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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from              to
Commission file number: 001-35779
USA Compression Partners, LP
(Exact Name of Registrant as Specified in its Charter)
Delaware
75-2771546
(State or Other Jurisdiction of Incorporation or Organization)(I.R.S. Employer Identification No.)
111 Congress Avenue, Suite 2400
Austin, Texas 78701
(Address of principal executive offices) (zip code)
(512) 473-2662
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading symbol(s)Name of each exchange on which registered
Common Units Representing Limited Partner InterestsUSACNew York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes     No 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes     No 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes     No 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes     No 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” or an “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Accelerated filer
Non-accelerated filerSmaller reporting company
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report.  
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  No
The aggregate market value of common units held by non-affiliates of the registrant as of June 30, 2020, the last business day of the registrant’s most recently completed second fiscal quarter was $542.2 million. This calculation does not reflect a determination that such persons are affiliates for any other purpose.
As of February 11, 2021, there were 96,996,304 common units outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: NONE



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Glossary
The abbreviations, acronyms and industry terminology used in this Annual Report are defined as follows:
COVID-19novel coronavirus 2019
Credit AgreementSixth 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.
DERsdistribution equivalent rights
DRIPdistribution reinvestment plan
EBITDAearnings before interest, taxes, depreciation and amortization
EIAUnited States Energy Information Agency
Exchange ActSecurities Exchange Act of 1934, as amended
GAAPgenerally accepted accounting principles of the United States of America
LIBORLondon Interbank Offered Rate
Preferred UnitsSeries A Preferred Units representing limited partner interests in USA Compression Partners, LP
SECUnited 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

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PART I
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This report contains “forward-looking statements.” All statements other than statements of historical fact contained in this report are forward-looking statements, including, without limitation, statements regarding our plans, strategies, prospects and expectations concerning our business, results of operations and financial condition. You can identify many of these statements by looking for words such as “believe,” “expect,” “intend,” “project,” “anticipate,” “estimate,” “continue,” “if,” “outlook,” “will,” “could,” “should,” or similar words or the negatives thereof.
Known material factors that could cause our actual results to differ from those in these forward-looking statements are described below, in Part I, Item 1A “Risk Factors” and in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations”. Important factors that could cause our actual results to differ materially from the expectations reflected in these forward-looking statements include, among other things:
changes in the long-term supply of and demand for crude oil and natural gas, including as a result of uncertainty regarding the length of time it will take for the U.S. and the rest of the world to slow the spread of COVID-19 to the point where applicable authorities are comfortable continuing to ease, or declining to reinstate certain restrictions on various commercial and economic activities; such restrictions are designed to protect public health but also have the effect of reducing demand for crude oil and natural gas;
the severity and duration of world health events, including the recent COVID-19 outbreak, related economic repercussions, actions taken by governmental authorities and other third parties in response to the pandemic and the resulting disruption in the oil and gas industry and negative impact on demand for oil and gas, which continues to negatively impact our business;
changes in general economic conditions and changes in economic conditions of the crude oil and natural gas industries specifically, including the ability of members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC and other allied producing countries, “OPEC+”) to agree on and comply with supply limitations;
uncertainty regarding the timing, pace and extent of an economic recovery in the U.S. and elsewhere, which in turn will likely affect demand for crude oil and natural gas and therefore the demand for the compression and treating services we provide and the commercial opportunities available to us;
the deterioration of the financial condition of our customers, which may result in the initiation of bankruptcy proceedings with respect to customers;
renegotiation of material terms of customer contracts;
competitive conditions in our industry;
our ability to realize the anticipated benefits of acquisitions;
actions taken by our customers, competitors and third-party operators;
changes in the availability and cost of capital;
operating hazards, natural disasters, epidemics, pandemics (such as COVID-19), weather-related delays, casualty losses and other matters beyond our control;
operational challenges relating to the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance of contracts and supply chain disruptions;
the restrictions on our business that are imposed under our long-term debt agreements;
information technology risks including the risk from cyberattack;
the effects of existing and future laws and governmental regulations; and
the effects of future litigation.
Many of the foregoing risks and uncertainties are, and will be, exacerbated by the COVID-19 pandemic and any consequent worsening of the global business and economic environment. New factors emerge from time to time, and it is not possible for us to predict all such factors. Should one or more of the risks or uncertainties described in this Annual Report
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occur, or should underlying assumptions prove incorrect, actual results and plans could differ materially from those expressed in any forward-looking statements.
All forward-looking statements included in this report are based on information available to us on the date of this report and speak only as of the date of this report. Except as required by law, we undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the foregoing cautionary statements.
ITEM 1.    Business
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 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,” “we,” “us” and “its” refer to USA Compression Partners, LP, together with its consolidated subsidiaries, including the USA Compression Predecessor, when used in periods subsequent to the Transactions Date, unless the context otherwise requires or where otherwise indicated.
Overview
We believe that we are one of the largest independent providers of natural gas compression services in the 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, 2020, we had 3,726,181 horsepower in our 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. Demand for our services is driven by the domestic production of natural gas and crude oil. As such, we have focused our activities in areas of attractive natural gas and crude oil production growth, which are generally found in these shale and unconventional resource plays. According to studies promulgated by the EIA, the production and transportation volumes in these shale plays are expected to increase over the long 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 to meet these changing operating conditions due to the operational design flexibility inherit 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, in order to reduce the hydrostatic pressure and allow the oil to flow at a higher rate, and other artificial lift technologies are critical to the enhancement of oil production from horizontal wells operating in tight shale plays.
We operate a modern fleet of compression units, with an average age of approximately 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 and maintain high overall utilization rates for our fleet.
As part of our services, we engineer, design, operate, service and repair our compression units and maintain related support inventory and equipment. The compression units in our modern fleet are designed to be easily adaptable to fit our customers’ changing compression requirements. Focusing on the needs of our customers and providing them with reliable and flexible compression services in geographic areas of attractive growth helps us to generate stable cash flows for our unitholders.
We provide compression services to our customers under fixed-fee contracts with initial contract terms typically between six months and five years, depending on the application and location of the compression unit. We typically continue to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis. We primarily enter into 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 maximize the throughput of product, reduce fuel costs and minimize emissions. While we significantly expanded our geographic footprint with the CDM Acquisition, our customers may have compression demands in areas of the U.S. in conjunction with their field development projects where we are not currently operating. We continually consider further expansion of our geographic areas of operation in the U.S. based upon the level of customer demand. Our modern, flexible fleet of compression units, which have been designed to be rapidly deployed and redeployed throughout the country, provides us with opportunities to expand into other areas with both new and existing customers. 
We also own and operate a fleet of equipment used to provide natural gas treating services, such as carbon dioxide and hydrogen sulfide removal, natural gas cooling and dehydration, to natural gas producers and midstream companies.
Our assets and operations are organized into a single reportable segment and are all located and conducted in the U.S. See our consolidated financial statements, and the notes thereto, in 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
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%.
COVID-19
Beginning in the first quarter of 2020, the COVID-19 pandemic prompted several states and municipalities in which we operate to 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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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.
Our Compression Fleet
The fleet of compression units that we own and use to provide compression services consists of specially engineered compression units that utilize standardized components, principally engines manufactured by Caterpillar, Inc. and compressor frames and cylinders manufactured by Ariel Corporation. Our units can be rapidly and cost effectively modified for specific customer applications. As of December 31, 2020, the average age of our compression units was approximately 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 5,000 horsepower per unit. These larger horsepower units, which we define as 400 horsepower per unit or greater, represented 86.3% of our total fleet horsepower as of December 31, 2020. The remainder of our fleet consists of smaller horsepower units ranging from 40 horsepower to 399 horsepower that are primarily used in gas lift applications. We believe the 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, 2020:
Unit HorsepowerFleet
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 %
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The following table sets forth certain information regarding our compression fleet as of the dates and for the periods indicated and excludes certain natural gas treating assets for which horsepower is not a relevant metric:
Year Ended December 31,Percent
Operating Data:20202019Change
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)%
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(1)Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order).
(2)Total available horsepower is revenue generating horsepower under contract for which we are billing a customer, horsepower in our fleet that is under contract but is not yet generating revenue, horsepower not yet in our fleet that is under contract but not yet generating revenue and that is subject to a purchase order, and idle horsepower. Total available horsepower excludes new horsepower on order for which we do not have an executed compression services contract.
(3)Revenue generating horsepower is horsepower under contract for which we are billing a customer.
(4)Calculated as the average of the month-end revenue generating horsepower for each of the months in the period.
(5)Calculated as the average of the month-end revenue generating horsepower per revenue generating compression unit for each of the months in the period.
(6)Horsepower utilization is calculated as (i) the sum of (a) revenue generating horsepower, (b) horsepower in our fleet that is under contract, but is not yet generating revenue and (c) horsepower not yet in our fleet that is under contract, not yet generating revenue and that is subject to a purchase order, divided by (ii) total available horsepower less idle horsepower that is under repair. Horsepower utilization based on revenue generating horsepower and fleet horsepower was 80.4% and 89.9% at December 31, 2020 and 2019, 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 84.5% and 89.8% for the years ended December 31, 2020 and 2019, respectively.
Many of our compression units contain devices that enable us to monitor the units remotely through cellular and satellite 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 2021 where beneficial from an operational and financial standpoint. All of our compression units are designed to automatically shut down if operating conditions deviate from a pre-determined range. While we retain the care, custody, ongoing maintenance and control of our compression units, we allow our customers, subject to a defined protocol, to start, stop, accelerate and slow down compression units in response to field conditions.
We adhere to routine, preventive and scheduled maintenance cycles. Each of our compression units is subjected to rigorous sizing and diagnostic analyses, including lubricating oil analysis and engine exhaust emission analysis. We have proprietary field service automation capabilities that allow our service technicians to electronically record and track operating, technical, environmental and commercial information at the discrete unit level. These capabilities allow our field technicians to identify potential problems and often act on them before such problems result in down-time.
Generally, we expect each of our compression units to undergo a major overhaul between service deployment cycles. The timing of these major overhauls depends on multiple factors, including run time and operating conditions. A major overhaul involves the periodic rebuilding of the unit to materially extend its economic useful life or to enhance the unit’s ability to fulfill broader or more diversified compression applications. Because our compression fleet is comprised of units of varying horsepower that have been placed into service with staggered initial on-line dates, we are able to schedule overhauls in a way that avoids excessive annual maintenance capital expenditures and minimizes the revenue impact of down-time.
We believe that our customers, by outsourcing their compression requirements, can achieve higher compression run-times, which translates into increased volumes of either natural gas or crude oil production and, therefore, increased revenues.
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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 requirements.
Marketing and Sales
Our marketing and client service functions are performed on a coordinated basis by our sales team and field technicians. Salespeople, applications engineers and field technicians qualify, analyze and scope new compression applications as well as regularly visit our customers to ensure customer satisfaction, determine a customer’s needs related to existing services being provided and determine the customer’s future compression service requirements. This ongoing communication allows us to quickly identify and respond to our customers’ compression requirements.
Customers
Our customers consist of more than 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 35%, 33% and 33% of our revenue for the years ended December 31, 2020, 2019 and 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 Corporation, GE Oil & Gas Gemini products and Arrow Engine Company for compressor frames and cylinders. We also rely primarily on four vendors, A G Equipment Company, Alegacy Equipment, LLC, Standard Equipment Corp. and Genis Holdings LLC, to package and assemble our compression units. Although we rely primarily on these suppliers, we believe alternative sources for natural gas compression equipment are generally available if needed. However, relying on alternative sources may increase our costs and change the standardized nature of our fleet. We have not experienced any material supply problems to date. Although lead-times for new Caterpillar engines and new Ariel compressor frames have in the past been in excess of one year due to increased demand and supply allocations imposed on equipment packagers and end-users, as of December 31, 2020, lead-times for such engines and frames are approximately six months. Please read Part I, Item 1A “Risk Factors – Risks Related to Our Business – We depend on a limited number of suppliers and are vulnerable to product shortages and price increases, which could have a negative impact on our results of operations”.
Competition
The compression services business is highly competitive. Some of our competitors have a broader geographic scope and greater financial and other resources than we do. On a regional basis, we experience competition from numerous smaller companies that may be able to more quickly adapt to changes within our industry and changes in economic conditions as a whole, more readily take advantage of available opportunities and adopt more aggressive pricing policies. Additionally, the historical availability of attractive financing terms from financial institutions and equipment manufacturers has made the purchase of individual compression units affordable to our customers. We believe that we compete effectively on the basis of price, equipment availability, customer service, flexibility in meeting customer needs, quality and reliability of our compressors and related services. Please read Part I, Item 1A “Risk Factors – Risks Related to Our Business – We face significant competition that may cause us to lose market share and reduce our cash available for distribution”.
Seasonality
Our results of operations have not historically been materially affected by seasonality, and we do not currently have reason to believe that seasonal fluctuations will have a material impact in the foreseeable future.
Insurance
We believe that our insurance coverage is customary for the industry and adequate for our business. As is customary in the energy services industry, we review our safety equipment and procedures and carry insurance against most, but not all, risks of our business. Losses and liabilities not covered by insurance would increase our costs. The compression business can be hazardous, involving unforeseen circumstances such as uncontrollable flows of gas or well fluids, fires and explosions or environmental damage. To address the hazards inherent in our business, we maintain insurance coverage that, subject to significant deductibles, includes physical damage coverage, third party general liability insurance, employer’s liability, environmental and pollution and other coverage, although coverage for environmental and pollution related losses is subject to significant limitations. Under the terms of our standard compression services contract, we are responsible for maintaining insurance coverage on our compression equipment. Please read Part I, Item 1A “Risk Factors – General Risk 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 operations and limit our growth and revenue. Moreover, failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of remedial obligations and the issuance of injunctions delaying or prohibiting operations. Private parties may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. While we believe that our operations are in substantial compliance with applicable environmental laws and regulations and that continued compliance with current requirements would not have a material adverse effect on us, we cannot predict whether our cost of compliance will materially increase in the future. Any changes in, or more stringent enforcement of, existing environmental laws and regulations, or passage of additional environmental laws and regulations that result in more stringent and costly pollution control equipment, waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations and financial position.
We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations or cash flows. We cannot assure you, however, that future events such as changes in existing laws or enforcement policies, the promulgation of new laws or regulations, or the development or discovery of new facts or conditions or unforeseen incidents will not cause us to incur significant costs. The following is a discussion of material environmental and safety laws that relate to our operations. We believe that we are in substantial compliance with all of these environmental laws and regulations. Please read Part I, Item 1A “Risk Factors – Risks Related to 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 various state or federal regulatory agencies. Our standard natural gas compression contract provides that the customer is responsible for obtaining air emissions permits and assuming the environmental risks related to site operations. In some instances, our customers may be required to aggregate emissions from a number of different sources on the theory that the different sources should be considered a single source. Any such determinations could have the effect of making projects more costly than our customers expected and could require the installation of more costly emissions controls, which may lead some of our customers not to pursue certain projects.
Increased obligations of operators to reduce air emissions of nitrogen oxides and other pollutants from internal combustion engines in transmission service have been enacted by governmental authorities. For example, in 2010, the U.S. Environmental Protection Agency (“EPA”) published new regulations under the CAA to control emissions of hazardous air pollutants from existing stationary reciprocal internal combustion engines, also known as Quad Z regulations. The rule requires us to undertake certain expenditures and activities, including purchasing and installing emissions control equipment on certain compressor engines and generators.
In recent years, the EPA has lowered the National Ambient Air Quality Standards (“NAAQS”) for several air pollutants. For example, in 2015, the EPA finalized a rule strengthening the primary and secondary standards for ground level ozone, both of which are 8-hour concentration standards of 70 parts per billion. 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 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 emissions controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package included New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emissions standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules established specific new requirements regarding emissions from compressors and controllers at natural gas processing plants, dehydrators, storage tanks
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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 required certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce methane gas and VOC emissions. These Subpart OOOOa standards would 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 issued a final rule that removed the transmission and storage segment from the 2016 New Source Performance Standards, rescinded VOCs and 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 to consider publishing for notice and comment a proposed rule suspending, revising, or rescinding the September 2020 rule, which could result in 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 emissions control equipment would not have a material adverse impact on our business, financial condition, results of operations and cash available for distribution.
Climate change. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas, are examples of greenhouse gases (“GHGs”). In recent years, the U.S. Congress has considered legislation to reduce GHG emissions. 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 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 review and reconsideration of federal oil and gas permitting and leasing practices. Other energy legislation and initiatives 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 have imposed new or more stringent permitting, disclosure or well construction requirements on oil and gas activities. Further, although Congress has not passed such legislation, almost half of the states have begun to address GHG emissions, primarily through the planned development of emissions inventories or regional GHG cap and trade programs. Depending on the particular program, we could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations.
Independent of Congress, the EPA undertook to adopt regulations controlling GHG emissions under its existing CAA authority. For example, in 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs endanger human health and the environment, allowing the agency to proceed with the adoption of regulations that restrict emissions of GHG under existing provisions of the CAA. In 2009 and 2010, the EPA adopted rules regarding regulation of GHG emissions from motor vehicles and requiring the reporting of GHG emissions in the U.S. from specified large GHG emissions sources, including petroleum and natural gas facilities such as natural gas transmission compression facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year.
In addition, from time to time, there have been various proposals to regulate hydraulic fracturing at the federal level. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the rock formation to stimulate gas production. 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 review
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and reconsideration of federal oil and gas permitting and leasing practices, effectively limiting hydraulic fracturing on federal lands and waters. Any limitations or bans on hydraulic fracturing at the federal level could increase the costs of operations for our customers who operate on 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. The Paris Agreement went into effect on November 4, 2016. While the U.S. withdrew from the Paris Agreement on November 4, 2020, President Biden issued an executive order on January 20, 2021 recommitting the United States to the Paris 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 GHG legislation, regulation, agreements or initiatives will impact our business, any legislation or regulation of GHG emissions that may be imposed in areas in which we conduct business or on the assets we operate, 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 Earth’s atmosphere may produce climate changes that have significant weather-related effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any of those effects were to occur, they could have an adverse effect on our assets and operations.
Water discharge. The Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the 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 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 property by filling wetlands. 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. Lawsuits have been filed challenging the rule, and on January 20, 2021, President Biden issued an executive order directing the heads of all agencies to immediately review all
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regulatory actions taken between January 20, 2017 and January 20, 2021, including the April 2020 rule. Should the April 2020 rule be rescinded or a different rule promulgated that expands the jurisdictional reach of the CWA, our customers could face increased costs and delays due to additional permitting and regulatory requirements and possible challenges to permitting decisions.
Safe Drinking Water Act. A significant portion of our customers’ natural gas production is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Legislation to amend the Safe Drinking Water Act (“SDWA”) to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed from time to time and the U.S. Congress continues to consider legislation to amend the SDWA. Several states have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing, including prohibitions on the practice. We cannot predict the future of such legislation and what additional, if any, provisions would be included. If additional levels of regulation, restrictions and permits were required through the adoption of new laws and regulations at the federal or state level or if the agencies that issue the permits develop new interpretations of those requirements, that could lead to delays, increased operating costs and process prohibitions that could reduce demand for our compression services, which could materially adversely affect our revenue and results of operations.
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 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, 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 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.
Human Capital Management
USA Compression Management Services, LLC (“USAC Management”), a wholly owned subsidiary of the General Partner, performs certain management and other administrative services for us, such as accounting, corporate development, finance and legal. All of our employees, including our executive officers, are employees of USAC Management. As of December 31, 2020, USAC Management had 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” 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 Exchange Act, as soon as reasonably practicable after such reports are electronically filed with, or furnished to, the SEC. The information contained on our website does not constitute part of this report.
The SEC maintains a website that contains these reports at sec.gov.
ITEM 1A.    Risk Factors
As described in Part I “Disclosure Regarding Forward-Looking Statements”, this report contains forward-looking statements regarding us, our business and our industry. The risk factors described below, among others, could cause our actual results to differ materially from the expectations reflected in the forward-looking statements. If any of the following risks were to materialize, our business, financial condition or results of operations could be materially and adversely affected. In that case, we might not be able to continue to pay our current quarterly distribution on our common units or increase the level of such distributions in the future, and the trading price of our common units could decline.
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 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.
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 the overall demand for energy. Any 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 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 had decreased to 404 rigs on May 20, 2016, and at that time, Henry Hub natural gas spot prices were $1.81 per MMBtu and WTI crude oil spot prices were $47.67 per barrel. This slowdown in new drilling activity caused some pressure on service rates for new and existing services and contributed to a decline in our utilization during 2015 and into 2016.
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 2020, the North American rig count was 351 rigs, the price of WTI crude oil was $48.35 per barrel and Henry Hub natural gas spot prices were $2.36 per MMBtu. The current decline in commodity prices and crude oil and natural gas production has resulted in a decline in the demand for our 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 governmental regulation, limitations on exploration and production activity or 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 periods of low crude oil prices, we typically experience pressure on service rates from our customers in gas lift applications, and we have started to experience such effects.
Additionally, unconventional sources, such as shales, tight sands and 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 become uneconomic to drill and produce, which 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.
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 35%, 33% and 33% of our revenue for the years ended December 31, 2020, 2019 and 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 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.
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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 COVID-19 pandemic, has had and could reduce the liquidity of our customers, suppliers or vendors, making it more difficult for them to meet their obligations to us. We are therefore subject to heightened risks of loss resulting from nonpayment or nonperformance by our 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 of our customers was to enter into bankruptcy, we could lose all or a portion of the amounts owed to us by such customer, and we may be forced to cancel all or a portion of our service contracts with such customer at significant expense to us. 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 and greater financial and other resources than we do. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenue and cash flows could be adversely affected by the activities of our competitors and our customers. If our competitors substantially increase the resources they devote to the development and marketing of competitive services or substantially decrease the prices at which they offer their services, we may be unable to compete effectively. Some of these competitors may expand or construct newer, more powerful or more flexible compression fleets, which would create additional competition for us. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and cash available for distribution.
Our customers may choose to vertically integrate their operations by purchasing and operating their own compression fleet, increasing the number of compression units they currently own or using alternative technologies for enhancing crude oil production.
Our customers that are significant producers, processors, gatherers and transporters of natural gas and crude oil may choose to vertically integrate their operations by purchasing and operating their own compression fleets in lieu of using our compression services. The historical availability of attractive financing terms from financial institutions and equipment manufacturers facilitates this possibility by making the purchase of individual compression units increasingly affordable to our customers. In addition, there are many technologies available for the artificial enhancement of crude oil production, and our customers may elect to use these alternative technologies instead of the gas lift compression services we provide. Such vertical integration, increases in vertical integration or use of alternative technologies could result in decreased demand for our compression services, which may have a material adverse effect on our business, results of operations, financial condition and reduce our cash available for distribution.
A significant portion of our services are provided to customers on a month-to-month basis, and we cannot be sure that such customers will continue to utilize our services.
Our contracts typically have an initial term of between six months and five years, depending on the application and location of the compression unit. After the expiration of the initial term, the contract continues on a month-to-month or longer basis until terminated by us or our customers upon notice as provided for in the applicable contract. For the year ended December 31, 2020, approximately 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. These customers can generally terminate their month-to-month compression services contracts on 30 days’ written notice. If a significant number of these customers were to terminate their month-to-month services, or attempt to renegotiate their month-to-month contracts at substantially lower rates, it could have a material adverse effect on our business, results of operations, financial condition and cash available for distribution.
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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 maintain or increase our per common unit distribution by expanding our business over time. Our future growth will depend upon a number of factors, some of which we cannot control. These factors include our ability to:
develop new business and enter into service contracts with new customers;
retain our existing customers and maintain or expand the services we provide them;
maintain or increase the fees we charge, and the margins we realize, from our compression services;
recruit and train qualified personnel and retain valued employees;
expand our geographic presence;
effectively manage our costs and expenses, including costs and expenses related to growth;
consummate accretive acquisitions;
obtain required debt or equity financing on favorable terms for our existing and new operations; and
meet customer specific contract requirements or pre-qualifications.
If we do not achieve our expected growth, we may not be able to maintain or increase the level of distributions on our common units, in which event the market price of our common units will likely decline.
We may be unable to grow successfully through acquisitions, which may negatively impact our operations and limit our ability to maintain or increase the level of distributions on our common units.
From time to time, we may choose to make business acquisitions, such as the CDM Acquisition, to pursue market opportunities, increase our existing capabilities and expand into new geographic areas of operations. While we have reviewed acquisition opportunities in the past and will continue to do so in the future, we may not be able to identify attractive acquisition opportunities or successfully acquire identified targets.
Any acquisitions we do complete may require us to issue a substantial amount of equity or incur a substantial amount of indebtedness. If we consummate any future material acquisitions, our capitalization may change significantly, 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 acquisitions 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. In addition, acquired assets may perform at levels below the forecasts used to evaluate their acquisition, due to factors beyond our control. If the acquired assets perform at levels below the forecasts, then our future results of operations could be negatively impacted.
Our ability to fund purchases of additional compression units and expansion capital expenditures in the future is dependent on our ability to access external capital.
The Partnership Agreement requires us to distribute all of our available cash to our unitholders (excluding prudent operating reserves). We expect that we will rely primarily upon cash generated by operating activities and, where necessary, borrowings under the Credit Agreement and the issuance of debt and equity securities, to fund expansion capital expenditures. However, we may not be able to obtain equity or debt financing on terms favorable to us or at all. To the extent we are unable to efficiently finance growth through external sources, our ability to maintain or increase the level of distributions on our common units could be significantly impaired. In addition, because we distribute all of our available cash, excluding prudent operating reserves, we may not grow as quickly as businesses that are able to reinvest their available cash to expand ongoing operations.
There are no limitations in the Partnership Agreement on our ability to issue additional equity securities, including securities ranking senior to the common units, subject to certain restrictions in the Partnership Agreement limiting our ability to issue units senior to or pari passu with the Preferred Units. To the extent we issue additional equity securities, including common units and preferred units, the payment of distributions on those additional securities may increase the risk that we will be unable to maintain or increase our per common unit distribution level. Similarly, our incurrence of borrowings or other debt to finance our growth strategy would increase our interest expense, which in turn would decrease our cash available for distribution.
Our debt level may limit our flexibility in obtaining additional financing, pursuing other business opportunities and paying distributions.
As of December 31, 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 $473.8 million, $1.1 billion of borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of $284.2 million.
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 and Senior Notes 2027 accrue interest at the rate of 6.875% per year.
Our ability to incur additional debt is also subject to limitations in 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;
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 ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. In addition, our ability to service our debt under the Credit Agreement could be impacted by market interest rates, as all of our outstanding borrowings under the Credit Agreement are subject to variable interest rates that fluctuate with changes in market interest rates. A substantial increase in the interest rates applicable to our outstanding borrowings could have a material negative impact on our cash available for distribution. If our operating results are not sufficient to service our current or future indebtedness, we could be forced to take actions such as reducing the level of distributions on our common units, curtailing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt or seeking additional equity capital. We may be unable to effect any of these actions on terms satisfactory to us or at all.
The terms of the Credit Agreement and the 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.
The Credit Agreement and the Indentures contain a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability to:
incur additional indebtedness;
pay dividends or make other distributions or repurchase or redeem equity interests;
prepay, redeem or repurchase certain debt;
issue certain preferred units or similar equity securities;
make investments;
sell assets;
incur liens;
enter into transactions with affiliates;
alter the businesses we conduct;
enter into agreements restricting our subsidiaries’ ability to pay dividends; and
consolidate, merge or sell all or substantially all of our assets.
In addition, the Credit Agreement contains certain operating and financial covenants and requires us to maintain specified financial ratios and satisfy other financial condition tests. Our ability to comply with those covenants and meet those financial ratios and tests can be affected by events beyond our control, including prevailing economic, financial and industry conditions. If market or other conditions deteriorate, our ability to comply with these covenants may be impaired.
A breach of the covenants or restrictions under the Credit Agreement or the Indentures could result in an event of default, in which case a significant portion of our indebtedness may become immediately due and payable and any other debt to which a cross-acceleration or cross-default provision applies may also be accelerated, our lenders’ commitment to make further loans to us may terminate, and we may be prohibited from making distributions to our unitholders. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. If we were unable to repay amounts due and payable under the Credit Agreement, those lenders could proceed against the collateral securing that indebtedness. We may not be able to replace
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the Credit Agreement, or if we are, any subsequent replacement of the Credit Agreement or any new indebtedness could be equally or more restrictive.
These restrictions may negatively affect our ability to grow in accordance with our strategy. In addition, our financial results, substantial indebtedness and credit ratings could adversely affect the availability and terms of our financing. Please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Revolving Credit Facility and – Senior Notes”.
The Preferred Units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of our common units.
The Preferred Units rank senior to 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 the Partnership Agreement related to the Preferred Units may limit our ability to make distributions to our common unitholders and our ability to capitalize on acquisition and other business opportunities.
The operating and financial restrictions and covenants in the Partnership Agreement related to the Preferred Units could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities. The Partnership Agreement restricts or limits our ability (subject to certain exceptions) to:
pay distributions on any junior securities, including our common units, prior to paying the quarterly distribution payable to the holders of the Preferred Units, including any previously accrued and unpaid distributions;
issue any securities that rank senior to or pari passu with the Preferred Units; however, we will be able to issue an unlimited number of securities ranking junior to the Preferred Units, including junior preferred units and additional common units; and
incur Indebtedness (as defined in the Credit Agreement) if, after giving pro forma effect to such incurrence, the Leverage Ratio (as defined in the Credit Agreement) determined as of the last day of the most recently ended fiscal quarter would exceed 6.5x, subject to certain exceptions.
A prolonged 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 have recorded $333.8 million of identifiable intangible assets, net, as of December 31, 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 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 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.
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Impairment in the carrying value of long-lived assets could reduce our earnings.
We have a significant number of long-lived assets on our consolidated balance sheet. Under GAAP, we are required to review our long-lived assets for impairment when events or circumstances indicate that the carrying value of such assets may not be recoverable or such assets will no longer be utilized in the operating fleet. The carrying value of a long-lived asset is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. If business conditions or other factors cause the expected undiscounted cash flows to decline, we may be required to record non-cash impairment charges. Events and conditions that could result in impairment in the value of our long-lived assets include changes in the industry in which we operate, competition, advances in technology, adverse changes in the regulatory environment, or other factors leading to a reduction in our expected long-term profitability. For example, for the years ended December 31, 2020, 2019 and 2018, we evaluated the future deployment of our idle fleet under current market conditions and determined to retire 37, 33 and 103 compressor units, respectively, for a total of approximately 15,000, 11,000 and 33,000 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, $5.9 million and $8.7 million for the years ended December 31, 2020, 2019 and 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 and the departure of any of our executive officers could have a significant negative effect on our business, operating results, financial condition and on our ability to compete effectively in the marketplace.
Additionally, our ability to hire, train and retain qualified personnel will continue to be important and could become more challenging as we grow and to the extent energy industry market conditions are competitive. When general industry conditions are favorable, the competition for experienced operational and field technicians increases as other energy and manufacturing companies’ needs for the same personnel increases. Our ability to grow or even to continue our current level of service to our current customers could be adversely impacted if we are unable to successfully hire, train and retain these important personnel.
We depend on a limited number of suppliers and are vulnerable to product shortages and price increases, which could have a negative impact on our results of operations.
The substantial majority of the components for our natural gas compression equipment are supplied by Caterpillar Inc., Cummins Inc. and Arrow Engine Company for engines, Air-X-Changers and Alfa Laval (US) for coolers, and Ariel Corporation, GE Oil & Gas Gemini products and Arrow Engine Company for compressor frames and cylinders.  Our reliance on these suppliers involves several risks, including price increases and a potential inability to obtain an adequate supply of required components in a timely manner. We also rely primarily on four vendors, A G Equipment Company, Alegacy Equipment, LLC, Standard Equipment Corp. and Genis Holdings LLC, to package and assemble our compression units. We do not have long-term contracts with these suppliers or packagers, and a partial or complete loss of any of these sources could have a negative impact on our results of operations and could damage our customer relationships. Some of these suppliers manufacture the components we purchase in a single facility, and any damage to that facility could lead to significant delays in delivery of completed compression units to us.
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, emissions controls and other environmental protection and occupational health and safety concerns, as discussed in detail in Item 1 “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 response costs. Remediation costs and other damages arising as a result of environmental laws and regulations, and costs associated with new information, changes in existing environmental laws and regulations or the adoption of new environmental laws and regulations could be substantial and could negatively impact our financial condition or results of operations. Moreover, failure to comply with these environmental laws and regulations may result in the imposition of administrative, civil and criminal penalties and the issuance of injunctions delaying or prohibiting operations.
We conduct operations in a wide variety of locations across the continental U.S. These operations require U.S. federal, state or local environmental permits or other authorizations. Our operations may require new or amended facility permits or licenses from time to time with respect to storm water discharges, waste handling or air emissions relating to equipment operations, which subject us to new or revised permitting conditions that may be onerous or costly to comply with. Additionally, the operation of compression units may require individual air permits or general authorizations to operate under various air regulatory programs established by rule or regulation. These permits and authorizations frequently contain numerous compliance requirements, including monitoring and reporting obligations and operational restrictions, such as emissions limits. Given the wide variety of locations in which we operate, and the numerous environmental permits and other authorizations that are applicable to our operations, we may occasionally identify or be notified of technical violations of certain requirements existing under various permits or other authorizations. We could be subject to penalties for any noncompliance in the future.
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 – 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. 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 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.
In 2012, the EPA finalized rules that establish new air emissions controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package included New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emissions standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The rules established specific new requirements regarding emissions from compressors and controllers at natural gas processing plants, dehydrators, storage tanks
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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 methane gas and VOC emissions. These Subpart OOOOa standards 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 issued a final rule that removed the transmission and storage segment from the 2016 New Source Performance Standards, rescinded VOCs and 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 to consider publishing for notice and comment a proposed rule suspending, revising, or rescinding the September 2020 rule, which could result in 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.
Climate change legislation, regulatory initiatives, and litigation could result in increased compliance 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 (“GHGs”). In recent years, the U.S. Congress has considered legislation to reduce GHG emissions. President Biden could seek to pursue legislative, regulatory or executive initiatives that restrict GHG emissions. Other energy legislation and initiatives 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 adopt regulations controlling GHG emissions under its existing CAA authority. Further, although Congress has not passed such legislation, many states have begun to address GHG emissions, primarily through the planned development of emissions inventories or regional GHG cap and trade programs. Depending on the particular program, we could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations.
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 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 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.
Although it is not currently possible to predict with specificity how any proposed or future GHG legislation, regulation, agreements or initiatives will impact our business, any legislation or regulation of GHG emissions that may be imposed in areas in which we conduct business or on the assets we operate, 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.
Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in Earth’s atmosphere may produce climate changes that have significant weather-related effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any of those effects were to occur, they could have an adverse effect on our assets and operations. Also, recent activism directed at shifting funding away from companies with energy-related assets could result in a reduction of funding for the energy sector overall, which could have an adverse effect on our ability to obtain external financing.
Increased regulation of hydraulic fracturing could result in reductions of, or delays in, natural gas production by our customers, which could adversely impact our revenue.
A significant portion of our customers’ natural gas production is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals
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under pressure into the rock formation to stimulate gas production. 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. In addition, members of the U.S. Congress are and a number of federal agencies historically have been requested to review, and under the Biden administration, may be requested to review again, a variety of environmental issues associated with hydraulic fracturing, which may lead to new or more strict regulation. Any new laws or regulations regarding hydraulic fracturing could negatively impact our customers’ ability to 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 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.
Risks Inherent in an Investment in Us
Holders of our common units have limited voting rights and are not entitled to elect the General Partner or its directors.
Unlike the holders of common stock in a corporation, our common unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Common unitholders have no right to elect the General Partner or the board of directors of the General Partner (the “Board”). ETO is the sole member of the General Partner and has the right to appoint the majority of the members of the Board, including all but one of its independent directors. Also, pursuant to that certain Board Representation Agreement entered into by us, the General Partner, 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 our common unitholders are dissatisfied with the General Partner’s performance, 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 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 decline because of the absence or reduction of a takeover premium in the trading price.
Furthermore, the Partnership Agreement contains provisions limiting the ability of common unitholders to call meetings or to obtain information about our operations, as well as other provisions limiting our common unitholders’ ability to influence the manner or direction of management.
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ETO owns and controls the General Partner, and the General Partner has sole responsibility for conducting our business and managing our operations. The General Partner and its affiliates, including ETO, have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of us and our unitholders.
ETO owns and controls the General Partner and appoints all of the officers and a majority of the directors of the General Partner, some of whom are also officers and directors of ETO. Although the General Partner has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of the General Partner also have a fiduciary duty to manage the General Partner in a manner that is beneficial to its owner. Conflicts of interest will arise between the General Partner and its owner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, the General Partner may favor its own interests and the interests of its owner over our interests and the interests of our unitholders. These conflicts include the following situations, among others:
neither the Partnership Agreement nor any other agreement requires ETO to pursue a business strategy that favors us;
ETO and its affiliates are not prohibited from engaging in businesses or activities that are in direct competition with us or from offering business opportunities or selling assets to our competitors;
the General Partner is allowed to take into account the interests of parties other than us, such as its owner, in resolving conflicts of interest;
the Partnership Agreement limits the liability of and reduces the fiduciary duties owed by the General Partner, and also restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty;
except in limited circumstances, the General Partner has the power and authority to conduct our business without unitholder approval;
the General Partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership interests and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders;
the General Partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders;
the General Partner determines which costs it incurs are reimbursable by us;
the General Partner may cause us to borrow funds in order to permit the payment of cash distributions;
the Partnership Agreement permits us to classify up to $36.6 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus;
the Partnership Agreement does not restrict the General Partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
the General Partner currently limits, and intends to continue limiting, its liability for our contractual and other obligations;
the General Partner may exercise its right to call and purchase all of our common units not owned by it and its affiliates if together those entities at any time own more than 80% of our common units;
the General Partner controls the enforcement of the obligations that it and its affiliates owe to us; and
the General Partner decides whether to retain separate counsel, accountants or others to perform services for us.
The General Partner’s liability for our obligations is limited.
The General Partner has included, and will continue to include, provisions in its and our contractual arrangements that limit its liability under such contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against the General Partner or its assets. The General Partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to it. The Partnership Agreement provides that any action taken by the General Partner to limit its liability is not a breach of the General Partner’s fiduciary duties, even if we could have obtained more favorable terms without such limitation on liability. In addition, we are obligated to reimburse or indemnify the General Partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce our amount of cash otherwise available for distribution.
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The Partnership Agreement limits the General Partner’s fiduciary duties to our unitholders.
The Partnership Agreement contains provisions that modify and reduce the fiduciary standards to which the General Partner would otherwise be held by state fiduciary duty law. For example, the Partnership Agreement permits the General Partner to make a number of decisions in its individual capacity, as opposed to its capacity as the General Partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles the General Partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that the General Partner may make in its individual capacity include:
how to allocate business opportunities among us and its affiliates;
whether to exercise its limited call right;
how to exercise its voting rights with respect to the common units it owns; and
whether or not to consent to any merger or consolidation of the Partnership or amendment to the Partnership Agreement.
By purchasing a unit, a unitholder agrees to become bound by the provisions of the Partnership Agreement, including the provisions discussed above.
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 contains provisions that restrict the remedies available to unitholders for actions taken by the General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, the Partnership Agreement:
provides that whenever the General Partner makes a determination or takes, or declines to take, any other action in its capacity as the General Partner, the General Partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any higher standard imposed by the Partnership Agreement, Delaware law, or any other law, rule or regulation, or at equity;
provides that the General Partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as such decisions are made in good faith, meaning that it believed that the decisions were in the best interest of the Partnership;
provides that the General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
provides that the General Partner will not be in breach of its obligations under the Partnership Agreement or its fiduciary duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:
approved by the conflicts committee of the Board, although the General Partner is not obligated to seek such approval;
approved by the vote of a majority of our outstanding common units, excluding any common units owned by the General Partner and its affiliates;
on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.
In a situation involving a transaction with an affiliate or a conflict of interest, any determination by the General Partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the Board determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the last two bullets above, then it will conclusively be deemed that, in making its decision, the Board acted in good faith.
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The Partnership Agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Common unitholders’ voting rights are further restricted by a provision of the Partnership Agreement providing that any units held by a person or group that owns 20% or more of such class of units then outstanding, other than, with respect to our common units, the General Partner, its affiliates, their direct transferees and their indirect transferees approved by the General Partner (which approval may be granted in its sole discretion) and persons who acquired such common units with the prior approval of the General Partner, cannot vote on any matter.
The general partner interest or the control of the General Partner may be transferred to a third party without unitholder consent.
The General Partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the common unitholders. Furthermore, the Partnership Agreement does not restrict the ability of ETO to transfer all or a portion of its ownership interest in the General Partner to a third party. The new owner of the General Partner would then be in a position to replace the majority of the Board, and all of the officers, of the General Partner with its own designees and thereby exert significant control over the decisions made by the Board and the officers of the General Partner.
An increase in interest rates may cause the market price of our common units to decline.
The market price of master limited partnership units, like other yield-oriented securities, may be affected by, among other factors, implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, increases or decreases in interest rates may affect whether or not certain investors decide to invest in master limited partnership units, including ours, and a rising interest rate environment could have an adverse impact on our common unit price and impair our ability to issue additional equity or incur debt to fund growth or for other purposes, including distributions.
We may issue additional limited partner interests without the approval of 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 Partnership Agreement does not limit the number or timing of additional limited partner interests that we may issue, including limited partner interests that are convertible into or senior to our common units, without the approval of our common unitholders as long as the newly issued limited partner interests are not senior to, or pari passu with, the Preferred Units. With the consent of a majority of the Preferred Units, we may issue an unlimited number of limited partner interests that are senior to our common units and pari passu with the Preferred Units.
If a substantial portion of the Preferred Units are converted into common units, common unitholders could experience significant dilution. Furthermore, if holders of such converted Preferred Units were to dispose of a substantial portion of these common units in the public market, whether in a single transaction or series of transactions, it could adversely affect the market price of our common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future.
Our issuance of additional common units, including pursuant to our DRIP, or other equity securities of equal or senior rank, such as additional preferred units, will have the following effects:
our existing common unitholders’ proportionate ownership interest in us will decrease;
our amount of cash available for distribution to common unitholders may decrease;
our ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding common unit may be diminished; and
the market price of our common units may decline.
ETO and the holders of the Preferred Units may sell our common units in the public or private markets, and such sales could have an adverse impact on the trading price of our common units.
As of December 31, 2020, ETO beneficially owns an aggregate of 46,056,228 common units in us. We have granted certain registration rights to ETO and its affiliates with respect to any common units they own, and have filed a registration statement with the SEC for the benefit of the holders of the Preferred Units with respect to any common units they may receive upon conversion of the Preferred Units or exercise of the Warrants. Any sales of these common units in the public or private markets could have an adverse impact on the price of our common units. 
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The General Partner has a call right that may require holders of our common units to sell their common units at an undesirable time or price.
If at any time the General Partner and its affiliates own more than 80% of our outstanding common units, the General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of our common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of the Partnership Agreement. As a result, holders of our common units may be required to sell their common units at an undesirable time or price. These holders may also incur a tax liability upon a sale of their common units. As of December 31, 2020, the General Partner and its affiliates (including ETO), beneficially own an aggregate of approximately 47% of our outstanding common units.
Unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.
Under Delaware law, unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right of limited partners to remove our general partner or to take other action under the Partnership Agreement constituted participation in the “control” of our business. Additionally, under Delaware law, the General Partner has unlimited liability for the obligations of the Partnership, such as our debts and environmental liabilities, except for those contractual obligations of the Partnership that are expressly made without recourse to the General Partner.
The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business. Unitholders could have unlimited liability for obligations of the Partnership if a court or government agency determined that (i) we were conducting business in a state, but had not complied with that particular state’s partnership statute; or (ii) a unitholder’s right to act with other unitholders to remove or replace the General Partner, to approve some amendments to the Partnership Agreement or to take other actions under the Partnership Agreement constituted “control” of our business.
Unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”), we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. The Delaware Act provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their interest in the Partnership and liabilities that are nonrecourse to the Partnership are not counted for purposes of determining whether a distribution is permissible.
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.
Our Partnership Agreement provides that, with certain limited exceptions, the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction) shall be the exclusive forum for any claims, suits, actions or proceedings (i) arising out of or relating in any way to the Partnership Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the Partnership Agreement), any partnership interest or the duties, obligations or liabilities among limited partners or of limited partners, or the rights or powers of, or restrictions on, the limited partners or us, (ii) asserting a claim arising out of any other instrument, document, agreement or certificate contemplated by any provision of the Delaware Act relating to the Partnership or the Partnership Agreement, (iii) asserting a claim against us arising pursuant to any provision of the Delaware Act or (iv) arising out of the federal securities laws of the U.S. or securities or antifraud laws of any governmental authority.
The exclusive forum provision would not apply to suits brought to enforce any liability or duty created by the Securities Act or the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction. To the extent that any such claims may be based upon federal law claims, Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. Furthermore, Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder.
The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents has been challenged in legal proceedings, and it is possible that a court could find the choice of forum provisions contained in our Partnership Agreement to be inapplicable or unenforceable, including with respect to claims arising under the U.S. federal securities laws. This exclusive forum provision may limit the ability of a limited partner to commence
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litigation in a forum that the limited partner prefers, or may require a limited partner to incur additional costs in order to commence litigation in Delaware, each of which may discourage such lawsuits against us or our general partner’s directors or officers. Alternatively, if a court were to find this exclusive forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings described above, we may incur additional costs associated with resolving such matters in other jurisdictions, which could negatively affect our business, results of operations and financial condition.
The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.
Our common units are listed on the NYSE. Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on the Board or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders do not have the same protections afforded to investors in certain corporations that are subject to all of the NYSE corporate governance requirements. Please read Part III, Item 10 “Directors, Executive Officers and Corporate Governance”.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, then our cash available for distribution would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested a ruling from the IRS on this or any other tax matter affecting us.
Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based upon our current operations that we are or will be so treated, a change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
If we were subjected to a material amount of additional entity level taxation by individual states, it would reduce our cash available for distribution.
Changes in current state law may subject us to additional entity level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay the Texas Margin Tax each year at a maximum effective rate of 0.75% of our “margin”, as defined in the law, apportioned to Texas in the prior year. Imposition of any similar taxes by any other state may substantially reduce the cash available for distribution and, therefore, negatively impact the value of an investment in our common units.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial changes or differing interpretations at any time. Members of the U.S. Congress have proposed and considered substantive changes to the existing federal income tax laws that would affect publicly traded partnerships, including elimination of partnership tax treatment for certain publicly traded partnerships. In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships.  There can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future.
Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as
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partnerships for federal income tax purposes. We are unable to predict whether any changes or other proposals will ultimately be enacted. Any future legislative changes could negatively impact the value of an investment in our common units. Unitholders are urged to consult with their own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on their investment in our common units.
Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.
Our unitholders will be treated as partners to whom we will allocate taxable income. Unitholders are required to pay federal income taxes and, in some cases, state and local income taxes, on their share of our taxable income, whether or not they receive cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax due from them with respect to that income.
We may engage in transactions to de-lever the Partnership and manage our liquidity that may result in income and gain to our unitholders. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale. Further, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” (also referred to as “COD income”) being allocated to our unitholders as taxable income. Unitholders may be allocated COD income, and income tax liabilities arising therefrom may exceed cash distributions. The ultimate effect of any such allocations will depend on the unitholder’s individual tax position with respect to its units. Unitholders are encouraged to consult their tax advisors with respect to the consequences of potential COD income or other transactions that may result in income and gain to unitholders.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained.
It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. To the extent possible under the new rules, the General Partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return. Although the General Partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be reduced. These rules are not applicable for tax years beginning on or prior to December 31, 2017.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If our unitholders sell common units, they will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its
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original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.
A substantial portion of the amount realized from a unitholder’s sale of our units, whether or not representing gain, may be taxed as ordinary income to such unitholder due to potential recapture items, including depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than such unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells its units, such unitholder may recognize ordinary income from our allocations of income and gain to such unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.
Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
Our ability to deduct interest paid or accrued on indebtedness properly allocable to a trade or business, “business interest”, may be limited in certain circumstances. Should our ability to deduct business interest be limited, the amount of taxable income allocated to our unitholders in the taxable year in which the limitation is in effect may increase. However, in certain circumstances, a unitholder may be able to utilize a portion of a business interest deduction subject to this limitation in future taxable years. Unitholders should consult their tax advisors regarding the impact of this business interest deduction limitation on an investment in our units.
Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Tax-exempt entities should consult a tax advisor before investing in our common units.
Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.
Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). A unitholder’s share of our income, gain, loss and deduction, and any gain from the sale of our units will generally be considered “effectively connected” income. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.
Moreover, upon the sale, exchange or other disposition of a unit by a non-U.S. unitholder, the transferee is generally required to withhold 10% of the amount realized on such transfer if any portion of the gain on such transfer would be treated as effectively connected income. The application of the withholding requirement on transfers of publicly traded interests, including our units, are suspended until December 31, 2021. For transfers of units occurring after December 31, 2021, the amount realized on a transfer of units will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and such broker will generally be responsible for the relevant withholding obligations. Non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in 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.
Because we cannot match transferors and transferees of common units, we have adopted certain methods for allocating depreciation and amortization deductions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to the use of these methods could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.
We generally prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We generally prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month (the “Allocation
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Date”), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate (i) certain deductions for depreciation of capital additions, (ii) gain or loss realized on a sale or other disposition of our assets, and (iii) in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned common units. In that case, the unitholder may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.
We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.
A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain recognized from our unitholders’ sale of common units, have a negative impact on the value of the common units, or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
As a result of investing in our common units, you will likely become subject to state and local taxes and income tax return filing requirements in jurisdictions where we operate or own or acquire properties.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with state and local filing requirements.
We currently conduct business and control assets in several states, many of which currently impose a personal income tax on individuals. Many of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states or foreign jurisdictions that impose an income tax. It is your responsibility to file all foreign, federal, state and local tax returns and pay any taxes due in these jurisdictions. Unitholders should consult with their own tax advisors regarding the filing of such tax returns, the payment of such taxes, and the deductibility of any taxes paid.
General Risk Factors
If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership. Although we continuously evaluate the effectiveness of and improve upon our
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internal controls, our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002 (“Section 404”). For example, Section 404 requires us to, among other things, review and report annually on the effectiveness of our internal control over financial reporting. In addition, our independent registered public accountants are required to assess the effectiveness of our internal control over financial reporting since we ceased to be an emerging growth company under the Jumpstart Our Business Startups Act (the “JOBS Act”) on December 31, 2018.
Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our independent registered public accounting firm’s conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls will subject us to regulatory scrutiny and may result in a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.
We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.
Our operations are subject to inherent risks such as equipment defects, malfunctions and failures, and natural disasters that can result in uncontrollable flows of gas or well fluids, fires and explosions. These risks could expose us to substantial liability for personal injury, death, property damage, pollution and other environmental damages. Our insurance may be inadequate to cover our liabilities. Further, insurance covering the risks we face or in the amounts we desire may not be available in the future or, if available, the premiums may not be commercially justifiable. If we were to incur substantial liability and such damages were not covered by insurance or were in excess of policy limits, or if we were to incur liability at a time when we are not able to obtain liability insurance, our business, results of operations and financial condition could be adversely affected.
Cybersecurity breaches and other disruptions of our information systems could compromise our information and operations and expose us to liability, which would cause our business and reputation to suffer.
We rely on our information technology infrastructure to process, transmit and store electronic information critical to our business activities. In recent years, there has been a rise in the number of cyberattacks on other companies’ network and information systems by both state-sponsored and criminal organizations, and as a result, the risks associated with such an event continue to increase. A significant failure, compromise, breach or interruption of our information systems could result in a disruption of our operations, customer dissatisfaction, damage to our reputation, a loss of customers or revenues and potential regulatory fines. If any such failure, interruption or similar event results in improper disclosure of information maintained in our information systems and networks or those of our customers, suppliers or vendors, including personnel, customer, pricing and other sensitive information, we could also be subject to liability under relevant contractual obligations and laws and regulations protecting personal data and privacy. Our financial results could also be adversely affected if our information systems are breached or an employee causes our information systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating such systems.
Terrorist attacks, the threat of terrorist attacks or other sustained military campaigns may adversely impact our results of operations.
The long-term impact of terrorist attacks and the magnitude of the threat of future terrorist attacks on the energy industry in general and on us in particular are not known at this time. Uncertainty surrounding sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil and natural gas supplies and markets for crude oil, natural gas and natural gas liquids and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. Changes in the insurance markets attributable to terrorist attacks may make insurance against such attacks more difficult for us to obtain, if we choose to do so. Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage. Instability in the financial markets resulting from terrorism or war could also negatively affect our ability to raise capital.
ITEM 1B.    Unresolved Staff Comments
None.
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ITEM 2.    Properties
We do not currently own or lease any material facilities or properties for storage or maintenance of our compression units. As of December 31, 2020, our headquarters consisted of 19,297 square feet of leased office space located at 111 Congress Avenue, Austin, Texas 78701.
ITEM 3.    Legal Proceedings
From time to time, we and our subsidiaries may be involved in various claims and litigation arising in the ordinary course of business. In management’s opinion, the resolution of such matters is not expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows.
ITEM 4.    Mine Safety Disclosures
None.
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PART II
ITEM 5.    Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our Partnership Interests
As of February 11, 2021, we had 96,996,304 common units outstanding. ETO owns 100% of the membership interests in the General Partner and, as of February 11, 2021, beneficially owns approximately 47% of our outstanding common units.
As of February 11, 2021, we had outstanding 500,000 Preferred Units representing limited partner interests in the Partnership, all of which were held by Preferred Unitholders. The Preferred Units rank senior to the common units with respect to distributions and rights upon liquidation. The Preferred Unitholders are entitled to receive cumulative quarterly 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 as follows: one third on or after April 2, 2021, two thirds on or after April 2, 2022, and the remainder on or after April 2, 2023. On or after April 2, 2023, we have the option to redeem all or any portion of the Preferred Units then outstanding. On or after April 2, 2028, the Preferred Unitholders have the right to require us to redeem all or a portion of the Preferred Units then outstanding, the purchase price for which we may elect to pay up to 50% in common units, subject to certain additional limits.
Our common units, which represent limited partner interests in us, are listed on the New York Stock Exchange (“NYSE”) under the symbol “USAC.”
Holders
At the close of business on February 11, 2021, based on information received from the transfer agent of the common units, we had 70 holders of record of our common units. The number of record holders does not include holders of common units held in “street name” or persons, partnerships, associations, corporations or other entities identified in security position listings maintained by depositories. There is no established public trading market for the Preferred Units, all of which are owned by the Preferred Unitholders. Please read Part II, Item 8 “Financial Statements and Supplementary Data – Note 11 – Preferred Units and – Note 12 – Partners’ Capital”.
Selected Information from the Partnership Agreement
Set forth below is a summary of the significant provisions of the Partnership Agreement that relate to available cash.
Available Cash
The Partnership Agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date, first to the holders of the Preferred Units and then to the common unitholders. The Partnership Agreement generally defines available cash, for each quarter, as cash on hand at the end of a quarter plus cash on hand resulting from working capital borrowings made after the end of the quarter less the amount of reserves established by the General Partner to provide for the proper conduct of our business, comply with applicable law, the Credit Agreement or other agreements; and provide funds for distributions to our unitholders for any one or more of the next four quarters. Working capital borrowings are borrowings made under a credit facility, commercial paper facility or other similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months from sources other than working capital borrowings.
Issuer Purchases of Equity Securities
None.
Sales of Unregistered Securities; Use of Proceeds from Sale of Securities
None.
Equity Compensation Plan
For disclosures regarding securities authorized for issuance under equity compensation plans, see Part III, Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters”.
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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, 2020, which has been derived from our audited consolidated financial 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 Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Part II, Item 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 Discussion and Analysis of Financial Condition and Results of Operations” contained in Part II, Item 7 of this report. In addition, a discussion of the risk factors that could affect our business and future financial condition and results of operations is included under Part I, Item 1A “Risk Factors” of this report. Additionally, Note 2 – Basis of Presentation and Significant Accounting Policies and Note 17 – Commitments and Contingencies under Part II, Item 8 “Financial Statements and Supplementary Data” of this report provide descriptions of areas where estimates and judgments and contingent liabilities could result in different amounts being recognized in our accompanying consolidated financial statements.
We believe that investors benefit from having access to the same financial measures utilized by management. The following table includes the non-GAAP financial measures of Adjusted gross margin, Adjusted EBITDA and Distributable Cash Flow (or “DCF”). For definitions of Adjusted gross margin, Adjusted EBITDA and DCF, and reconciliations of such measures to their most directly comparable financial measures calculated and presented in accordance with GAAP, please read “Non-GAAP Financial Measures” below.
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Year Ended December 31,
20202019201820172016
(in thousands, except per unit amounts)
Revenues:
Contract operations$644,194 $664,162 $546,896 $249,346 $239,143 
Parts and service11,117 14,236 20,402 10,085 7,921 
Related party12,372 19,967 17,054 17,240 16,873 
Total revenues667,683 698,365 584,352 276,671 263,937 
Costs and expenses:
Costs of operations, exclusive of depreciation and amortization205,939 227,303 214,724 125,204 112,898 
Depreciation and amortization238,968 231,447 213,692 166,558 155,134 
Selling, general and administrative59,981 64,397 68,995 24,944 22,739 
Loss (gain) on disposition of assets146 940 12,964 (367)120 
Impairment of compression equipment8,090 5,894 8,666 — — 
Impairment of goodwill619,411 — — 223,000 — 
Total costs and expenses1,132,535 529,981 519,041 539,339 290,891 
Operating income (loss)(464,852)168,384 65,311 (262,668)(26,954)
Other income (expense):
Interest expense, net(128,633)(127,146)(78,377)— — 
Other86 80 41 (223)(153)
Total other expense(128,547)(127,066)(78,336)(223)(153)
Net income (loss) before income tax expense (benefit)(593,399)41,318 (13,025)(262,891)(27,107)
Income tax expense (benefit)1,333 2,186 (2,474)1,843 (163)
Net income (loss)(594,732)39,132 (10,551)$(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 Margin
Adjusted gross margin is a non-GAAP financial measure. We define Adjusted gross margin as revenue less cost of operations, exclusive of depreciation and amortization expense. We believe that Adjusted gross margin is useful as a supplemental measure to investors of our operating profitability. 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. Adjusted gross margin should not be considered an alternative to, or more meaningful than, gross margin or any other measure of financial performance presented in accordance with GAAP. Moreover, Adjusted gross 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 margin as a measure of our performance, we believe that it is important to consider gross margin determined under GAAP, as well as Adjusted gross 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,
20202019201820172016
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 amortization238,968 231,447 213,692 166,558 155,134 
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 (benefit). We define Adjusted EBITDA as EBITDA plus impairment of compression equipment, impairment of goodwill, interest income on capital lease, unit-based compensation expense, severance charges, certain transaction expenses, loss (gain) on disposition of assets and other. We view Adjusted EBITDA as one of management’s primary tools for evaluating our results of operations, and we track this item on a monthly basis both as an absolute amount and as a percentage of revenue compared to the prior month, year-to-date, prior year and budget. Adjusted EBITDA is used as a supplemental financial measure by our management and external users of our financial statements, such as investors and commercial banks, to assess:
the financial performance of our assets without regard to the impact of financing methods, capital structure or historical cost basis of our assets;
the viability of capital expenditure projects and the overall rates of return on alternative investment opportunities;
the ability of our assets to generate cash sufficient to make debt payments and to 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.
We believe that Adjusted EBITDA provides useful information to investors because, when viewed with our GAAP results and the accompanying reconciliations, it may provide a more complete understanding of our performance than GAAP results alone. We also believe that external users of our financial statements benefit from having access to the same financial measures that management uses in evaluating the results of our business.
Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP as measures of operating performance and liquidity. Moreover, our Adjusted EBITDA as presented may not be comparable to similarly titled measures of other companies.
Because we use capital assets, depreciation, impairment of compression equipment, loss (gain) on disposition of assets and the interest cost of acquiring compression equipment are also necessary elements of our costs. Unit-based compensation
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expense related to equity awards to employees is also a necessary component of our business. Therefore, measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income (loss) and net cash provided by operating activities determined under GAAP, as well as Adjusted EBITDA, to evaluate 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 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,
20202019201820172016
Net income (loss)$(594,732)$39,132 $(10,551)$(264,734)$(26,944)
Interest expense, net128,633 127,146 78,377 — — 
Depreciation and amortization238,968 231,447 213,692 166,558 155,134 
Income tax expense (benefit)1,333 2,186 (2,474)1,843 (163)
EBITDA$(225,798)$399,911 $279,044 $(96,333)$128,027 
Interest income on capital lease383 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 charges3,130 831 3,171 — — 
Loss (gain) on disposition of assets146 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 expense8,402 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)— — 
Other4,230 2,426 (2,030)24 (748)
Changes in operating assets and liabilities283 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, 2020, 2019 and 2018, unit-based compensation expense included $3.2 million, $2.5 million and $1.3 million of 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.
(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.
(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”.
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 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 (after distributions on the Preferred Units but prior to any retained cash reserves established by the General Partner and the effect of the DRIP) to the cash distributions we expect to pay our common unitholders. Using DCF, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions.
DCF should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance and liquidity. Moreover, our DCF as presented may not be comparable to similarly titled measures of other companies.
Because we use capital assets, depreciation, impairment of compression equipment, loss (gain) on disposition of assets, the interest cost of acquiring compression equipment and maintenance capital expenditures are necessary elements of our costs. Unit-based compensation expense related to equity awards to employees is also a necessary component of our business. Therefore, measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income (loss) and net cash provided by operating activities determined under GAAP, as well as DCF, to evaluate our financial performance and our liquidity. Our DCF excludes some, but not all, items that affect net income (loss) and net cash provided by operating activities, and these measures may vary among companies. Management compensates for the limitations of DCF as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating this knowledge into their decision making processes.
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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,
20202019201820172016
Net income (loss)$(594,732)$39,132 $(10,551)$(264,734)$(26,944)
Non-cash interest expense8,402 7,607 5,080 — — 
Depreciation and amortization238,968 231,447 213,692 166,558 155,134 
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 charges3,130 831 3,171 — — 
Loss (gain) on disposition of assets146 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 recovery336 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 expenditures23,301 29,592 32,502 20,980 8,252 
Transaction expenses(136)(578)(4,181)— — 
Severance charges(3,130)(831)(3,171)— — 
Distributions on Preferred Units48,750 48,750 36,430 — — 
Other3,364 (541)224 (1,777)(593)
Changes in operating assets and liabilities283 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, 2020, 2019 and 2018, unit-based compensation expense included $3.2 million, $2.5 million and $1.3 million of 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.
(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.
(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”.
(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 divided by distributions declared to common unitholders in respect of such period. Cash Coverage Ratio is defined as DCF divided by cash distributions expected to be paid to common unitholders in respect of such period, after taking into account the non-cash impact of the DRIP. We believe DCF Coverage Ratio and Cash Coverage Ratio are important measures of operating performance because they allow management, investors and others to gauge our ability to pay cash distributions to common unitholders using the cash flows that we generate. Our DCF Coverage Ratio and Cash Coverage Ratio as presented may not be comparable to similarly titled measures of other companies.
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The following table summarizes certain coverage ratios for the periods presented (dollars in thousands):
Year Ended December 31,
202020192018 (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 Ratio1.09 x1.13 x1.25 x
Cash Coverage Ratio1.10 x1.14 x1.26 x
________________________
(1)Represents distributions to the holders of our common units as of the record date.
(2)Represents distributions to holders enrolled in the DRIP as of the record date.
(3)Represents cash distributions declared for common units not participating in the DRIP.
(4)Distributions for the year ended December 31, 2018 reflect only three quarters of distributions as the USA Compression Predecessor did not pay distributions prior to the Transactions Date. DCF, however, reflects a full year of DCF. On a pro forma basis, both the DCF Coverage Ratio and Cash Coverage Ratio for the year ended December 31, 2018 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.  
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 Regarding Forward-Looking Statements” and Part I, Item 1A “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. Demand for our services is driven by the domestic production of natural gas and crude oil. As such, we have focused our activities in areas of attractive natural gas and crude oil production growth, which are generally found in these shale and unconventional resource plays. According to studies promulgated by the EIA, the production and transportation volumes in these shale plays are expected to increase over the long 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 to meet these changing operating conditions due to the operational design flexibility inherit 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
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an existing producing well, in order to reduce the hydrostatic pressure and allow the oil to flow at a higher rate, and other artificial lift technologies are critical to the enhancement of oil production from horizontal wells operating in tight shale plays.
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
A significant amount of our assets are utilized in natural gas infrastructure applications typically located in shale plays, primarily in centralized gathering systems and processing facilities utilizing large horsepower compression units. Given the 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 relative to other businesses more directly tied to drilling activity and wellhead economics. In addition to our natural gas infrastructure applications, a portion of our fleet is used in connection with gas lift applications on crude oil production targeted by horizontal drilling 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 stability in commodity prices encouraged investment in domestic exploration and production (“E&P”) and midstream infrastructure across the energy industry, particularly in the low-cost basins characterized by associated gas and crude oil production. The development of these basins producing both commodities has created additional incremental demand for natural gas 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 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 services. Accordingly, we have reduced our planned capital spending significantly for 2021.
The EIA’s January 2021 Short-Term Energy Outlook (“EIA Outlook”) estimates that annual U.S. crude oil production averaged 11.3 million barrels per day (“bpd”) in 2020, down 1.0 million bpd from 2019 reflecting the impact of well curtailments and a decrease in drilling activity related to low crude oil prices. While the price of crude oil rebounded during the second quarter of 2020 and remained relatively stable during the third and fourth quarters of 2020, and rig counts have
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increased modestly since the recent bottom during summer 2020, many E&P companies, including some of our customers, continue to take a cautious approach to development plans and budget for reduced capital expenditure forecasts. The EIA Outlook forecasts total U.S. crude oil production in 2021 to decline again, averaging 11.1 million bpd, before increasing to 11.5 million bpd in 2022. Taking into account an approximate six-month lag between changes in crude oil prices and changes in crude oil production, 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 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 and natural gas, however, is 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 their existing production. For example, as wells age, and the 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 bottom out in March 2021 and then increase through the rest of 2021, followed by continued increase in 2022. We expect the baseload natural gas demand previously described will continue to 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 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 respect to demand could have a varying impact on our business. Whereas several factors, including uncertain future demand, caused volatility in crude oil prices 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 crude oil, 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 and demand may likely have an impact on activity levels in both the upstream and midstream sectors, we cannot predict the ultimate magnitude of that impact on our business and expect it to be varied across our operations, depending on the region, customer, nature of compression application, contract term and other factors. We believe our customers’ mid- to long-term expectations regarding commodity prices and the cost they would incur to return our large horsepower equipment will provide an incentive for our customers to keep our equipment in the field following expiration of the 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 our business will be impacted by the factors described above, as well as future developments beyond our control, cannot be predicted with reasonable certainty. However, we continue to believe that overall the long-term demand for our compression services will continue given the necessity of compression in facilitating the transportation and processing of natural gas 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 municipalities in which we operate to 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 and excludes certain gas treating assets for which horsepower is not a relevant metric.
Year Ended December 31,Percent
20202019Change
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 end82.8 %93.7 %(11.6)%
Average for the period (8)86.8 %94.1 %(7.8)%
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(1)Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order).
(2)Total available horsepower is revenue generating horsepower under contract for which we are billing a customer, horsepower in our fleet that is under contract but is not yet generating revenue, horsepower not yet in our fleet that is under contract but not yet generating revenue and that is subject to a purchase order, and idle horsepower. Total available horsepower excludes new horsepower on order for which we do not have an executed compression services contract.
(3)Revenue generating horsepower is horsepower under contract for which we are billing a customer.
(4)Calculated as the average of the month-end revenue generating horsepower for each of the months in the period.
(5)Calculated as the average of the result of dividing the contractual monthly rate, 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.
(6)Calculated as the average of the month-end revenue generating horsepower per revenue generating compression unit for each of the months in the period.
(7)Horsepower utilization is calculated as (i) the sum of (a) revenue generating horsepower, (b) horsepower in our fleet that is under contract, but is not yet generating revenue and (c) horsepower not yet in our fleet that is under contract, not yet generating revenue and that is subject to a purchase order, divided by (ii) total available horsepower less idle horsepower that is under repair. Horsepower utilization based on revenue generating horsepower and fleet horsepower was 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 1.2% increase in fleet horsepower as of December 31, 2020 compared to December 31, 2019 was attributable to compression units added to our fleet primarily for specific customer demand for our compression services, partially offset by compression units impaired during the current period. The 9.4% decrease in revenue generating horsepower as of December 31, 2020 compared to December 31, 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 a decrease in demand for compression services driven by a decline in U.S. crude oil and natural gas activity.
The 3.6% increase in average horsepower per revenue generating compression unit was driven primarily by the composition of compression unit returns. The 0.4% increase in average revenue per revenue generating horsepower per month for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to contracts on new compression units and selective price increases on our existing large horsepower fleet, partially offset by reduced pricing in our small horsepower 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 idle horsepower from compression units returned to us and (2) a 2.0% decrease in horsepower that is on-contract or pending-contract but not yet active. Average
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horsepower utilization decreased to 86.8% during the year ended December 31, 2020 compared to 94.1% during the year ended December 31, 2019. The 7.8% decrease in average horsepower utilization is primarily due to (1) a 6.9% increase in our average idle horsepower from compression units returned to us and (2) a 3.0% decrease in horsepower that is on-contract or pending-contract but not yet active. The decreases in period end and average horsepower utilization are primarily due to a decrease in demand for compression services driven by a decline in U.S. crude oil and natural gas activity.
Horsepower utilization based on revenue generating horsepower and fleet horsepower decreased to 80.4% as of December 31, 2020 compared to 89.9% as of December 31, 2019. The 10.6% decrease in horsepower utilization based on revenue generating horsepower as of December 31, 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 84.5% for the year ended December 31, 2020 compared to 89.8% for the year ended December 31, 2019. The 5.9% decrease in average horsepower utilization based on revenue generating horsepower for the year ended December 31, 2020 was primarily attributable to an increase in our average idle horsepower from compression units returned to us. The decreases in period end and average horsepower utilization based on revenue generating horsepower and fleet horsepower are primarily due to a decrease in demand for compression services driven by a decline in U.S. crude oil and natural gas activity.
Financial Results of Operations
Year ended December 31, 2020 compared to the year ended December 31, 2019
The following table summarizes our results of operations for the periods presented (dollars in thousands):
Year Ended December 31,Percent
20202019Change
Revenues:
Contract operations$644,194 $664,162 (3.0)%
Parts and service11,117 14,236 (21.9)%
Related party12,372 19,967 (38.0)%
Total revenues667,683 698,365 (4.4)%
Costs and expenses:
Cost of operations, exclusive of depreciation and amortization205,939 227,303 (9.4)%
Depreciation and amortization238,968 231,447 3.2 %
Selling, general and administrative59,981 64,397 (6.9)%
Loss on disposition of assets146 940 (84.5)%
Impairment of compression equipment8,090 5,894 37.3 %
Impairment of goodwill619,411 —           *
Total costs and expenses1,132,535 529,981           *
Operating income (loss)(464,852)168,384           *
Other income (expense):
Interest expense, net(128,633)(127,146)1.2 %
Other86 80 7.5 %
Total other expense(128,547)(127,066)1.2 %
Net income (loss) before income tax expense(593,399)41,318           *
Income tax expense1,333 2,186 (39.0)%
Net income (loss)$(594,732)$39,132           *
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*Not meaningful.
Contract operations revenue. The $20.0 million decrease in contract operations revenue for the year ended December 31, 2020 compared to 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, 2020 compared to the year ended December 31, 2019, partially offset by a 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 not
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materially impacted by any renegotiations of our contracts during the period with our customers. Additionally, 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 their primary term during the period.
Parts and service revenue. 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 a reduction in maintenance work performed on units at our customers’ locations that are outside the scope of our core maintenance activities and offered as a courtesy to our customers, and freight and crane charges that are directly reimbursable by customers. Demand for retail parts and services fluctuates from period to period based on the varying needs of our customers.
Related party revenue. Related party revenue was 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 $21.4 million decrease in cost of operations for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to (1) an $11.5 million decrease in direct expenses, such as parts and fluids expenses, (2) a $6.2 million decrease in direct labor expenses, (3) a $4.6 million decrease in retail parts and services expenses, which had a corresponding decrease in parts and service revenue, (4) a $3.1 million decrease in expenses related to our vehicle fleet and (5) a $1.7 million decrease in training and other indirect expenses. The decreases in parts, fluids, direct labor, vehicle expenses, training and other indirect expenses are primarily driven by the decrease in average revenue generating horsepower and reduced headcount during the current period. The decreases were partially offset by (6) a $5.1 million increase in ad valorem tax expenses due primarily to refunds received during the prior period.
Depreciation and amortization expense.  The $7.5 million increase in depreciation and amortization expense for the year ended December 31, 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.