below) 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 ~~USAC Management, pursuant to which USAC Management provides to us and our general partner management, administrative and operating services and personnel to manage and operate our business.~~Retention Units forfeited for tax withholding purposes upon vesting. Pursuant to the ~~services agreement, we~~terms of Mr. Long’s Retention Agreements, upon Mr. Long’s termination of employment due to voluntary retirement, provided that Mr. Long is at least 65 years of age at the time of such retirement and has been employed by the Company, the Partnership or their Affiliates for at least 10 years, 40% of his then-outstanding, unvested Retention Units will ~~reimburse USAC Management~~receive accelerated vesting and the remaining 60% 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 ~~allocable expenses~~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 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 Transactions, and Director Independence”).

~~Severance Arrangements~~

~~Each NEO’s employment agreementhad an initial term that~~NEO has been ~~extended on a year-to-year basis~~given written notice specifying in detail the conduct that allegedly constitutes grounds to terminate for Cause and an opportunity for 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 ~~extended automatically for successive twelve-month periods thereafter unless either party delivers~~delivered.

“Good Reason” is defined under the Retention Agreements as the occurrence, during the Restricted Period (as defined in the Retention Agreement) 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 NEO’s authority, duties, reporting relationship or responsibilities with the Partnership on 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 ~~other within ninety days prior to the expiration~~Company of the ~~then-current employment term. Upon~~existence of the Good Reason condition within a period not to exceed 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 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.

Employment Agreements

As previously noted, each of Messrs. Porter 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. Porter and Kimble. All capitalized terms used in the following description but not defined therein will 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 (each as defined in the Employment Agreements and set forth below): (i) semi-monthly severance payments for the one year period following the NEO’s ~~employment~~Separation from Service (the “Severance Period”) in an amount totaling the higher of the NEO’s Base Salary for (a) the current year and (b) any ~~reason,~~previous year during the term of the Employment

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Agreement (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” (as defined in the Employment Agreements and set forth below) 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 following his Separation from Service (the “Coverage Period”), 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 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 ~~annual~~ base salary and ~~vacation~~paid time ~~(and, with respect~~off. The NEO’s right to the ~~chief executive officer, accrued, unused sick time off) shall~~Severance Payment and continued health insurance benefits described in (i) and (iv) of the preceding sentence are subject to (1) the NEO’s execution of a release of claims against the Company within 45 days of such NEO’s Separation from Service and (2) the NEO’s compliance with the continuing obligations under his Employment Agreement, including confidentiality, non-compete and non-solicit obligations.

In the event of the termination of Mr. Porter’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 toin a lump sum on the ~~NEO within thirty (30)~~Company’s first regular payroll date that occurs on or after 30 days ofafter the date of the NEO’s Separation from Service.

In the event of a termination of ~~employment. Upon termination of an NEO’s~~Mr. Porter’s or Mr. Kimble’s employment ~~either by us for convenience or~~ due to death or Disability (as defined in the Employment Agreements), the Company shall pay the following to the NEO or the NEO’s ~~resignation~~estate: (i) the entire amount of any earned Annual Bonus for ~~good reason, subject to~~ the ~~timely execution of a general release of claims,~~year preceding the year in which the NEO ~~is entitled to receive (i) an amount equal to one times his annual~~dies or becomes Disabled; (ii) 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 (iii) all earned but unpaid base salary ~~(plus, in~~and paid time off. In the ~~case~~event of Mr. Long, an amount equal to one times his target annual bonus), payable in equal semi-monthly installments over one year following termination (the “Severance Period”) (or, if such termination occurs within two years following a change in control, in a lump sum within thirty days following the termination of employment), subject to acceleration upon the NEO’s death during the Severance Period, ~~and (ii) continued coverage for twenty-four (24) months (or, with respect to Mr. Long, thirty (30) months) under our group medical plan~~the Severance Payment will be paid in ~~which the executive and any~~a lump sum within 30 days of his ~~dependents were participating immediately prior to his termination. Continued coverage under our group medical plan is subsidized for the first twelve (12) months~~

death.

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following termination, after which time continued coverage shall be provided at the NEO’s sole expense (except with respect to Mr. Long, who is entitled to reimbursement by us to the extent the cost of such coverage exceeds $1,200 per month) for the remainder of the applicable period. Additionally, upon a termination of an NEO’s employment by us for convenience, by the NEO for good reason, or due to the NEO’s death or disability, the NEO is entitled to receive (i) an amount equal to one times his annual bonus (up to his target annual bonus) for the immediately preceding year and (ii) a pro-rata portion of any earned annual bonus for the year in which termination occurs. During employment and for two years following termination, each NEO’s employment agreement prohibits him from competing with our business.

As used in the ~~NEOs’ employment agreements,~~Employment Agreements, a termination for “convenience” generally means an involuntary termination for any reason, including, under certain circumstances, 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.” “Cause” is defined in the ~~NEOs’ employment agreements~~Employment Agreements to mean (i) any material breach of the ~~employment agreement~~Employment Agreement, including the material breach of any representation, warranty or covenant made under the ~~Holdings Operating~~Employment Agreement by the ~~executive,~~NEO, (ii) the ~~executive’s~~NEO’s breach of any applicable duties of loyalty to usthe Company or any of ~~our~~its affiliates, gross negligence or material misconduct, or a significant act or acts of personal dishonesty or deceit, taken by the ~~executive,~~NEO, in the performance of the duties and services required of the ~~executive~~NEO that ~~has a material adverse effect on us~~is demonstrably and significantly injurious to the Company or any of ~~our~~its affiliates, (iii) conviction ~~or indictment~~ of ~~the executive of, or a plea of nolo contendere by the executive to,~~ a felony or crime involving moral turpitude, (iv) the ~~executive’s~~NEO’s willful and continued failure or refusal to perform substantially the ~~executive’s~~NEO’s material obligations pursuant to the ~~employment agreement or the Holdings Operating~~Employment Agreement or follow any lawful and reasonable directive from the ~~board of managers of USA Compression Holdings (regarding Mr. Long)~~CEO or the ~~board of directors of our general partner (regarding Mr. Manias and Mr. Liuzzi) or,~~Board, as applicable, ~~the chief executive officer,~~ other than as a result of the ~~executive’s~~NEO’s incapacity, or (v) a ~~pattern~~violation of ~~illegal conduct by~~federal, state or local law or regulation applicable to the ~~executive~~business of the Company that is ~~materially~~demonstrably and significantly injurious to ~~us or any of our affiliates or our or their reputation.~~

the Company.

“Good ~~reason”~~Reason” is defined in ~~the NEOs’ employment agreements~~Employment Agreements to mean (i) a material breach by usthe Company of the ~~employment agreement, the Holdings Operating~~Employment Agreement or any other material agreement with the ~~executive,~~NEO, (ii) ~~any failure by us to pay to~~a material reduction in the ~~executive the amounts or benefits to which he is entitled,~~NEO’s base salary, other than ~~an isolated and inadvertent failure not committed in bad faith,~~a reduction that is generally applicable to all similarly situated employees of the Company, (iii) a material reduction in the ~~executive’s~~NEO’s duties, authority, responsibilities, job title or reporting relationships, ~~or responsibilities,~~ (iv) a material reduction by usthe Company in the facilities or perquisites available to the ~~executive or in the executive’s base salary,~~NEO, other than a reduction that is generally applicable to all similarly situated employees, or (v) the relocation of the geographic location of the ~~executive’s~~NEO’s current principal place of employment by more than ~~fifty~~50 miles from the location of the ~~executive’s~~NEO’s principal place of ~~employment. With respect to Mr. Long’s~~ employment ~~agreement, “good reason” also means~~as of the ~~failure to appoint and maintain Mr. Long~~effective date of the Employment Agreement.

“Disability” is defined in the ~~office~~Employment Agreements as the NEO being unable to perform essential functions of ~~President~~his position, with reasonable accommodation, due to an illness or physical or mental impairment or other incapacity which continues for a period in excess of 20 consecutive weeks. The determination of Disability will be made by a physician selected by the NEO and ~~Chief Executive Officer.~~

Inacceptable to the Company or its insurers.

Change in Control Benefits – LTIP

On November 1, 2018, the Compensation Committee adopted the Phantom Unit Agreement, which (i) provides for incremental vesting of Phantom 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 Phantom Units in the event

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of (a) a Change in Control (as defined under the LTIP and set forth below) or (b) the death or Disability of the NEO. Also, under the Phantom Unit Agreement, if the NEO has been employed by the Company, the Partnership or their Affiliates for at least 10 years and is at least 65 at the time of his voluntary retirement, 60% of his then-unvested Phantom Units will be forfeited, and the remainder will vest, at the time of retirement. If the NEO has been employed by the Company, the Partnership or their Affiliates for at least 10 years and is over age 68 at the time of his voluntary retirement, 50% of his then-unvested Phantom Units will be forfeited, and the remainder will vest, at the time of retirement.

Prior to November 1, 2018, we had 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). Under the LTIP award agreements entered into prior to the Transactions, in the event of cessation of the NEO’s service for any reason that is not in connection with a change in control transaction, all ~~phantom units~~Phantom Units that have not vested prior to or in connection with such cessation of service shall automatically be forfeited. ~~With respect~~However, because the agreements contained the double-trigger vesting provisions described below, and the Transactions were deemed to satisfy the time-based awards for Mr. Manias and Mr. Liuzzi, the awards will receive accelerated vesting in the event that that the holder is terminated without cause or for good reason (as each term is defined above with respect to the employment agreements) in connection withfirst trigger of a change in control ~~event. With respect to~~transaction, a termination by the ~~time-based awards~~Company without Cause or by the NEO for ~~Mr. Long,~~Good Reason following the ~~award will receive accelerated vesting~~Transactions would result in connection with a change in control event regardless of whether Mr. Long’s service is terminated in connection with such change in control. All performance-based phantom unit awards will receive accelerated vesting at target levels in connection with a change in control event (subject to the ~~discretion~~acceleration of the ~~compensation committee to vest a greater portion).~~

~~Each of the Class B~~Phantom Units held by the NEOs would be forfeited for no consideration if the NEO was terminated for cause. A termination for “Cause” under the USA Compression Holdings limited liability company agreement is defined substantially the same as the term used within the employment agreements described above. In the event that the NEO’s employment is terminated for any reason, however, USA Compression Holdings (or its nominee) shall have the right, but not the obligation, to repurchase any vested Class B Units held by the terminated NEO for then-current fair market value or other agreed value.

~~Change in Control Benefits~~

~~We generally have double-trigger change in control benefits for our outstanding LTIP awards, although in 2017 and 2016 we~~ granted ~~performance-based phantom unit awards that could become vested upon a change in control. If a~~

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change in control occurs, and our NEOs are also terminated without cause or for good reason (each term as defined in the NEO’s employment agreement) in connection with that change in control event, the current time-based LTIP phantom units would become fully vested. One exception to this practice is with respect to our CEO, who would receive immediate vesting of any outstanding time-based phantom units upon the change in control event. The performance-based phantom units granted during 2017 and 2016 will become eligible to vest at target levels in the event of a change in control. In addition, a portion (subject to the discretion of the compensation committee) of each LTIP award granted to our NEOs during the year ending December 31, 2017 will immediately vest immediately prior to the ~~change in control event.~~Transactions. For ~~example,~~purposes of this description, the ~~number of phantom units that would vest upon change in control as a result of the CDM Acquisition would be 192,471 for Mr. Long, 38,865 for Mr. Manias and 30,886 for Mr. Liuzzi.~~

“Company” means USA Compression GP, LLC.

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

(a)with respect to Awards granted before April 3, 2018, the occurrence of ~~one~~any of the following events: (i) any ~~person~~“person” or ~~group,~~“group” within the meaning of Sections 13(d) and 14(d)(2) of the Exchange Act, other than ~~our general partner,~~the Company, Riverstone Holdings LLC or an ~~affiliate~~Affiliate of ~~our general partner~~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 ~~our equity interests or~~ the equity interests in the Company or the Partnership; (ii) the limited partners of ~~our general partner; (ii) our shareholders~~the Partnership approve, in one or a series of transactions, a plan of complete ~~liquidation;~~liquidation of the Partnership; (iii) the sale or other disposition by either usthe Company or ~~our general partner~~the Partnership of all or substantially all of its assets in one or more transactions to any ~~person~~Person other than ~~to us, our general partner,~~the Company, the Partnership, Riverstone Holdings LLC or an ~~affiliate~~Affiliate of ~~us, our general partner~~the Company, the Partnership or Riverstone Holdings LLC; or (iv) a transaction resulting in a ~~person~~Person other than ~~our general partner,~~the Company, Riverstone Holdings LLC or an ~~affiliate~~Affiliate of ~~our general partner~~the Company (as determined immediately prior to such event) or Riverstone Holdings LLC being ~~our~~the sole general ~~partner.~~ 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 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.

“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.

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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, 2020 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. Except as otherwise noted, the value of the acceleration of the LTIP awards was calculated using the value of $13.60, which was the closing price of the Partnership’s common units on December 31, 2020.


Executive Benefits and Payments	Change in Control followed by termination without “Cause” or for “Good Reason” ($) (3)	Termination of Employment without “Cause” or for “Good Reason” ($) (3)	Termination of Employment because of Death or Disability ($) (4)	Termination by the Executive Other Than for “Good Reason” ($) (5)	Continued Employment Following Change of Control ($) (6)
Eric D. Long
President and Chief Executive Officer
Salary	—	—	—	—	—
Bonus	—	—	—	—	—
Accelerated Vesting of Phantom Units (8)	7,581,320	—	7,581,320	—	7,581,320
Accelerated Vesting of Retention Units (9)	1,791,990	1,791,990	1,791,990	—	1,791,990
Severance Payment under Retention Agreements (10)	361,169	361,169	—	—	—
Totals	9,734,479	2,153,159	9,373,310	—	9,373,310

Matthew C. Liuzzi
Vice President, Chief Financial Officer and Treasurer
Salary	—	—	—	—	—
Bonus	—	—	—	—	—
Accelerated Vesting of Phantom Units (8)	3,096,462	156,645	2,939,817	—	2,939,817
Accelerated Vesting of Retention Units (9)	828,390	828,390	828,390	—	828,390
Severance Payment under Retention Agreements (10)	172,416	172,416	—	—	—
Totals	4,097,268	1,157,451	3,768,207	—	3,768,207

Eric A. Scheller
Vice President and Chief Operating Officer
Salary	—	—	—	—	—
Bonus	—	—	—	—	—
Accelerated Vesting of Phantom Units (8)	1,314,154	30,328	1,283,826	—	1,283,826
Totals	1,314,154	30,328	1,283,826	—	1,283,826

Christopher W. Porter
Vice President, General Counsel and Secretary
Salary (1)	337,307	337,307	22,307	22,307	—
Bonus (2)	482,200	482,200	482,200	—	—
Accelerated Vesting of Phantom Units (8)	1,480,197	39,059	1,441,138	—	1,441,138
Health and Welfare Plan Benefits (7)	20,673	20,673	—	—	—
Totals	2,320,377	879,239	1,945,645	22,307	1,441,138

Sean T. Kimble
Vice President, Human Resources
Salary (1)	331,384	331,384	14,484	14,484	—
Bonus (2)	498,991	498,991	498,991	—	—

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Accelerated Vesting of Phantom Units (8)	1,707,222	108,895	1,598,326	—	1,598,326
Health and Welfare Plan Benefits (7)	20,673	20,673	—	—	—
Totals	2,558,270	959,943	2,111,801	14,484	1,598,326

William G. Manias (11)
Former Vice President and Chief Operating Officer
Salary	—	—	—	—	—
Bonus	—	—	—	—	—
Accelerated Vesting of Phantom Units	—	—	—	—	—
Accelerated Vesting of Retention Units	—	—	—	—	—
Severance Payment under Retention Agreements	—	—	—	—	—
Totals	—	—	—	—	—

________________________

(1)The listed salary for each of Messrs. Porter and Kimble represents his accrued but unused paid time off as of December 31, 2020 plus, with respect to the first two columns, his base salary as of December 31, 2020. Any accrued but unused paid time off owed to Mr. Porter or Mr. Kimble would be paid within 30 days of the date of his termination of employment, and the base salary would be paid out as set forth in footnote (3).

(2)The listed bonus amount for each of Messrs. Kimble and Porter is his pro rata bonus awarded with respect to the year ended December 31, 2020 and his bonus awarded with respect to the year ended December 31, 2019.

(3)The Employment Agreements for each of Messrs. Porter 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 semi-monthly installments over the course of one year. Upon the death of Mr. Porter or Mr. Kimble during this one year period, his salary payment will be accelerated and all remaining Severance Payments (as defined in the Employment Agreements) would be paid in a lump sum within 30 days of his death. If such termination occurs within two years after a “change in control event” within the meaning of Treasury Regulation 1.409A-3(i)(5), the Severance Payment will be made in a lump sum on the first regular payroll date that occurs on or after 30 days of the NEO’s termination date.

(4)Upon the death or Disability (as defined in the Employment Agreements) of Mr. Porter or Mr. Kimble, he (or his estate) will be entitled to the same bonus payment as if the death or Disability had not occurred.

(5)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. None of the NEOs had earned but unpaid annual base salary as of December 31, 2020.

(6)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. Accordingly, 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, and only the acceleration values of outstanding equity at the time of a Change of Control have been reflected.

(7)In the event of Mr. Porter’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 the Coverage Period, 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 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. Messrs. Long, Liuzzi and Scheller are not currently party to any contractual arrangements providing for continued health insurance coverage by the Company following a termination of employment.

(8)In the event of the NEO’s cessation of service for any reason (other than death or Disability), 100% of the NEO’s Phantom 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 Phantom Units granted on December 5, 2018, December 5, 2019 and December 5, 2020 (collectively, the “December LTIP Phantom Units”), if the NEO retires after attaining the age of 65, 60% of his then-unvested December LTIP Phantom Units will be forfeited, and the remainder will vest, at the time of retirement and, if the NEO is over age 68 at the time of retirement, 50% of his then-unvested December LTIP Phantom Units will be forfeited, and the remainder will vest, at the time of retirement. In the event of the death or Disability (as defined under the LTIP) of the NEO, 100% of the then-unvested December LTIP Phantom Units shall vest in full immediately prior to such NEO’s 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 December LTIP Phantom Units would vest. As noted above, the Phantom Units granted prior to the Transactions contained a double-trigger change in control provision, and the Transactions satisfied the first trigger,

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therefore they could become vested upon a termination by the Company without Cause or by the NEO without Good Reason that occurred on December 31, 2020.

(9)The Retention Agreements for Messrs. Long and Liuzzi 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 and 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.

(10)For Messrs. Long and Liuzzi, 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, which payment would be paid within 60 days of the NEO’s date of separation.

(11)Mr. Manias left the Partnership effective June 1, 2020. In recognition of his service and contributions to us, we paid Mr. Manias a separation payment of $1,340,997, as approved by our Compensation Committee. Under the terms of Mr. Manias’s Retention Agreement dated November 1, 2018, in connection with his departure (i) Mr. Manias received a $165,375 release payment and (ii) all 45,000 unvested Phantom Units granted to Mr. Manias under that agreement vested. Additionally, pursuant to the terms of Mr. Manias’s Phantom Unit Agreement dated February 12, 2018, the 14,626 unvested Phantom Units granted to Mr. Manias pursuant to that agreement vested in connection with his departure. These Phantom Units had a value of $585,000 and $190,138, respectively, on the date they vested. In connection with Mr. Manias’s departure and receipt of the payments and Phantom Units described in this footnote, Mr. Manias executed a Full Release and Waiver of Claims in our favor, pursuant to which he released all claims against us and acknowledged his continuing obligations under his Retention Agreement dated November 1, 2018 and his Phantom Unit Agreement dated February 12, 2018, including the non-solicitation and non-disparagement provisions therein. Mr. Manias also received $10,389 of earned but unpaid base salary as of June 1, 2020, the date of his departure, bringing the total amount received by Mr. Manias pursuant to his departure to $2,291,899.

CEO Pay Ratio

Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, require us to provide certain information about the relationship of the annual total compensation of our employees and the annual total compensation of our Chief Executive Officer, Eric Long (our “CEO”). The employees providing services to us are directly employed by USAC Management, therefore we do not have employees for purposes of the pay ratio rules. Rather than providing a pay ratio disclosure that contemplates no employees, we have determined that the disclosure that would be most aligned with the spirit of the pay ratio rules and that would provide our unitholders with more meaningful information would be to provide a ratio using the median employee from the USAC Management employee population. All references to “our” employees within this section shall refer to the applicable USAC Management employees.

For 2020, our last completed fiscal year:

•The median of the annual total compensation of all employees (other than the CEO) was $104,631.

•The annual total compensation of our CEO, as reported in the Summary Compensation Table included elsewhere within this Form 10-K, was $5,153,407.

•Based on this information, for 2020 the ratio of the annual total compensation of Mr. Long to the median of the annual total compensation of all employees was reasonably estimated to be 49.3 to 1.

To identify the median of the annual total compensation of all our employees, as well as to determine the annual total compensation of our median employee and our CEO, we took the following steps:

•We determined that, as of December 31, 2020, our employee population consisted of approximately 742 individuals with all of these individuals located in the U.S. This population consisted of our full-time employees, as we do not have any part-time employees, temporary employees, or seasonal workers.

•We selected December 31, 2020 as our identification date for determining our median employee because it enabled us to make such identification in a reasonably efficient and economic manner.

•We used a consistently applied compensation measure to identify our median employee of comparing the amount of salary or wages, bonuses, compensation received from equity award vesting, and any other compensation items reported to the Internal Revenue Service on Form W-2 for 2020.

•We identified our median employee by consistently applying this compensation measure to all of our employees included in our analysis. Since all of our employees, including our CEO, are located in the U.S., we did not make any cost of living adjustments in identifying the median employee.

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•After we identified our median employee, we combined all of the elements of such employee’s compensation for the 2020 year in accordance with the requirements of Item 402(c)(2)(x) of Regulation S-K, resulting in annual total compensation of $104,631.

•With respect to the annual total compensation of our CEO, we used the amount reported in the “Total” column of our 2020 Summary Compensation Table included in this Form 10-K.

Director Compensation

For the year ended December 31, ~~2017, Mr. Long,~~2020, our CEO was the only NEO who also served as a director, and he did not receive additional compensation for his service ~~as a director.~~on the Board. Mr. Long’s compensation as an ~~executive~~NEO is reflected in the Summary Compensation Table above. ~~Only the independent members of the board of directors of our general partner receive compensation for their service as directors.~~

~~The following table shows the total compensation earned by each independent director during 2017.~~

Fees Earned or



All Other


Paid in Cash

Unit Awards

Compensation

Total
Name

($)

($) (1)

($) (2)

($)
John D. Chandler

85,500

—
(3)
23,861

109,361
Robert F. End

136,000

75,000

23,861

234,861
Forrest E. Wylie

117,000
(4)
75,000

47,725

239,725
Jerry L. Peters

46,500

—

—

46,500

~~(1)~~

Represents the grant date fair value of our phantom units, calculated in accordance with ASC 718. For a detailed discussion of the assumptions utilized in coming to these values, please see Note 9 to our consolidated financial statements. As of December 31, 2017, the independent members of the board of directors of our general partner held the following number of outstanding equity awards under the LTIP: Mr. End, 4,073 phantom units; and Mr. Wylie, 8,147 phantom units.

~~(2)~~

~~Amounts in this column reflect the value of DERs, received by the directors with respect to their outstanding phantom unit awards.~~

~~(3)~~

~~Mr. Chandler’s outstanding equity awards were forfeited upon his resignation during 2017.~~

~~(4)~~

~~Mr. Wylie elected to receive his annual cash retainer of $75,000 in phantom units that will vest in full on February 15, 2018.~~

Officers, employees or paid consultants or advisors of us or ~~our general partner~~the General Partner or its affiliates who also serve as directors do not receive additional compensation for their service as directors. ~~Our~~Other than Mr. Hartman, our directors who are not officers, employees or paid consultants or advisors of us or ~~our general partner~~the General Partner or its affiliates receive cash and equity based

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compensation for their services as directors. Our director compensation program ~~consists of the following and will be~~is subject to revision by the ~~board of directors of our general partner~~Board from time to ~~time:~~

time.

The following table shows the total fees earned and other compensation paid in cash to each independent director during 2020.


Name	Fees Paid in Cash ($)	Unit Awards ($) (1)	All Other Compensation ($) (2)	Total ($)
Matthew S. Hartman (3)	—	—	—	—
Glenn E. Joyce	130,000	99,985	45,851	275,836
William S. Waldheim	132,500	99,985	45,851	278,336

________________________

(1)Represents the grant date fair value of our Phantom Units, calculated in accordance with ASC 718. For a detailed discussion of the assumptions utilized in coming to these values, please see Note 15 in Part II, Item 8 “Financial Statements and Supplementary Data”. As of December 31, 2020, the independent members of the Board who receive equity awards held the following number of outstanding equity awards under the LTIP: Mr. Joyce: 16,617 Phantom Units; and Mr. Waldheim: 16,617 Phantom Units. The Phantom Units granted in 2020 to Messrs. Joyce and Waldheim vest incrementally, with 60% of the Phantom Units vesting on December 5, 2022 and the remaining 40% of the Phantom Units vesting on December 5, 2024. In the event of the director’s cessation of service due to death, Disability or a Change in Control, 100% of his outstanding, unvested Phantom 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 each quarter in the 2020 year.

(3)Mr. Hartman was appointed to the Board pursuant to that certain Board Representation Agreement entered to among us, the General Partner, ET LP 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.

On July 30, 2018 the Board adopted the Amended and Restated Outside Director Compensation Policy (the “Director Compensation Policy”), which provides for: (i) an annual cash retainer of $100,000; (ii) an annual cash retainer for acting as the Chairman of the Audit Committee and for acting as Chairman of the Compensation Committee; (iii) an annual cash retainer for membership on the Audit Committee or Compensation Committee; (iv) an undetermined fixed sum for membership on a special or conflicts committee; (v) an annual equity grant with a value of $100,000; and (vi) a one-time director onboarding equity award of 2,500 Phantom Units. The Phantom Units granted pursuant to the Director Compensation Policy vest incrementally over five years and all outstanding, unvested Phantom Units vest in full in the event of the director’s death, Disability or upon a Change in Control (each as defined in the LTIP). The Director Compensation Policy does not provide for per meeting attendance fees.

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The following chart summarizes the Director Compensation Policy.

~~an annual cash retainer of $75,000,~~

Compensation Element	·	Director Compensation Detail
Annual Cash Retainer	~~an additional annual retainer of~~	$100,000

Committee Chair Cash Retainer		Audit Committee: $25,000 Compensation Committee: $15,000 ~~for service as the chair of any standing committee,~~

			·
Committee Membership Retainer (if not Committee Chair)			~~meeting attendance fees of $2,000 per meeting attended, and~~			Audit Committee: $15,000 Compensation Committee: $7,500

	·
Initial Phantom Unit Award	~~an annual equity based award in the form of phantom units that will be granted under the LTIP, having a~~	2,500 Phantom Units

Annual Phantom Unit Award		$100,000 value ~~as of the grant date of $75,000.~~

DERs on Unvested Phantom ~~unit awards are expected to be subject to vesting conditions (which, for the 2017 phantom unit grants was a one year vesting period). DERs will be paid either~~Units		Yes (paid on a current basis)

Phantom Unit Vesting Schedule		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

Cessation of Service due to Death or ~~deferred basis,~~Disability		Unvested Phantom Units vest in ~~each case as will be determined at the time~~full

Attendance Fee Per Meeting		None

Reimbursement of ~~grant of the awards; the 2017 phantom unit awards provided for deferred DERs.~~ Out-of-Pocket Expenses		Yes

Indemnification		Yes, to fullest extent permitted under Delaware law

Directors will also receive reimbursement for out-of-pocket expenses associated with attending such board or committee meetings and director and officer liability insurance coverage. Each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law.

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

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 ~~our~~the Partnership’s common units and Preferred Units as of February ~~8, 2018~~11, 2021 held by:

~~each person who beneficially owns 5% or more of our outstanding units;~~

~~all of the directors of USA Compression GP, LLC;~~

~~each named executive officer of USA Compression GP, LLC; and~~

~~all directors and executive officers of USA Compression GP, LLC as a group.~~

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

•all of the directors of the General Partner;

~~Table~~•each NEO of ~~Contents~~

the General Partner; and

•all directors and executive officers of the General Partner as a group.

As of February 11, 2021, there were 96,996,304 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~~111 Congress Avenue, Suite ~~450,~~2400, Austin, Texas 78701.

Percentage of

Common Units

Common Units

Name of Beneficial Owner

Beneficially Owned

Beneficially Owned

USA Compression Holdings (1)

25,092,196

40.3
%
Argonaut (2)

7,715,948

12.4
%
Oppenheimer Funds, Inc. (3)

6,529,518

10.5
%
Eric D. Long (4)

359,579

*

William G. Manias (5)

161,620

*

Matthew C. Liuzzi (6)

111,764

*

Jerry L. Peters

—

—

Jim H. Derryberry

—

—

William H. Shea, Jr.

—

—

Robert F. End (7)

33,717

*

Olivia C. Wassenaar

—

—

Forrest E. Wylie (8)

54,116

*

All directors and executive officers

as a group (12 persons) (9)

856,973

1.4
%
Any fractional common units are rounded down to the nearest whole number.

The table also presents information with respect to ET LP’s common units beneficially owned as of February 11, 2021, by each current director and named executive officer of the General Partner and by all directors and executive officers of the General Partner as a group. As of February 11, 2021, ET LP had 2,702,436,307 common units outstanding. Any fractional common units are rounded down to the nearest whole number.

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	USA Compression Partners, LP			Energy Transfer LP
Name of Beneficial Owner	Common Units Beneficially Owned	Percentage of Common Units		Common Units Beneficially Owned	Percentage of Common Units
Energy Transfer Operating, L.P. (1) (2)	46,056,228	47.48	%	—	*
Invesco Ltd. (3)	18,181,762	18.74	%	—	*
EIG Veteran Equity Aggregator, L.P. (4)	19,626,959	16.83	%	—	*
Eric D. Long (5)	529,327	*		22,144	*
Matthew C. Liuzzi (6)	237,500	*		—	*
Eric A. Scheller (7)	39,169	*		—	*
Christopher W. Porter (8)	20,051	*		—	*
Sean T. Kimble (9)	91,186	*		500	*
William G. Manias	246,772	*		—	*
Christopher R. Curia	—	*		258,424	*
Matthew S. Hartman	—	*		—	*
Glenn E. Joyce	5,217	*		2,000	*
Thomas E. Long	—	*		395,231	*
Thomas P. Mason	—	*		598,760	*
Matthew S. Ramsey	—	*		428,745	*
William S. Waldheim	5,217	*		—	*
Bradford D. Whitehurst (10)	—	*		280,680	*
All directors and officers as a group (14 persons) (11)	1,174,439	1.21	%	1,986,484	*

________________________

*Less than 1%.

~~(1)~~

~~Eric D. Long, Matthew C. Liuzzi, William G. Manias, and David A. Smith, each of whom are executive officers of our general partner, Aladdin Partners, L.P., a limited partnership affiliated~~(1)Energy Transfer Operating, L.P. has shared voting and dispositive power over 46,056,228 common units based on a Schedule 13D/A filed on August 5, 2019 with Mr. Long, and R/C IV USACP Holdings, L.P. (“R/C Holdings”), own equity interests in USA Compression Holdings. USA Compression Holdings is managed by a three person board of managers consisting of Mr. Long, Mr. Derryberry and Ms. Wassenaar. The board of managers exercises investment discretion and control over the units held by USA Compression Holdings.

~~R/C Holdings is~~ the ~~record holder of approximately 97.6% of the limited liability company interests of~~SEC. The Schedule 13D/A was filed jointly by Energy Transfer LP, LE GP, LLC, Kelcy L. Warren, USA Compression ~~Holdings~~GP, LLC, Energy Transfer Partners, L.L.C., Energy Transfer Partners GP, L.P. and ~~is entitled to elect a majority of~~Energy Transfer Operating, L.P. (collectively, the ~~members of the board of managers of USA Compression Holdings. R/C Holdings is an investment partnership affiliated with Riverstone/Carlyle Global Energy and Power Fund IV, L.P. (“R/C IV”~~“ET Reporting Companies”). ~~Management and control of R/C Holdings is vested in its general partner, which is in turn managed and controlled by its general partner, R/C Energy GP IV, LLC.~~ The principal business address of ~~R/C Energy~~each of the ET Reporting Companies, other than USA Compression GP, ~~IV,~~ LLC, is ~~712 Fifth Avenue, 51st Floor, New York, New York 10019.~~

~~Mr. Long, Mr. Derryberry and Ms. Wassenaar, each of whom is a member of the board of managers~~8111 Westchester Drive, Suite 600, Dallas, Texas 75225. The principal business address of USA Compression ~~Holdings and a member of the board of directors of our general partner, each disclaims beneficial ownership of the~~GP, LLC is 111 Congress Avenue, Suite 2400, Austin, Texas 78701.

(2)Includes 8,000,000 common units ~~owned~~held by USA Compression ~~Holdings.~~

~~(2)~~

~~Argonaut has sole voting and dispositive power of 7,715,948 common units. The principal business address of Argonaut is 6733 South Yale Avenue, Tulsa, Oklahoma 74136.~~

~~(3)~~

Oppenheimer Funds, Inc. has the shared power to vote or to direct the vote, and the shared power to dispose or to direct the disposition of, 6,529,518 common units based on Amendment No. 8 to Schedule 13G filed on February 6, 2018 with the SEC. The principal business address of Oppenheimer Funds, Inc. is Two World Financial Center, 225 Liberty Street, New York, New York 10281.

~~(4)~~

Includes 184,947 common units held directly by Mr. Long, 7,592 common units held by Aladdin Partners, L.P., a limited partnership affiliated with Mr. Long, 45,248 common units held by certain trusts of which Mr. Long is the trustee, 2,174 common units held by Mr. Long’s spouse and 119,618 common units that Mr. Long has the right to acquire within 60 days upon the vesting and/or settlement of his phantom units, subject to compensation committee discretion. Mr. Long disclaims any beneficial ownership of the units held by Mr. Long’s spouse, except to the extent of his pecuniary interest therein. Mr. Long also has the right to acquire an additional 192,471 common units upon vesting and/or settlement of his phantom units upon the closing of the CDM Acquisition, which could occur within 60 days from February 8, 2018.

~~(5)~~

Includes 63,988 common units that Mr. Manias has the right to acquire within 60 days upon the vesting and/or settlement of his phantom units, subject to compensation committee discretion. Mr. Manias also has the right to acquire an additional 38,865

GP, LLC.

(3)Invesco Ltd. has the sole power to dispose or to direct the disposition of 18,181,762 common units based on a Schedule 13G/A filed on February 12, 2021 with the SEC. Invesco Ltd., in its capacity as a parent holding company to its investment advisers, may be deemed to beneficially own these 18,181,762 common units which are held of record by clients of Invesco Ltd. The principal business address of Invesco Ltd. is 1555 Peachtree Street NE, Suite 1800, Atlanta GA 30309.

(4)EIG Veteran Equity Aggregator, L.P. holds Warrants to acquire (i) 4,206,640 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 became exercisable on April 2, 2019 and will expire on April 2, 2028. EIG owns 420,664 Preferred Units, 140,221 of which will be convertible within 60 days into 7,007,038 common units at the election of the holder. At the option of the holder of Preferred Units, (i) from and after April 2, 2021, 33 1/3% of the Preferred Units are convertible into common units, (ii) from and after April 2, 2022, 66 2/3% of the Preferred Units are convertible into common units and (iii) from and after April 2, 2023, all of the Preferred Units are convertible into common units. Upon (1) exercise of the Warrants in full and assuming the Partnership does not elect to settle the Warrants in common units on a net basis, and (2) conversion of all 140,221 Preferred Units, EIG would have sole voting and dispositive power over 19,626,959 common units of the Partnership based on the Schedule 13D/A filed on February 1, 2021 with the SEC and our records. The principal business address of EIG Veteran Equity Aggregator, L.P. is 1700 Pennsylvania Ave NW, STE. 800, Washington, DC 20006.

(5)Includes 455,371 of our common units held directly by Mr. Long, 17,592 of our common units held by Aladdin Partners, L.P., a limited partnership affiliated with Mr. Long and, 56,364 of our common units held by certain trusts of which Mr. Long is the trustee. The ET LP common units reported as owned by Mr. Long include 12,000 common units held directly by Mr. Long, 4,000 common units held by Aladdin Partners, L.P., and 6,144 common units held by certain trusts of which Mr. Long is the trustee.

(6)Includes 11,518 common units that Mr. Liuzzi has the right to acquire within 60 days upon the vesting and/or settlement of his Phantom Units, subject to Compensation Committee discretion.

(7)Includes 2,230 common units that Mr. Scheller has the right to acquire within 60 days upon the vesting and/or settlement of his Phantom Units, subject to Compensation Committee discretion.

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(8)Includes 2,872 common units that Mr. Porter has the right to acquire within 60 days upon the vesting and/or settlement of his Phantom Units, subject to Compensation Committee discretion.

~~common units upon vesting and/or settlement of his phantom units upon the closing of the CDM Acquisition, which could occur within 60 days from February 8, 2018.~~

(9)Includes 8,007 common units that Mr. Kimble has the right to acquire within 60 days upon the vesting and/or settlement of his Phantom Units, subject to Compensation Committee discretion.

~~(6)~~

Includes 51,024 common units that Mr. Liuzzi has the right to acquire within 60 days upon the vesting and/or settlement of his phantom units, subject to compensation committee discretion. Mr. Liuzzi also has the right to acquire an additional 30,886 common units upon vesting and/or settlement of his phantom units upon the closing of the CDM Acquisition, which could occur within 60 days from February 8, 2018.

(10)Mr. Whitehurst holds 186,898 of ET LP’s common units in a margin account.

~~(7)~~

~~Includes 4,073 common units that Mr. End has the right to acquire within 60 days upon the vesting and/or settlement of his phantom units.~~

(11)Includes 24,627 of our 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.

~~(8)~~

~~Includes 8,147 common units that Mr. Wylie has the right to acquire within 60 days upon the vesting and/or settlement of his phantom units.~~

~~(9)~~

Includes 309,891 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. Certain of our directors and executive officers have the right to acquire an additional 300,568 common units upon vesting and/or settlement of phantom units held by such directors and executive officers upon the closing of the CDM Acquisition, which could occur within 60 days from February 8, 2018.

Securities Authorized for Issuance Under Equity Compensation Plans

In connection with ~~the consummation of~~ our ~~initial public offering~~IPO on January 18, 2013, the ~~board of directors of our general partner~~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 brought 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 ~~this plan~~the LTIP as of December 31, ~~2017:~~

Number of securities

remaining available for

future issuance under

Number of securities to

Weighted-average

equity compensation

be issued upon exercise

exercise price of

plan (excluding securities

of outstanding options,

outstanding options,

reflected in the first

Plan Category

warrants and rights

warrants and rights

column)

Equity compensation plans approved by security holders

—

N/A

—

Equity compensation plans not approved by security holders

1,086,858

N/A

—
(1)
2020:

Plan Category

Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights

Weighted-average
exercise price of
outstanding options,
warrants and rights

Number of securities
remaining available for
future issuance under
equity compensation
plan (excluding securities
reflected in the first
column)

Equity compensation plans approved by security holders

—

N/A

—

Equity compensation plans not approved by security holders

2,137,957

N/A

6,327,375

(1)

~~(1)~~

As of December 31, 2017, the number of common units that may be delivered pursuant to awards under the LTIP was 755,804 common units before giving effect to any outstanding awards. Awards that are forfeited, cancelled, paid or otherwise terminate or expire without the actual delivery of units will be available for delivery pursuant to other awards. Currently, only phantom unit awards are outstanding under the LTIP. Pursuant to the terms of the LTIP, each phantom unit award is the economic equivalent of one common unit and may be settled in cash or common units at the discretion of the board of directors of our general partner or a committee thereof. Any phantom unit settled in cash will not result in the actual delivery of a common unit.

________________________

(1)As of December 31, 2020, we had 8,465,332 common units available under the LTIP before giving effect to the outstanding awards of 2,137,957 Phantom Units. Pursuant to the terms of the LTIP, other than director Phantom Unit awards, awards of Phantom Units 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. Additionally, Phantom Units withheld to satisfy the exercise price or tax withholdings of an award and Phantom Units that are forfeited, cancelled, or otherwise terminate or expire without the actual delivery of common units will be available for delivery pursuant to other awards.

For more information about ~~our~~the LTIP, please see Note ~~9 to our consolidated financial statements.~~

15 in Part II, Item 8 “Financial Statements and Supplementary Data”.

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

Certain Relationships ~~And~~and Related Party Transactions

Services Agreement

In connection with our formation and ~~initial public offering,~~IPO, we and other parties have entered into the ~~following agreements.~~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.

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We entered into ~~a services agreement~~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 ~~our general partner~~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.~~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

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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 ~~term of the services agreement~~Services Agreement was ~~extended~~amended to extend its term to December 31, ~~2022 pursuant to an amendment to that certain services agreement.~~2022. The ~~services agreement~~Services Agreement may be terminated at any time by (i) the ~~board of directors of our general partner~~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 ~~our general partner~~the General Partner experience a ~~change~~Change of ~~control;~~Control (as defined in the Services Agreement); (b) we or ~~our general partner~~the General Partner breach the terms of the ~~services agreement~~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 ~~our general partner’s~~the General Partner’s property or an order is made to wind up our or ~~our general partner’s~~the General Partner’s business; (d) a final judgment, order or decree that materially and adversely affects the ability of us or ~~our general partner~~the General Partner to perform under the ~~services agreement~~Services Agreement is obtained or entered against us or ~~our general partner,~~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 ~~our general partner~~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~~Services Agreement unless its acts or omissions constitute gross negligence or willful misconduct.

~~Other Related Party~~

Transactions

with Energy Transfer

We provide compression services to entities affiliated with ~~Riverstone/Carlyle Global~~ Energy ~~and Power Fund IV, L.P. (“Riverstone”),~~Transfer, which ~~owns~~became a ~~majority~~related party of ours on the Transactions Date as a result of the ~~membership interests in USA Compression Holdings. As~~Transactions and its resultant ownership and control of ~~December 31, 2017, USA Compression Holdings owned~~the General Partner and ~~controlled our general partner and owned~~ownership of approximately ~~40%~~47% of our limited partner ~~interests.~~interests as of December 31, 2020 (including the 8,000,000 common units owned by the General Partner). We recognized ~~$0.7 million and $0.4~~$12.4 million in revenue from compression services from ~~such~~entities affiliated ~~entities~~with Energy Transfer for the ~~years~~year ended December 31, ~~2017 and 2016, respectively.~~2020. We may provide compression services to entities affiliated with ~~Riverstone~~Energy Transfer in the future, and any significant transactions will be disclosed.

~~Procedures for Review, Approval~~

The following table summarizes payments and ~~Ratification of Related Person Transactions~~

~~The board of directors of our general partner adopted a code of business conduct~~receivables between us and ethics in connection with the closing of our initial public offering that provides that the board of directors of our general partner or its authorized committee will periodically review all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. If the board of directors of our general partner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the code of business conduct and ethics provides that our management will make all reasonable efforts to cancel or annul the transaction.

The code of business conduct and ethics provides that, in determining whether or not to recommend the initial approval or ratification of a related person transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to: (i) whether there is an appropriate business justification for the transaction; (ii) the benefits that accrue to us as a result of the transaction; (iii) the terms available to unrelated third parties entering into similar transactions; (iv) the impact of the transaction on a director’s independence (in the event the related person is a director, an immediate family member of a director or an entity in which a director or an immediate family member of a director is a partner, shareholder, member or executive officer); (v) the availability of other sources for comparable products or services; (vi) whether it is a single transaction or a series of ongoing, related transactions; and (vii) whether entering into the transaction would be consistent with the code of business conduct and ethics.

The code of business conduct and ethics described above was adopted in connection with the closing of our initial public offering, and as a result the transaction described above was not reviewed under such policy. The transaction

Energy Transfer during 2020.

Transaction

Explanation

Amount/Value

2020 quarterly distributions on limited partner interests

Represents the aggregate amount of distributions made to Energy Transfer in respect of the Partnership’s common units during 2020.

96.7 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 2020.

12.4 million

Sales Tax Contingency

Receivable from ETO as of December 31, 2020 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, 2020.

0.1 million

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~~described above was not approved by an independent committee of our board of directors of our general partner and the terms were determined by negotiation among the parties.~~

Conflicts of Interest

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

Whenever a conflict arises between ~~our general partner~~the General Partner or its affiliates, on the one hand, and usthe Partnership and ~~our~~its limited partners, on the other hand, ~~our general partner~~the General Partner will resolve that conflict. ~~Our partnership agreement~~The Partnership Agreement contains provisions that modify and limit ~~our general partner’s~~the General Partner’s fiduciary duties to ~~our~~the Partnership’s unitholders. ~~Our partnership agreement~~The Partnership Agreement also restricts the remedies available to ~~our~~the Partnership’s unitholders for actions taken by ~~our general partner~~the General Partner that, without those limitations, might constitute breaches of its fiduciary duty.

~~Our general partner~~

The Partnership Agreement provides that the General Partner will not be in breach of its obligations under ~~our partnership agreement~~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 ~~conflict is:~~

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.

~~approved by the conflicts committee of our general partner, although our general partner is not obligated to seek such approval;~~

~~approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or any of its affiliates;~~

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~~on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or~~

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

~~Our general partner~~The General Partner may, but is not required to, seek the approval of such resolution from the conflicts committee of ~~its board of directors.~~the Board. In connection with a situation involving a conflict of interest, any determination by ~~our general partner involving~~ the ~~resolution of the conflict of interest~~General Partner must be made in good faith, provided that, if ~~our general partner~~the General Partner does not seek approval from the conflicts committee and ~~its board of directors~~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 ~~the third and fourth bullet points~~subclauses (c) or (d) above, then it will conclusively be deemed that, in making its decision, the ~~board of directors~~Board acted in good faith. Unless the resolution of a conflict is specifically provided for in ~~our partnership agreement, our general partner~~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 ~~our partnership agreement~~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.~~

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,~~“Directors, Executive Officers and Corporate ~~Governance—~~Governance – Board of Directors”) for a discussion of director independence matters.

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ITEM 14.Principal Accountant Fees and Services

The following table ~~presents~~sets forth fees paid for professional services rendered by ~~our independent registered public accounting firm, KPMG~~Grant Thornton LLP (“Grant Thornton”) during the years ended December 31, ~~2017~~2020 and ~~2016:~~

Year Ended December 31,

2017

2016

(in millions)
Audit Fees (1)

$
0.6

$
0.6
Audit-Related Fees

—

—
Tax Fees

—

—
All Other Fees

—

—
Total

$
0.6

$
0.6
2019 (in millions):


	Year Ended December 31,
	2020		2019

Audit fees (1)	$	1.0	$	1.1
Audit-related fees	—		—
Tax fees	—		—
All other fees	—		—
Total	$	1.0	$	1.1

~~(1)~~

Expenditures classified as “Audit Fees” above were billed to USA Compression Partners, LP and include the audits of our annual financial statements, work related to the registration statements, reviews of our quarterly financial statements, and fees associated with comfort letters and consents related to equity offerings and registration statements.

________________________

~~Our audit committee~~

(1)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 ~~an audit committee charter,~~the Audit Committee Charter, which is available on our website and which requires the ~~audit committee~~Audit Committee to pre-approve all audit and non-audit services to be provided by our independent registered public accounting firm. The ~~audit committee~~Audit Committee does not delegate its pre-approval responsibilities to management or to an individual member of the ~~audit committee.~~

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

~~(a)~~

~~Documents filed as a part of this report.~~

2.Financial Statement Schedule

~~Financial Statements. See “Index to Consolidated Financial Statements” set forth on Page F-1.~~

~~Financial Statement Schedule~~

All other schedules have been omitted because they are not required under the relevant instructions.

~~Exhibits~~

1.Exhibits

The following documents are filed as exhibits to this report:


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						~~First~~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 ~~January 18, 2013)~~April 6, 2018)

~~10.1~~ 4.1						~~Fifth~~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						Indenture, dated as of March 7, 2019 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 7, 2019)

4.5						Form of 6.875% Senior Note due 2027 (incorporated by reference to Exhibit 4.2 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on March 7, 2019)

4.6						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)

4.7						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)

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4.8						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)

4.9						Description of the USA Compression Partners, LP Common Units (incorporated by reference to Exhibit 4.10 to the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2019 (File No. 001-35779) filed on February 18, 2020)

10.1						Sixth Amended and Restated Credit Agreement, dated as of ~~December 13, 2013,~~April 2, 2018, by and among ~~USA Compression Partners, LP,~~the Partnership, as borrower, USAC OpCo 2, LLC, ~~and~~ USAC Leasing 2, LLC, ~~as guarantors,~~ USA Compression Partners, LLC, ~~and~~ USAC Leasing, LLC, ~~as borrowers,~~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, ~~J.P. Morgan Securities LLC, as lead arranger~~JPMorgan Chase Bank, N.A., Barclays Bank PLC, Regions Capital Markets, a division of Regions Bank, RBC Capital Markets and ~~sole book runner,~~ Wells Fargo Bank, N.A., as ~~documentation agent,~~joint lead arrangers and joint book runners, Barclays Bank PLC, Regions Bank, RBC Capital Markets and Wells Fargo Bank, N.A., as syndication ~~agent~~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 ~~December 17, 2013)~~April 6, 2018)

10.2						~~Letter~~Amendment No. 1 to Sixth Amended and Restated Credit Agreement, ~~by and~~dated as of August 3, 2020, among USA Compression Partners ~~LLC, USAC Leasing, LLC, USA Compression Partners,~~ LP, ~~USAC Leasing 2, LLC, USAC OpCo 2, LLC,~~as borrower, each of the Guarantors and Lenders party thereto and JPMorgan Chase ~~Bank,~~bank, N.A., ~~in its capacity~~ as ~~administrative agent for~~an LC Issuer and as the ~~Lenders, dated as of June 30, 2014~~Agent (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K (File No. 001-35779) filed on ~~July~~August 3, ~~2014)~~2020)

~~10.3~~ 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)

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.

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 2015 to 3025 years. Amortization expense for the year ended December 31, 2017 was $3.5 million and for each of the years ended December 31, 2016 and 2015 was $3.6 million. The expected amortization of the identifiable intangible assets for each of the five succeeding years is as follows (in thousands):

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. In the first quarter of 2020, we determined that the impairment of our goodwill was an indicator of potential impairment of the carrying amount of our identifiable intangible assets. Accordingly, we performed a quantitative impairment test of our identifiable intangible assets, by which we determined that they were not also impaired. No triggering events have been identified subsequent to the first quarter of 2020.

~~The Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification (“ASC”)~~

The ~~revolving credit facility~~Credit Agreement also contains various financial covenants, including covenants requiring us to maintain:

~~All~~ of our ~~outstanding subordinated units, which were held~~available cash 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;

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, 2017 were $122.2 million, of which $119.7 million are expected to be settled within the next twelve months.

Our compliance with state and local sales tax regulations is subject to audit by various taxing authorities. Certain taxing authorities have either claimed or issued an assessment that specific operational processes, which we and ~~others~~other companies in our industry regularly conduct, result in transactions that are subject to state sales taxes. We and other ~~entities~~companies in our industry have disputed these claims and assessments based on either existing tax statutes ~~which provide for manufacturing exemptions on~~or published guidance by the ~~transactions~~taxing authorities.


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)~~


Large accelerated filer ☐		☐		Accelerated filer		☒

Non-accelerated filer ☐	☐		Smaller reporting company		☐
~~(Do not check if a smaller reporting company)~~

Emerging growth company ☒		☐


PART I			1 1

	Item 1.	Business	2 2
	Item 1A.	Risk Factors	11 15
	Item 1B.	Unresolved Staff Comments	33 38
	Item 2.	Properties	34 38
	Item 3.	Legal Proceedings	34 38
	Item 4.	Mine Safety Disclosures	34 39

PART II			35 39

	Item 5.	Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	35 39
	Item 6.	Selected Financial Data	36 40
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42 48
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	55 63
	Item 8.	Financial Statements and Supplementary Data	55 64
	Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	56 64
	Item 9A.	Controls and Procedures	56 64
	Item 9B.	Other Information	58 65

PART III			59 66

	Item 10.	Directors, Executive Officers and Corporate Governance	59 66
	Item 11.	Executive Compensation	64 72
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	85 81
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	87 83
	Item 14.	Principal Accountant Fees and Services	89 86

PART IV			90 87

	Item 15.	Exhibits and Financial Statement Schedules	90 87


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


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


COVID-19						novel coronavirus 2019
Credit Agreement						Sixth Amended and Restated Credit Agreement by and among USA Compression Partners, LP, 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 USA Compression Finance Corp., the lenders party thereto from time to time, JPMorgan Chase Bank, N.A., as agent and a letter of credit 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, as amended, and may be further amended from time to time.
DERs						distribution equivalent rights
DRIP						distribution reinvestment plan
EBITDA						earnings before interest, taxes, depreciation and amortization
EIA						United States Energy Information Agency

Exchange Act						Securities Exchange Act of 1934, as amended
GAAP						generally accepted accounting principles of the United States of America
LIBOR						London Interbank Offered Rate
Preferred Units						Series A Preferred Units representing limited partner interests in USA Compression Partners, LP
SEC						United States Securities and Exchange Commission
Senior Notes 2026						$725.0 million aggregate principal amount of senior notes due on April 1, 2026
Senior Notes 2027						$750.0 million aggregate principal amount of senior notes due on September 1, 2027

U.S.						United States of America


	Year Ended						Percent
	December 31,						Change
Operating Data:	2017		2016		2015		2017		2016
Fleet horsepower (at period end) (1)	1,799,781		1,720,547		1,712,196		4.6	%	0.5	%
Total available horsepower (at period end) (2)	1,950,301		1,730,547		1,712,196		12.7	%	1.1	%
Revenue generating horsepower (at period end) (3)	1,624,377		1,387,073		1,424,537		17.1	%	(2.6)	%
Average revenue generating horsepower (4)	1,505,657		1,377,966		1,408,689		9.3	%	(2.2)	%
Revenue generating compression units (at period end)	2,830		2,552		2,737		10.9	%	(6.8)	%
Average horsepower per revenue generating compression unit (5)	554		534		517		3.7	%	3.3	%
Horsepower utilization (6):
At period end	94.8	%	87.1	%	89.2	%	8.8	%	(2.4)	%
Average for the period (7)	92.0	%	87.4	%	90.5	%	5.3	%	(3.4)	%


					Cash
					Distribution
	Price Range				Declared Per
Period	High		Low		Common Unit		Date Paid
First Quarter 2016	$	11.89	$	7.03	$	0.525	May 13, 2016
Second Quarter 2016	$	16.42	$	10.50	$	0.525	August 12, 2016
Third Quarter 2016	$	18.90	$	14.02	$	0.525	November 14, 2016
Fourth Quarter 2016	$	19.33	$	15.41	$	0.525	February 14, 2017
First Quarter 2017	$	19.78	$	16.13	$	0.525	May 12, 2017
Second Quarter 2017	$	17.85	$	14.30	$	0.525	August 11, 2017
Third Quarter 2017	$	17.84	$	14.55	$	0.525	November 10, 2017
Fourth Quarter 2017	$	17.64	$	15.48	$	0.525	February 14, 2018


	Year Ended December 31,									Percent Change
Operating Data:	2017			2016			2015			2017		2016
Fleet horsepower (at period end) (1)		1,799,781			1,720,547			1,712,196		4.6	%	0.5	%
Total available horsepower (at period end) (2)		1,950,301			1,730,547			1,712,196		12.7	%	1.1	%
Revenue generating horsepower (at period end) (3)		1,624,377			1,387,073			1,424,537		17.1	%	(2.6)	%
Average revenue generating horsepower (4)		1,505,657			1,377,966			1,408,689		9.3	%	(2.2)	%
Average revenue per revenue generating horsepower per month (5)	$	15.07		$	15.41		$	15.90		(2.2)	%	(3.1)	%
Revenue generating compression units (at period end)		2,830			2,552			2,737		10.9	%	(6.8)	%
Average horsepower per revenue generating compression unit (6)		554			534			517		3.7	%	3.3	%
Horsepower utilization (7):
At period end		94.8	%		87.1	%		89.2	%	8.8	%	(2.4)	%
Average for the period (8)		92.0	%		87.4	%		90.5	%	5.3	%	(3.4)	%


	Payments Due by Period
									More than
Contractual Obligations	Total		1 year		2 - 3 years		4 - 5 years		5 years
	(in thousands)
Long-term debt (1)	$	782,902	$	—	$	782,902	$	—	$	—
Interest on long-term debt obligations (2)		54,622		27,088		27,534		—		—
Equipment/capital purchases (3)		122,156		119,656		2,500		—		—
Operating lease obligations (4)		2,946		1,517		1,357		72		—
Total contractual cash obligations	$	962,626	$	148,261	$	814,293	$	72	$	—


					All Other
				Unit Awards	Compensation
Name and Principal Position	Year	Salary ($)	Bonus ($) (1)	($) (2)	($)		Total ($)
Eric D. Long	2017	625,233	721,436	1,953,127	755,233	(3)	4,055,029
President and Chief Executive Officer	2016	607,019	773,419	1,892,893	742,412		4,015,743
William G. Manias	2017	423,886	396,711	993,108	389,700	(4)	2,203,405
Vice President and Chief Operating Officer	2016	411,538	416,353	1,069,430	380,616		2,277,937
Matthew C. Liuzzi	2017	375,538	329,496	782,050	313,209	(5)	1,800,293
Vice President, Chief Financial Officer and Treasurer	2016	362,885	381,399	852,693	306,589		1,903,566


	2017 Base Salary	Current 2018 Base Salary
Name and Principal Position	($)	($)
Eric D. Long, President and Chief Executive Officer	625,931	644,709
William G. Manias, Vice President and Chief Operating Officer	424,361	437,092
Matthew C. Liuzzi, Vice President, Chief Financial Officer and Treasurer	375,960	387,239


	DCF as a	Percentage of
	Percentage of	DCF
Levels of	Budgeted DCF	Bonus that would
DCF Bonus	for 2017	be Paid

Threshold	80%	50%
Target	100%	100%
Maximum	110%	200%


	Unit Awards
					Equity Incentive Plan Awards
	Number of	Number of		Market	Number of Unearned		Market Value Of
	Class B Units	Outstanding		Value of	Units That Have		Unearned Units That
	That Have Vested but	Phantom Units		Outstanding	Not Vested		Have Not Vested
	Are Still Outstanding	(Time-Based)		Phantom Units	(Performance-Based)		(Performance-Based)
Name	(#)(1)	(#)		($) (5)	(#)		($) (5)
Eric D. Long	481,250
2015 Grant		25,176	(2)	416,411
2016 Grant		134,484	(3)	2,224,365	100,862	(6)	1,668,257
2017 Grant		81,598	(4)	1,349,631	40,800	(7)	674,832
William G. Manias	125,000
2015 Grant		12,168	(2)	201,259
2016 Grant		75,979	(3)	1,256,693	56,984	(6)	942,515
2017 Grant		41,490	(4)	686,245	20,746	(7)	343,139
Matthew C. Liuzzi	62,500
2015 Grant		9,843	(2)	162,803
2016 Grant		60,580	(3)	1,001,993	45,436	(6)	751,511
2017 Grant		32,673	(4)	540,411	16,336	(7)	270,197


	Fees Earned or				All Other
	Paid in Cash		Unit Awards		Compensation	Total
Name	($)		($) (1)		($) (2)	($)
John D. Chandler	85,500		—	(3)	23,861	109,361
Robert F. End	136,000		75,000		23,861	234,861
Forrest E. Wylie	117,000	(4)	75,000		47,725	239,725
Jerry L. Peters	46,500		—		—	46,500


		Percentage of
	Common Units	Common Units
Name of Beneficial Owner	Beneficially Owned	Beneficially Owned
USA Compression Holdings (1)	25,092,196	40.3	%
Argonaut (2)	7,715,948	12.4	%
Oppenheimer Funds, Inc. (3)	6,529,518	10.5	%
Eric D. Long (4)	359,579	*
William G. Manias (5)	161,620	*
Matthew C. Liuzzi (6)	111,764	*
Jerry L. Peters	—	—
Jim H. Derryberry	—	—
William H. Shea, Jr.	—	—
Robert F. End (7)	33,717	*
Olivia C. Wassenaar	—	—
Forrest E. Wylie (8)	54,116	*
All directors and executive officers
as a group (12 persons) (9)	856,973	1.4	%


			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	1,086,858	N/A	—	(1)

~~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†~~	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)

~~10.7†~~ 10.4†		~~Employment Agreement, dated December 23, 2010, between~~First Amendment to the 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)~~

~~10.8†~~	~~Employment Agreement, dated April 17,~~LP 2013 ~~between USA Compression Management Services, LLC and Matthew C. Liuzzi~~Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Partnership’s ~~Current~~Quarterly Report on Form ~~8-K~~10-Q (File No. 001-35779) filed on ~~January 15, 2015)~~November 6, 2018)

~~10.9†~~ 10.5†		Employment Agreement, dated July ~~15, 2013,~~1, 2016, between USA Compression Management Services, LLC and ~~William G. Manias~~Sean T. Kimble (incorporated by reference to Exhibit ~~10.7~~10.13 to the Partnership’s Annual Report on Form 10-K for the year ended December 31, ~~2015~~201 8 (File No. 001-35779) filed on February ~~11, 2016)~~ 19 , 2019)

~~10.10~~ 10.6†*		Employment Agreement, dated December 14, 2016, between USA Compression Management Services, LLC and Christopher W. Porter

10.7		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)

~~10.11~~ 10.8		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)

~~10.12†~~ 10.9†		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)

~~10.13†~~ 10.10†		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)

~~10.14†~~ 10.11†		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)

~~10.15†~~ 10.12†		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)


10.13†						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)
~~10.16†~~
10.14†						USA Compression Partners, LP Amended and Restated Annual Cash Incentive Plan (incorporated by reference to Exhibit 10.21 to the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2019 (File No. 001-35779) filed on February 2, 2019)

10.15†						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)

~~10.17~~ 10.16†						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)

10.17†						USA Compression Partners, LP 201 3 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)

10.18						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)

10.19†						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)

10.20						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)

21.1*						List of subsidiaries of USA Compression Partners, LP

23.1* 22.1*						List of Subsidiary Guarantors and Co-Issuer

23.1*						Consent of ~~KPMG~~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

101.INS* 101*						~~XBRL Instance Document~~ Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of December 31, 2020 and 2019; (ii) our Consolidated Statements of Operations for the years ended December 31, 2020, 2019 and 2018; (iii) our Consolidated Statement of Partners’ Capital and Predecessor Parent Company Net Investment for the years ended December 31, 2020, 2019 and 2018; (iv) our Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018; and (v) the notes to our Consolidated Financial Statements.

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*



104						Cover Page Interactive Data File (embedded within the Inline XBRL ~~Presentation Linkbase Document~~ document)


					USA COMPRESSION PARTNERS, LP


	By:			USA Compression GP, LLC,
						its General Partner

Date:			February 16, 2021
By:	~~By:~~			/s/ Eric D. Long
						Eric D. Long
						President and Chief Executive Officer
						(Principal Executive Officer)

	~~Date:~~	~~February 12, 2018~~


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/ ~~Jerry L. Peters~~ Christopher R. Curia		Director
~~Jerry L. Peters~~ Christopher R. Curia			~~Director~~

/s/ ~~Jim H. Derryberry~~ Glenn E. Joyce		Director
~~Jim H. Derryberry~~ Glenn E. Joyce			~~Director~~

/s/ ~~Robert F. End~~ Thomas E. Long		Director
~~Robert F. End~~ Thomas E. Long			~~Director~~

/s/ Thomas P. Mason		Director
Thomas P. Mason

/s/ Matthew S. Ramsey		Director
Matthew S. Ramsey

/s/ William ~~H. Shea, Jr.~~ S. Waldheim		Director
William ~~H. Shea, Jr.~~ S. Waldheim			~~Director~~

/s/ ~~Olivia C. Wassenaar~~ Bradford D. Whitehurst		Director
~~Olivia C. Wassenaar~~ Bradford D. Whitehurst			~~Director~~

~~/s/ Forrest E. Wylie~~
~~Forrest E. Wylie~~	~~Director~~

~~/s/ Michael A. Wichterich~~
~~Michael A. Wichterich~~	~~Director~~


Report of Independent Registered Public Accounting Firm			~~F-2~~ F-2

Consolidated Balance Sheets as of December 31, ~~2017~~2020 and ~~2016~~2019			~~F-3~~ F-4

Consolidated Statements of Operations for the years ended December 31, ~~2017, 2016~~2020, 2019 and ~~2015~~2018			~~F-4~~ F-5

Consolidated Statements of Changes in Partners’ Capital and Predecessor Parent Company Net Investment for the years ended December 31, ~~2017, 2016~~2020, 2019 and ~~2015~~2018			~~F-5~~ F-6

Consolidated Statements of Cash Flows for the years ended December 31, ~~2017, 2016~~2020, 2019 and ~~2015~~2018			~~F-6~~ F-7

Notes to Consolidated Financial Statements			~~F-7~~ F-8

Supplemental Selected Quarterly Financial Data			~~S-1~~ F-36


	Partners’ Capital								Total
	Common Units			Subordinated Units			General Partner Interest		Partners’
	Units	Amount		Units	Amount		Amount		Capital
Partners’ capital, December 31, 2014	31,307	$	600,401	14,049	$	225,221	$	13,898	$	839,520
Vesting of phantom units	101		1,844	—		—		—		1,844
Distributions and DERs	—		(69,480)	—		(29,151)		(2,503)		(101,134)
Issuance of common units under the DRIP	3,113		56,895	—		—		—		56,895
Issuance of common units	4,035		75,111	—		—		—		75,111
Unit-based compensation of equity classified awards	—		325	—		—		—		325
Net loss	—		(107,513)	—		(45,283)		(1,477)		(154,273)
Partners’ capital, December 31, 2015	38,556	$	557,583	14,049	$	150,787	$	9,918	$	718,288
Vesting of phantom units	201		1,619	—		—		—		1,619
Distributions and DERs	—		(106,570)	—		(7,376)		(2,845)		(116,791)
Issuance of common units under the DRIP	2,708		31,812	—		—		—		31,812
Issuance of common units	5,175		80,892	—		—		—		80,892
Unit-based compensation of equity classified awards	—		762	—		—		—		762
Net income (loss)	—		14,282	—		(2,711)		1,364		12,935
Conversion of subordinated units to common units	14,049		140,700	(14,049)		(140,700)		—		—
Partners’ capital, December 31, 2016	60,689	$	721,080	—	$	—	$	8,437	$	729,517
Vesting of phantom units	272		4,267	—		—		—		4,267
Distributions and DERs	—		(128,930)	—		—		(2,999)		(131,929)
Issuance of common units under the DRIP	1,233		20,324	—		—		—		20,324
Unit-based compensation of equity classified awards	—		234	—		—		—		234
Net income	—		9,947	—		—		1,493		11,440
Partners’ capital, December 31, 2017	62,194	$	626,922	—	$	—	$	6,931	$	633,853


	Limited Partners
	Common Units		Class B Units		Warrants		Predecessor Parent Company Net Investment		Total
Ending balance, December 31, 2017	$	0	$	0	$	0	$	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	5,242		—		—		—		5,242
Distributions and DERs, $1.575 per unit	(141,694)		—		—		—		(141,694)
Issuance of common units under the DRIP	645		—		—		—		645
Unit-based compensation for equity classified awards	41		—		—		—		41
Net loss attributable to common and Class B unitholders’ interests 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		0		1,378,856
Vesting of phantom units	2,926		—		—		—		2,926
Distributions and DERs, $2.10 per unit	(192,723)		—		—		—		(192,723)
Issuance of common units under the DRIP	997		—		—		—		997
Unit-based compensation for equity classified awards	160		—		—		—		160
Net loss attributable to common and Class B unitholders’ interests	(1,774)		(7,844)		—		—		(9,618)
Conversion of Class B Units to common units	67,302		(67,302)		—		—		—
Partners' capital ending balance, December 31, 2019	1,166,619		0		13,979		0		1,180,598
Vesting of phantom units	1,748		—		—		—		1,748
Distributions and DERs, $2.10 per unit	(203,325)		—		—		—		(203,325)
Issuance of common units under the DRIP	1,901		—		—		—		1,901
Unit-based compensation for equity classified awards	215		—		—		—		215
Net loss attributable to common unitholders’ interests	(643,482)		0		—		—		(643,482)
Partners' capital ending balance, December 31, 2020	$	323,676	$	0	$	13,979	$	0	$	337,655


~~Compression equipment, acquired new~~		~~25 years~~
~~Compression equipment, acquired used~~		~~9 - 25 years~~
~~Furniture and fixtures~~		~~7 years~~
~~Vehicles and computer equipment~~		~~3 - 7 years~~
~~Leasehold improvements~~		~~5 years~~


	Customer
	Relationships		Trade Names		Non-compete		Total
Gross Balance at December 31, 2015	$	78,700	$	15,600	$	900	$	95,200
Accumulated amortization		(15,517)		(3,744)		(750)		(20,011)
Net Balance at December 31, 2016	$	63,183	$	11,856	$	150	$	75,189

Gross Balance at December 31, 2016	$	78,700	$	15,600	$	900	$	95,200
Accumulated amortization		(18,252)		(4,368)		(900)		(23,520)
Net Balance at December 31, 2017	$	60,448	$	11,232	$	—	$	71,680


Year Ending December 31,	Total
2018	$	3,359
2019		3,359
2020		3,359
2021		3,359
2022		3,359


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)


Total revenues	$	662,091
Net loss	(44,894)
Net loss attributable to common and Class B unitholders’ interests	(93,644)
Basic and diluted net loss per common unit and Class B Unit	(0.98)


	Allowance for Credit Losses (1)
Balance, December 31, 2018	$	1,705
Current-period provision for expected credit losses	1,050
Writeoffs charged against the allowance	(276)

Balance, December 31, 2019	2,479
Current-period provision for expected credit losses	3,700
Writeoffs charged against the allowance	(1,197)
Balance, December 31, 2020	$	4,982


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


	Customer Relationships		Trade Names		Total
Gross balance at December 31, 2018	$	485,162	$	65,500	$	550,662

Accumulated amortization	(156,105)		(31,386)		(187,491)
Net balance at December 31, 2019	$	329,057	$	34,114	$	363,171

Gross balance at December 31, 2019	$	485,162	$	65,500	$	550,662
Accumulated amortization	(182,210)		(34,661)		(216,871)
Net balance at December 31, 2020	$	302,952	$	30,839	$	333,791