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 , 2021
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
(Exact Name of Registrant as Specified in its Charter)
| (State or Other Jurisdiction of Incorporation or Organization) | (I.R.S. Employer Identification No.) | ||||
(Address of principal executive offices) (zip code)
(512 ) 473-2662
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading symbol(s) | Name of each exchange on which registered | ||||||||||||
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.
| ☒ | Accelerated filer | ☐ | |||||||||
| Non-accelerated filer | ☐ | Smaller reporting company | |||||||||
| Emerging growth company | |||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant 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, 2021, the last business day of the registrant’s most recently completed second fiscal quarter was $825.2 million. This calculation does not reflect a determination that such persons are affiliates for any other purpose.
As of February 10, 2022, there were 97,377,355 common units outstanding.
Table of Contents
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Glossary
The abbreviations, acronyms and industry terminology used in this Annual Report are defined as follows:
| COVID-19 | novel coronavirus 2019 | |||||||
| Credit Agreement | Seventh Amended and Restated Credit Agreement, dated as of December 8, 2021, by and among USA Compression Partners, LP, as borrower, the guarantors party thereto from time to time, the lenders party thereto from time to time, JPMorgan Chase Bank, N.A., as administrative agent and issuing bank, JPMorgan Chase Bank, N.A., MUFG Union Bank, N.A., Regions Bank, Royal Bank of Canada, Truist Securities, Inc. and Wells Fargo Bank, National Association, as joint bookrunners and joint lead arrangers, Fifth Third Bank, National Association, The Bank of Nova Scotia, Houston Branch, NYCB Specialty Finance Company, LLC, Sumitomo Mitsui Banking Corporation, Barclays Bank PLC and PNC Bank, National Association, as senior managing agents, as may be amended from time to time. | |||||||
| DERs | distribution equivalent rights | |||||||
| DRIP | distribution reinvestment plan | |||||||
| EBITDA | earnings before interest, taxes, depreciation and amortization | |||||||
| EIA | United States Energy Information Agency | |||||||
| Energy Transfer | Energy Transfer LP, for periods following its merger with Energy Transfer Operating, L.P., and Energy Transfer Operating, L.P. for periods prior to such merger | |||||||
| Exchange Act | Securities Exchange Act of 1934, as amended | |||||||
| GAAP | generally accepted accounting principles of the United States of America | |||||||
| Preferred Units | Series A Preferred Units representing limited partner interests in USA Compression Partners, LP | |||||||
| SEC | United States Securities and Exchange Commission | |||||||
| Senior Notes 2026 | $725.0 million aggregate principal amount of senior notes due on April 1, 2026 | |||||||
| Senior Notes 2027 | $750.0 million aggregate principal amount of senior notes due on September 1, 2027 | |||||||
| SOFR | Secured Overnight Financing Rate | |||||||
| 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 the severity and duration of world health events, including the COVID-19 pandemic, related economic repercussions, actions taken by governmental authorities and other third parties in response to such events and the resulting disruption in the oil and gas industry and impact on demand for oil and gas;
•changes in general economic conditions, including inflation, and changes in economic conditions of the crude oil and natural gas industries;
•competitive conditions in our industry, including competition for employees in a tight labor market;
•renegotiation of material terms of customer contracts;
•actions taken by our customers, competitors and third-party operators;
•changes in the availability and cost of capital, including changes to interest rates;
•operating hazards, natural disasters, epidemics, pandemics (such as COVID-19), weather-related impacts, casualty losses and other matters beyond our control;
•operational challenges relating to COVID-19 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 deterioration of the financial condition of our customers, which may result in the initiation of bankruptcy proceedings with respect to customers;
•the restrictions on our business that are imposed under our long-term debt agreements;
•information technology risks including the risk from cyberattacks;
•the effects of existing and future laws and governmental regulations;
•the effects of future litigation; and
•our ability to realize the anticipated benefits of acquisitions.
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 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 wholly owned by Energy Transfer.
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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, 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. On April 2, 2018, we acquired all of the equity interests in CDM Resource Management LLC and CDM Environmental & Technical Services LLC (the “CDM Acquisition”).
As of December 31, 2021, we had 3,689,018 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, 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 collectively increase over the long term. Furthermore, the changes in production volumes and pressures of shale plays over time require a wider range of compression 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 nine 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 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 production 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. Our customers may have compression demands in conjunction with their field development projects in areas of the U.S. where we are not currently operating, and 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
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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
Seventh Amended and Restated Credit Agreement
On December 8, 2021, we amended and restated our existing credit agreement by entering into the Credit Agreement which, among other things, extended the maturity of our revolving credit facility until 2026, as described further in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Revolving Credit Facility.”
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.
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, 2021, the average age of our compression units was approximately nine 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 (including compression units on order) as of December 31, 2021. 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.
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The following table provides a summary of our compression units by horsepower as of December 31, 2021:
| Unit Horsepower | Fleet Horsepower | Number of Units | Horsepower on Order (1) | Number of Units on Order | Total Horsepower | Number of Units | Percent of Total Horsepower | Percent of Units | ||||||||||||||||||||||||||||||||||||||||||
Small horsepower | ||||||||||||||||||||||||||||||||||||||||||||||||||
| <400 | 508,496 | 2,991 | — | — | 508,496 | 2,991 | 13.7 | % | 55.2 | % | ||||||||||||||||||||||||||||||||||||||||
Large horsepower | ||||||||||||||||||||||||||||||||||||||||||||||||||
| ≥400 and <1,000 | 430,677 | 736 | — | — | 430,677 | 736 | 11.6 | % | 13.6 | % | ||||||||||||||||||||||||||||||||||||||||
| ≥1,000 | 2,749,845 | 1,684 | 25,000 | 10 | 2,774,845 | 1,694 | 74.7 | % | 31.2 | % | ||||||||||||||||||||||||||||||||||||||||
| Total large horsepower | 3,180,522 | 2,420 | 25,000 | 10 | 3,205,522 | 2,430 | 86.3 | % | 44.8 | % | ||||||||||||||||||||||||||||||||||||||||
| Total horsepower | 3,689,018 | 5,411 | 25,000 | 10 | 3,714,018 | 5,421 | 100.0 | % | 100.0 | % | ||||||||||||||||||||||||||||||||||||||||
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(1)As of December 31, 2021, we had 10 large horsepower units, consisting of 25,000 horsepower, on order for delivery during 2022. Subsequent to December 31, 2021, we ordered an additional 20 large horsepower units, consisting of 50,000 horsepower, on order for delivery during 2022.
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 2022 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.
We adhere to routine, preventive and scheduled maintenance cycles. Each of our compression units is subjected to rigorous sizing and diagnostic analyses, including lubricating oil analysis and engine exhaust emission analysis. We have proprietary field service automation capabilities that allow our service technicians to electronically record and track operating, technical, environmental and commercial information at the discrete unit level. These capabilities allow our field technicians to identify potential problems and often act on them before such problems result in down-time.
Generally, we expect each of our compression units to undergo a major overhaul between service deployment cycles. The timing of these major overhauls depends on multiple factors, including run time and operating conditions. A major overhaul involves the periodic rebuilding of the unit to materially extend its economic useful life or to enhance the unit’s ability to fulfill broader or more diversified compression applications. Because our compression fleet is comprised of units of varying horsepower that have been placed into service with staggered initial on-line dates, we are able to schedule overhauls in a way that avoids excessive annual maintenance capital expenditures and minimizes the revenue impact of down-time.
We believe that our customers, by outsourcing their compression requirements, can achieve higher compression run-times, which translates into increased volumes of either natural gas or crude oil production and, therefore, increased revenues. Utilizing our compression services also allows our customers to reduce their operating, maintenance and equipment costs by allowing us to efficiently manage their changing compression needs. In many of our service contracts, we guarantee our customers availability (as described below) ranging from 95% to 98%, depending on field-level requirements.
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 39%, 35% and 33% of our revenue for the years ended December 31, 2021, 2020 and 2019, 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, Cooper Machinery Services Gemini products and Arrow Engine Company for compressor frames and cylinders. We also rely primarily
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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 recent past varied between six months and one year due to changes in demand and supply allocations, as of December 31, 2021, lead-times for such engines and frames are slightly less than one year. 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”.
Governmental 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 provide information to 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.
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We do not believe that compliance with current federal, state or local 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 regulations 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 Governmental Legislation and Regulation – We and our customers are subject to substantial environmental regulation, and changes in these regulations could increase our and their costs or liabilities and result in decreased demand for our services”.
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 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 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. In addition, in November 2021, the EPA proposed a rule to further reduce methane and VOC emissions from new and existing sources in the oil and gas sector.
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
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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, the government could seek to pursue legislative, regulatory or executive initiatives that may impose significant restrictions on fossil-fuel exploration and 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. Other energy legislation and initiatives could include a carbon tax, methane fee 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. 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, and the United States formally rejoined in February 2021. The United States has established an economy-wide target of reducing its net GHG emissions by 50-52 percent below 2005 levels in 2030 and achieving net zero GHG emissions economy-wide by no later than 2050. 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, methane fee or cap and trade program, could result in increased compliance or operating costs or additional operating restrictions or reduced demand for our services, and
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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, which could have an adverse effect on our ability to obtain external financing.
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 or our customers’ assets and operations, or result in increased cost or difficulty obtaining insurance. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas liquids (“NGLs”) and natural gas is generally impacted by periods of colder weather and warmer weather, so any changes in climate could affect the market for these fuels, and thus demand for our services. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our services could be affected by increased temperature volatility.
We recognize the need to decrease emissions and integrate alternative energy sources into our operations, and we actively pursue economically beneficial opportunities to reduce our environmental footprint. To that end, we have been exploring the use of a dual-drive technology, which offers the ability to switch compression drivers between an electric motor and a natural gas engine, to reduce our emissions of nitrogen oxide, carbon monoxide, CO2 and VOCs.
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 December 7, 2021, the EPA and the U.S. Army Corps of Engineers issued a proposed rule revising the standard for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the CWA. Should the proposed rule be adopted 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
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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, 2021, USAC Management had 697 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.
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. We have a strong commitment to safety. 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
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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 approximately 1,600,000 hours worked in 2021, our TRIR was 0.75 for 2021. We believe our low TRIR and our 3,800,000 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 services, we place a high priority on the safety of our employees and the continued operation of our assets, 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
•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.
•An extended 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.
•Pandemics and other public health crises, including the ongoing global COVID-19 pandemic, may have an adverse effect on our business and results of operations.
•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 face significant competition that may cause us to lose market share and reduce our 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.
•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 debt level, including any increases in interest rates, may limit our flexibility in obtaining additional financing, pursuing other business opportunities and paying distributions.
•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.
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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.
•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.
•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.
Risks Related to Governmental Legislation and Regulation
•We and our customers are subject to substantial environmental regulation, and changes in these regulations could increase our and their costs or liabilities and result in decreased demand for our services.
•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.
•Energy Transfer 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 Energy Transfer, 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 holders of our common units to sell their 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.
•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.
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•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
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 $51.1 million per quarter, or $204.5 million per year, based on the number of common units outstanding as of February 10, 2022.
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.
An extended 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 extended reduction in the demand for natural gas or crude oil could 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. At 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 decline in commodity prices and the demand for and production of crude oil and natural gas 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 2020 and 2021. 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 and utilization from our customers in gas lift applications, and we experienced such effects in 2020, as an example. 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.
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.
Pandemics and other public health crises, including the ongoing global COVID-19 pandemic, may have an adverse effect on our business and results of operations.
Pandemics, such as the COVID-19 pandemic, or other public health crises could significantly reduce the demand for, price of and level of production of natural gas and crude oil, which could have an adverse impact on our business and results of operations. The COVID-19 pandemic that began in early 2020 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 declined in 2020 due in part to the COVID-19 pandemic and associated government imposed restrictions and decreased consumer demand. This reduced demand also contributed to a decline in commodity prices and production. These declines had, and may again in the future have, a negative impact on many of our customers involved in the domestic exploration and production of crude oil and natural gas, which in turn had and may continue to have, an adverse effect on our business and results of operations.
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, could potentially cause:
•a negative impact on our results of operations and financial condition;
•the deterioration of the financial condition of our customers, suppliers and vendors;
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•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 or other pandemics 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 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 39%, 35% and 33% of our revenue for the years ended December 31, 2021, 2020 and 2019, 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.
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, 2021, approximately 33% 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
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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.
Our debt level, including any increases in interest rates, may limit our flexibility in obtaining additional financing, pursuing other business opportunities and paying distributions.
As of December 31, 2021, we had $2.0 billion of total debt, net of amortized deferred financing costs, outstanding under 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 up to $200 million. The Credit Agreement matures on December 8, 2026, except that if any portion of the Senior Notes 2026 are outstanding on December 31, 2025, the Credit Agreement will mature on December 31, 2025. As of December 31, 2021, we had outstanding borrowings under the Credit Agreement of $516.3 million, $1.1 billion of borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of $261.9 million.
As of December 31, 2021, 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, 2021, our leverage ratio under the Credit Agreement was 5.09x. Financial covenants in the Credit Agreement permit a maximum leverage ratio of not greater than 5.75 to 1.00 through the second fiscal quarter of 2022; 5.50 to 1.00 from the third fiscal quarter of 2022 through the third fiscal quarter of 2023; and 5.25 to 1.00 thereafter (except that we may increase the applicable Total Leverage Ratio by 0.25 for any fiscal quarter during which a Specified Acquisition (as defined in the Credit Agreement) occurs and the following two fiscal quarters, but in no event shall the maximum Total Leverage Ratio exceed 5.50 to 1.00 for any fiscal quarter as a result of such increase), an Interest Coverage Ratio (as defined in the Credit Agreement) of not less than 2.50 to 1.00 and a Secured Leverage Ratio (as defined in the Credit Agreement) of not greater than 3.00 to 1.00 or less than 0.00 to 1.00. As of February 10, 2022, we had outstanding borrowings under the Credit Agreement of $549.9 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. For example, a one percent increase in the effective interest rate on our outstanding borrowings under the Credit Agreement as of December 31, 2021 would result in an annual increase in our interest expense of approximately $5.2 million. 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.
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, Cooper Machinery Services Gemini products and Arrow Engine Company for compressor frames and cylinders.
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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.
Additionally, if we are not able to pass along increases to our costs due to inflation on parts, fluids, labor and other aspects of our business, it may adversely affect our results of operations and cash flows.
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.
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
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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.
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 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 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
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in a reduction in our customers’ spending for our services. For example, our customers could seek to preserve capital by using lower cost providers, not renewing month-to-month contracts or determining not to enter into any new compression service contracts. A significant decline in commodity prices may cause certain of our customers to reconsider their near-term capital budgets, which may impact large-scale natural gas infrastructure and crude oil production activities. Reduced demand for our services could adversely affect our business, results of operations, financial condition and cash flows.
We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, suppliers or vendors could reduce our revenues, increase our expenses and otherwise have a negative impact on our ability to conduct our business, operating results, cash flows and ability to make distributions to our unitholders.
Weak economic conditions and widespread financial distress, including as a result of the COVID-19 pandemic, did and could again 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, 2021, one customer accounted for 14% of our trade account receivables, net balance. If this customer 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 by the COVID-19 pandemic and the governmental responses thereto continue.
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. 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 10 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
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•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 $304.4 million of identifiable intangible assets, net, as of December 31, 2021. 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.
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.
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, 2021, 2020 and 2019, we evaluated the future deployment of our idle fleet under current market conditions and determined to retire 26, 37 and 33 compressor units, respectively, for a total of approximately 11,000, 15,000 and 11,000 horsepower, respectively, that were previously used to provide compression services in our business. As a result, we recorded impairments of compression equipment of $5.1 million, $8.1 million and $5.9 million for the years ended December 31, 2021, 2020 and 2019, 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 labor markets are tight, such as 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.
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;
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•loss of customers;
•loss of key employees;
•maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002 as well as other regulatory compliance and corporate governance matters; and
•integrating new technology systems for financial reporting.
If any of these risks or other unanticipated liabilities or costs were to materialize, we may not realize the desired benefits from past and future acquisitions, resulting in a negative impact on our results of operations. For example, subsequent to the CDM Acquisition the attrition rate of specialized field technicians exceeded our projections and, as a result, we incurred unanticipated costs 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.
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 Energy Transfer in connection therewith, but there may be unknown and contingent liabilities of which we are currently unaware. Energy Transfer 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 Energy Transfer’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.
From time to time, we are subject to various claims, tax audits, litigation and other proceedings that could ultimately be resolved against us and require material future cash payments or charges, which could impair our financial condition or results of operations.
The size, nature and complexity of our business make us susceptible to various claims, tax audits, litigation and binding arbitration proceedings. We are currently, and may in the future become, subject to various claims, which, if not resolved within amounts we have accrued, if any, could have a material adverse effect on our financial position, results of operations or cash flows, including our ability to pay distributions. Similarly, any claims, even if fully indemnified or insured, could negatively impact our reputation among our customers and the public, and make it more difficult for us to compete effectively or obtain adequate insurance in the future. See Part I, Item 3 “Legal Proceedings” and Note 16 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for additional information regarding certain legal proceedings to which we are a party.
Risks Related to Governmental Legislation and Regulation
We and our customers are subject to substantial environmental regulation, and changes in these regulations could increase our and their costs or liabilities and result in decreased demand for our services.
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 – Governmental 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.
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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 – Governmental 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 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 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. In addition, in November 2021, the EPA proposed a rule to further reduce methane and VOC emissions from new and existing sources in the oil and gas sector.
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.
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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. In addition, federal or state governmental agencies could seek to pursue legislative, regulatory or executive initiatives that restrict GHG emissions. Other energy legislation and initiatives could include a carbon tax, methane fee or cap and trade program. Independent of Congress, and as discussed in detail in Item 1 “Business – Our Operations – Governmental Regulations”, the EPA has taken steps 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 impose restrictive requirements on new pipeline infrastructure or fossil-fuel export facilities. 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, methane fee 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.
Additionally, the SEC announced its intention to promulgate rules requiring climate disclosures. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.
Climate change may increase the frequency and severity of weather events that could result in severe personal injury, property damage and environmental damage, which could curtail our or our customers’ operations and otherwise materially adversely affect our cash flows.
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, including damages to our or our customers’ facilities and assets from powerful wind or rising waters. We may experience increased insurance costs, or difficulty obtaining adequate insurance coverage, for our assets in areas subject to more frequent severe weather. We may not be able to recoup these increased costs through the rates we charge our customers. Extreme weather events could cause damage to property or facilities that could exceed our insurance coverage and our business, financial condition and results of operations could be adversely affected.
Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for NGLs and natural gas is generally impacted by periods of colder weather and warmer weather, so any changes in climate could affect the market for those fuels, and thus demand for our services. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our services could be affected by increased temperature volatility.
A climate-related decrease in demand for crude oil and natural gas could negatively affect our business.
Supply and demand for crude oil and natural gas is dependent upon a variety of factors, many of which are beyond our control. These factors include, among others, the potential adoption of new government regulations, including those related to fuel conservation measures and climate change regulations, technological advances in fuel economy and energy generation devices. For example, legislative, regulatory or executive actions intended to reduce emissions of GHGs could increase the cost of consuming crude oil and natural gas, thereby potentially causing a reduction in the demand for such products. A broader
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transition to alternative fuels or energy sources, whether resulting from potential new government regulation, carbon taxes or consumer preferences could result in decreased demand for crude oil, natural gas and NGLs. Any decrease in demand for these products could consequently reduce demand for our services and could have a negative effect on our business.
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 as well as negatively affect the cost of, and terms for, financing to fund capital expenditures or other aspects of our business.
Increased attention to ESG matters and conservation measures may adversely impact our business
Increasing attention to, and societal expectations on companies to address climate change and other environmental and social impacts, investor and societal expectations regarding voluntary environmental, social and governance (“ESG”) disclosures, and consumer demand for alternative forms of energy may result in increased costs, reduced demand for fossil fuels and consequently demand for our services, reduced profits, increased risk of investigations and litigation, and negative impacts on the value of our assets and access to capital. Increasing attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us or our customers. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our access to and costs of capital. Additionally, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations.
Such ESG matters may also impact our customers or suppliers, which may adversely impact our business, financial condition, or results of operations.
Increased regulation of hydraulic fracturing could result in reductions of, or delays in, natural gas production by our customers, which could adversely impact our revenue.
A significant portion of our customers’ natural gas production is developed from unconventional sources that require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the rock formation to stimulate gas production. 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, from time to time, there have been various proposals to regulate hydraulic fracturing at the federal level. 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,
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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”). Energy Transfer 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, Energy Transfer 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 Energy Transfer 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.
Energy Transfer 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 Energy Transfer, 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.
Energy Transfer 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 Energy Transfer. 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 Energy Transfer to pursue a business strategy that favors us;
•Energy Transfer 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,
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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.
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;
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•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.
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 Energy Transfer 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
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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.
Energy Transfer 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, 2021, Energy Transfer beneficially owns an aggregate of 46,056,228 common units in us. We have granted certain registration rights to Energy Transfer 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.
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, 2021, the General Partner and its affiliates (including Energy Transfer), 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
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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 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
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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 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.
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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.
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. Our U.S. Federal income tax returns for years 2019 and 2020 are currently under examination by the IRS. To the extent possible under applicable rules, the General Partner may pay such taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, elect to issue a revised Schedule K-1 to each unitholder and former unitholder with respect to an audited and adjusted return. No assurances can be made 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 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.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If our unitholders sell common units, they will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.
A substantial portion of the amount realized from a unitholder’s sale of our units, whether or not representing gain, may be taxed as ordinary income to such unitholder due to potential recapture items, including depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than such unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells its units, such unitholder may recognize ordinary income from our allocations of income and gain to such unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.
Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
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.
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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. Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor. Treasury regulations and recent Treasury guidance further provide that withholding on a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs on or prior to December 31, 2022, and after that date, if effected through a broker, the obligation to withhold is imposed on the transferor’s broker. 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 Date”), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate (i) certain deductions for depreciation of capital additions, (ii) gain or loss realized on a sale or other disposition of our assets, and (iii) in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units. If so, he would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned common units. In that case, the unitholder may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.
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We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our common units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.
A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain recognized from our unitholders’ sale of common units, have a negative impact on the value of the common units, or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
As a result of investing in our common units, you will likely become subject to state and local taxes and income tax return filing requirements in jurisdictions where we operate or own or acquire properties.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with state and local filing requirements.
We currently conduct business and control assets in several states, many of which currently impose a personal income tax on individuals. Many of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states or foreign jurisdictions that impose an income tax. It is our unitholders’ 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 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.
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
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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.
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, 2021, our headquarters consisted of 19,225 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 10, 2022, we had 97,377,355 common units outstanding. Energy Transfer owns 100% of the membership interests in the General Partner and, as of February 10, 2022, beneficially owns approximately 47% of our outstanding common units.
As of February 10, 2022, 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 holder, into common units in accordance with the terms of our Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”) as follows: one third on or after April 2, 2021, two thirds on or after April 2, 2022, and 100% are convertible 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, subject to certain minimum redemption threshold amounts, for a redemption price set forth in the Partnership Agreement. On or after April 2, 2028, each Preferred Unitholder will have the right to require us to redeem all or a portion of their Preferred Units, subject to certain minimum redemption threshold amounts, for a redemption price set forth in the Partnership Agreement, 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 10, 2022, based on information received from the transfer agent of the common units, we had 62 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 10 – Preferred Units and – Note 11 – 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.
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Equity Compensation Plan
For disclosures regarding securities authorized for issuance under equity compensation plans, see Part III, Item 12 “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters”.
ITEM 6. [RESERVED]
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, 2020 compared to the year ended December 31, 2019 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, 2020 with the SEC on February 16, 2021.
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, 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 collectively increase over the long term. Furthermore, the changes in production volumes and pressures of shale plays over time require a wider range of compression 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.
Recent Developments
Seventh Amended and Restated Credit Agreement
On December 8, 2021, we amended and restated our existing credit agreement by entering into the Credit Agreement. The Credit Agreement matures on December 8, 2026, except that if any portion of the Senior Notes 2026 are outstanding on December 31, 2025, the Credit Agreement will mature on December 31, 2025.
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 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. Relative stability in commodity prices over much of the past
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decade encouraged investment in domestic exploration and production 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.
Following this period of general stability and moderate growth for both the midstream energy industry and the broader energy industry, the events of 2020—including the COVID-19 pandemic and the crude oil price wars— impacted participants across the energy industry, including us and our customers. The significant price volatility in both crude oil and natural gas had an impact on energy companies’ financial performance, and combined with reduced and uncertain future demand, created a market environment that saw numerous corporate restructurings in the energy industry as companies worked to adjust to a vastly different marketplace than prior to Spring of 2020. This included a focus on rebuilding balance sheet strength, driven in part by meaningful reductions in capital investment.
During 2021, the general energy industry in large part recovered from the low commodity prices and reduced activity of 2020, driven by continued, and growing, demand for both crude oil and natural gas as countries across the world emerged from COVID-19 lock-downs and economies began to recover. As the demand for hydrocarbons generally follows economic growth, 2021 saw strong demand growth coupled with constrained supply, due in part to the effects of reduced capital investment across the energy sector. This has driven commodity prices to meaningfully higher levels, and has helped the energy industry further recover from the lows of 2020. Members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC and other allied producing countries, “OPEC+”) have increased production moderately, but continue to be focused on supply and demand dynamics. In addition, some members of OPEC+ may not be able to increase production to the level of their agreed-to supply amounts.
While the ongoing COVID-19 pandemic continues to create economic uncertainty, many economies and industries that directly or indirectly use crude oil and natural gas have begun to recover, resulting in increased demand. According to the EIA, global consumption of petroleum and liquids fuels increased over 5% in 2021 and the EIA estimates that U.S. gross domestic product increased 5.7% in 2021, both illustrating the continued demand recovery in the U.S. as well as globally.
While overall, economies are working to return to pre-pandemic levels, since the Spring of 2020, the domestic oil and gas industry has been characterized by robust capital discipline, even in the face of the increasing commodity prices witnessed during 2021. Greatly moderated levels of production, exploration and capital investment activity in the upstream sector has trickled down through the midstream sector, and during 2021, we experienced more reduced demand for our compression services than we had anticipated, given the constructive broader commodity environment and increasing demand for crude oil and natural gas. Although 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. And given the level of capital discipline exhibited during 2021, our customers saw generally lower levels of new drilling activity, and instead producers sought alternative paths to maintaining production levels to meet demand, including by working off inventory of drilled-but-uncompleted wells as well as using smaller booster compression units in lieu of drilling new wells.
The EIA’s January 2022 Short-Term Energy Outlook (“EIA Outlook”) estimates that annual U.S. crude oil production averaged 11.2 million barrels per day (“bpd”) in 2021, down just 0.1 million bpd from 2020, primarily due to well freeze-offs during February 2021 and well shut-ins during Hurricane Ida in August and September 2021. In 2022 and 2023, the EIA Outlook expects U.S. crude oil production growth to resume, with 11.8 million bpd in 2022 and 12.4 million bpd in 2023, which would reflect the highest annual average on record, surpassing 2019’s level of production. The expected increase in production is in part due to increased crude oil rig activity, which was up 80% over the past year, according to Baker Hughes, driven by higher crude oil prices, which averaged above $75 per barrel in the fourth quarter of 2021, compared to $58 per barrel in the first quarter of 2021. We expect this increased activity in crude oil and natural gas production throughout 2021 to translate into increased demand for our compression services, particularly in associated gas basins like the Permian Basin, Delaware Basin and Eagle Ford Shale.
While metrics such as monthly crude oil production, rig counts and prices would suggest a positive environment for natural gas producers, variables including 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.
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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. Domestic power generation and industrial uses such as chemical plants have benefited from this low-price environment. These low prices, combined with a general move away from coal-fired power plants due to emissions concerns, has resulted in power generation becoming, and remaining, the largest use of natural gas in the U.S. This low natural gas price environment helped create relatively resilient baseload demand for natural gas. Also, the development of long-term liquefied natural gas (“LNG”) export infrastructure has continued to occur, driven in part by attractive global prices, and according to the EIA, estimates are that the U.S. set a record for LNG exports during December 2021. The EIA Outlook expects U.S. natural gas consumption to remain consistent in 2022 and 2023, reflecting 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, which decreases are expected to be partially offset by other uses, including increased LNG exports as well as increased pipeline exports to Mexico. While natural gas prices were volatile in 2021, during the second half of the year they were relatively higher compared with recent years, which the EIA Outlook expects to last into 2022 and 2023. However, we expect the baseload natural gas demand previously described will continue to support long-term domestic natural gas production.
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 natural gas market through 2022 and beyond.
In summary, the broader outlook for commodity prices improved considerably during 2021. While continuing uncertainty with respect to demand may have a varying impact on our business and the ultimate timing of a recovery in utilization metrics, we believe the outlook for the natural gas industry in the U.S. is positive. The overall outlook for our compression services will depend, in part, on the strength and duration of the ongoing recovery in the commodity markets. While we anticipate that the combination of commodity prices and demand may likely have a positive 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 our services, contract term and other factors.
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 | ||||||||||||||||
| 2021 | 2020 | Change | |||||||||||||||
| Fleet horsepower (at period end) (1) | 3,689,018 | 3,726,181 | (1.0 | %) | |||||||||||||
| Total available horsepower (at period end) (2) | 3,689,018 | 3,726,181 | (1.0 | %) | |||||||||||||
| Revenue generating horsepower (at period end) (3) | 2,964,206 | 2,997,262 | (1.1 | %) | |||||||||||||
| Average revenue generating horsepower (4) | 2,951,013 | 3,139,732 | (6.0 | %) | |||||||||||||
| Average revenue per revenue generating horsepower per month (5) | $ | 16.60 | $ | 16.71 | (0.7 | %) | |||||||||||
| Revenue generating compression units (at period end) | 3,942 | 3,968 | (0.7 | %) | |||||||||||||
| Average horsepower per revenue generating compression unit (6) | 750 | 746 | 0.5 | % | |||||||||||||
| Horsepower utilization (7): | |||||||||||||||||
| At period end | 82.7 | % | 82.8 | % | (0.1 | %) | |||||||||||
| Average for the period (8) | 82.7 | % | 86.8 | % | (4.7 | %) | |||||||||||
(1)Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order). As of December 31, 2021, we had 25,000 large horsepower on order for delivery during 2022. Subsequent to December 31, 2021, we ordered an additional 50,000 large horsepower for delivery during 2022.
(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% at December 31, 2021 and 2020.
(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 79.8% and 84.5% for the years ended December 31, 2021 and 2020, respectively.
The 1.0% decrease in fleet and total available horsepower as of December 31, 2021 compared to December 31, 2020 was primarily due to the exercise of a purchase option on certain compression units by a customer during the current period as well as compression units impaired since the previous period. The exercise of this purchase option also drove a 1.1% decrease in revenue generating horsepower and a 0.7% decrease in revenue generating compression units as of December 31, 2021 compared to December 31, 2020.
The 6.0% decrease in average revenue generating horsepower for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to returns of compression units from our customers. We believe the returns of compression units from our customers were primarily due to continued optimization of existing compression service requirements by those customers.
The 0.7% decrease in average revenue per revenue generating horsepower per month for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to reduced pricing in our small horsepower fleet. The 0.5% increase in average horsepower per revenue generating compression unit was primarily due to a greater number of compression unit returns related to our small horsepower fleet than related to our large horsepower fleet.
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Horsepower utilization was consistent period over period at 82.7% as of December 31, 2021 compared to 82.8% as of December 31, 2020. Average horsepower utilization decreased to 82.7% during the year ended December 31, 2021 compared to 86.8% during the year ended December 31, 2020. The 4.7% decrease in average horsepower utilization for the year ended December 31, 2021 is primarily due to an increase in our average idle horsepower from compression units returned to us, which we believe is primarily due to continued optimization of existing compression service requirements by our customers.
Horsepower utilization based on revenue generating horsepower and fleet horsepower was consistent period over period at 80.4% as of December 31, 2021 and 2020. Average horsepower utilization based on revenue generating horsepower and fleet horsepower decreased to 79.8% for the year ended December 31, 2021 compared to 84.5% for the year ended December 31, 2020. The 5.6% decrease in average horsepower utilization based on revenue generating horsepower and fleet horsepower for the year ended December 31, 2021 is primarily due to an increase in our average idle horsepower from compression units returned to us, which we believe is primarily due to continued optimization of existing compression service requirements by our customers.
Financial Results of Operations
Year ended December 31, 2021 compared to the year ended December 31, 2020
The following table summarizes our results of operations for the periods presented (dollars in thousands):
| Year Ended December 31, | Percent | ||||||||||||||||
| 2021 | 2020 | Change | |||||||||||||||
| Revenues: | |||||||||||||||||
| Contract operations | $ | 609,450 | $ | 644,194 | (5.4) | % | |||||||||||
| Parts and service | 11,228 | 11,117 | 1.0 | % | |||||||||||||
| Related party | 11,967 | 12,372 | (3.3) | % | |||||||||||||
| Total revenues | 632,645 | 667,683 | (5.2) | % | |||||||||||||
| Costs and expenses: | |||||||||||||||||
| Cost of operations, exclusive of depreciation and amortization | 194,389 | 205,939 | (5.6) | % | |||||||||||||
| Depreciation and amortization | 238,769 | 238,968 | (0.1) | % | |||||||||||||
| Selling, general and administrative | 56,082 | 59,981 | (6.5) | % | |||||||||||||
| Loss (gain) on disposition of assets | (2,588) | 146 | * | ||||||||||||||
| Impairment of compression equipment | 5,121 | 8,090 | (36.7) | % | |||||||||||||
| Impairment of goodwill | — | 619,411 | * | ||||||||||||||
| Total costs and expenses | 491,773 | 1,132,535 | * | ||||||||||||||
| Operating income (loss) | 140,872 | (464,852) | * | ||||||||||||||
| Other income (expense): | |||||||||||||||||
| Interest expense, net | (129,826) | (128,633) | 0.9 | % | |||||||||||||
| Other | 107 | 86 | 24.4 | % | |||||||||||||
| Total other expense | (129,719) | (128,547) | 0.9 | % | |||||||||||||
| Net income (loss) before income tax expense | 11,153 | (593,399) | * | ||||||||||||||
| Income tax expense | 874 | 1,333 | (34.4) | % | |||||||||||||
| Net income (loss) | $ | 10,279 | $ | (594,732) | * | ||||||||||||
*Not meaningful.
Contract operations revenue. The $34.7 million decrease in contract operations revenue for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to returns of compression units from our customers, which we believe is primarily due to continued optimization of existing compression service requirements by those customers which resulted in a 6.0% decrease in average revenue generating horsepower and a 0.7% decrease in average revenue per revenue generating horsepower per month which decreased to $16.60 for the year ended December 31, 2021 compared to $16.71 for the year ended December 31, 2020. These decreases were partially offset by compression units moving from standby to full billing rate since the previous period.
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Our contract operations revenue was not 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. Parts and service revenue was consistent period over period and is related to 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 Energy Transfer and was consistent period over period.
Cost of operations, exclusive of depreciation and amortization. The $11.6 million decrease in cost of operations for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to (i) an $8.0 million decrease in direct labor expenses, (ii) a $5.2 million decrease in non-income taxes, primarily due to sales tax refunds received in the current period related to prior periods, (iii) a $2.7 million decrease in direct expenses, driven by fluids and parts, and (iv) a $0.6 million decrease in training and other indirect expenses, partially offset by (v) a $3.9 million increase in outside maintenance expenses due to greater use of third-party labor during the current period and (vi) a $1.3 million increase in expenses related to our vehicle fleet, primarily due to increased fuel costs.
The decreases in direct labor, fluids and parts, training and other indirect expenses were primarily driven by the decrease in average revenue generating horsepower and reduced headcount during the current period.
Depreciation and amortization expense. The $0.2 million decrease in depreciation and amortization expense for the year ended December 31, 2021 compared to the year ended December 31, 2020 was due to a decrease in non-compression unit depreciation, driven by lower vehicle depreciation related to a reduction in our vehicle fleet in the current period, partially offset by increased compression unit depreciation related to compression unit overhauls and new compression units placed in service throughout 2020 to meet then existing demand by customers.
Selling, general and administrative expense. The $3.9 million decrease in selling, general and administrative expense for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to (i) a $6.4 million decrease in the provision for expected credit losses, (ii) a $2.4 million decrease in employee-related expenses, and (iii) a $1.9 million decrease in severance charges primarily due to the departure of one of our executives during the prior period, partially offset by (iv) a $7.1 million increase in unit-based compensation expense.
The change to the provision for expected credit losses is related to improved market conditions for customers due to the recovery in commodity prices in the current period as compared to the prior period, where we made a provision for the potential negative impact to our customers of low commodity prices driven by decreased demand due to the COVID-19 pandemic and the global oversupply of crude oil during that time. The decrease in employee-related expenses is primarily due to reduced headcount during the current period and cost saving measures. The increase in unit-based compensation expense is primarily due to the overall change in our unit price as of December 31, 2021, and the related mark-to-market change to our unit-based compensation liability.
Loss (gain) on disposition of assets. The $2.6 million gain on disposition of assets for the year ended December 31, 2021 was primarily due to the exercise of a purchase option on certain compression units by a customer.
Impairment of compression equipment. The $5.1 million and $8.1 million impairments of compression equipment during the years ended December 31, 2021 and 2020, respectively, were primarily the result of our evaluations of the future deployment of our idle fleet under current market conditions. The primary causes for these impairments were: (i) units were not considered marketable in the foreseeable future, (ii) units were subject to excessive maintenance costs or (iii) units were unlikely to be accepted by customers due to certain performance characteristics of the unit, such as the inability to meet current quoting criteria without excessive retrofitting costs. These compression units were written down to their respective estimated salvage values, if any.
As a result of our evaluations during the years ended December 31, 2021 and 2020, we determined to retire 26 and 37 compression units, respectively, with a total of approximately 11,000 and 15,000 horsepower, respectively, that had been previously used to provide compression services in our business.
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Impairment of goodwill. During the first quarter of 2020 certain potential impairment indicators were identified, specifically (i) the decline in the market price of our common units, (ii) the decline in global commodity prices, and (iii) the COVID-19 pandemic; which together indicated the fair value of the reporting unit was less than its carrying amount as of March 31, 2020. We performed a quantitative goodwill impairment test as of March 31, 2020 and determined fair value using a weighted combination of the income approach and the market approach and, as a result, recognized a goodwill impairment of $619.4 million for the year ended December 31, 2020.
Interest expense, net. The $1.2 million increase in interest expense, net for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to (i) increased borrowings under our credit agreement and (ii) increased amortization of debt issuance costs related to the amendment and restatement of our credit agreement in the current period, partially offset by (iii) lower weighted average interest rates under our credit agreement.
Average outstanding borrowings under our credit agreement were $491.5 million for the year ended December 31, 2021 compared to $455.7 million for the year ended December 31, 2020. The weighted average interest rate applicable to borrowings under our credit agreement was 2.98% for the year ended December 31, 2021 compared to 3.27% for the year ended December 31, 2020.
Income tax expense. The $0.5 million decrease in income tax expense for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily related to deferred taxes associated with the Texas Margin Tax.
Other Financial Data
The following table summarizes other financial data for the periods presented (dollars in thousands):
| Year Ended December 31, | Percent | |||||||||||||||||||
| Other Financial Data: (1) | 2021 | 2020 | Change | |||||||||||||||||
| Gross margin | $ | 199,487 | $ | 222,776 | (10.5) | % | ||||||||||||||
Adjusted gross margin | $ | 438,256 | $ | 461,744 | (5.1) | % | ||||||||||||||
Adjusted gross margin percentage (2) | 69.3 | % | 69.2 | % | 0.1 | % | ||||||||||||||
Adjusted EBITDA | $ | 398,380 | $ | 413,898 | (3.7) | % | ||||||||||||||
Adjusted EBITDA percentage (2) | 63.0 | % | 62.0 | % | 1.6 | % | ||||||||||||||
DCF | $ | 209,128 | $ | 220,766 | (5.3) | % | ||||||||||||||
DCF Coverage Ratio | 1.03 | x | 1.09 | x | (5.5) | % | ||||||||||||||
| Cash Coverage Ratio | 1.03 | x | 1.10 | x | (6.4) | % | ||||||||||||||
(1)Adjusted gross margin, Adjusted EBITDA, DCF, DCF Coverage Ratio and Cash Coverage Ratio are all non-GAAP financial measures. Definitions of each measure, as well as reconciliations of each measure to its most directly comparable financial measure(s) calculated and presented in accordance with GAAP, can be found below under the caption “Non-GAAP Financial Measures”.
(2)Adjusted gross margin percentage and Adjusted EBITDA percentage are calculated as a percentage of revenue.
Gross margin. The $23.3 million decrease in gross margin for the year ended December 31, 2021 compared to the year ended December 31, 2020 was due to (i) a $35.0 million decrease in revenues, offset by (ii) an $11.6 million decrease in cost of operations, exclusive of depreciation and amortization and (iii) a $0.2 million decrease in depreciation and amortization.
Adjusted gross margin. The $23.5 million decrease in Adjusted gross margin for the year ended December 31, 2021 compared to the year ended December 31, 2020 was due to a $35.0 million decrease in revenues, partially offset by an $11.6 million decrease in cost of operations, exclusive of depreciation and amortization.
Adjusted EBITDA. The $15.5 million decrease in Adjusted EBITDA for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to a $23.5 million decrease in Adjusted gross margin, partially offset by a $9.0 million decrease in selling, general and administrative expenses, excluding unit-based compensation expense, severance charges and transaction expenses.
DCF. The $11.6 million decrease in DCF during the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to (i) a $23.5 million decrease in Adjusted gross margin, partially offset by (ii) a $9.0 million decrease in selling, general and administrative expenses, excluding unit-based compensation expense, severance charges and transaction expenses and (iii) a $3.8 million decrease in maintenance capital expenditures.
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Coverage Ratios. The decreases in DCF Coverage Ratio and Cash Coverage Ratio for the year ended December 31, 2021 compared to the year ended December 31, 2020 were primarily due to the decrease in DCF.
Liquidity and Capital Resources
Overview
We operate in a capital-intensive industry, and our primary liquidity needs are to finance the purchase of additional compression units and make other capital expenditures, service our debt, fund working capital, and pay distributions. Our principal sources of liquidity include cash generated by operating activities, borrowings under the Credit Agreement and issuances of debt and equity securities, including common units under the DRIP.
We typically utilize cash generated by operating activities and, where necessary, borrowings under the Credit Agreement to service our debt, fund working capital, fund our estimated expansion capital expenditures, fund our maintenance capital expenditures and pay distributions to our unitholders. Covenants in the Credit Agreement and other debt instruments require that we maintain certain leverage ratios, and if we predict that we may violate those covenants in the future we could: (i) delay discretionary capital spending and reduce operating expenses; (ii) request an amendment to the Credit Agreement; (iii) reduce or suspend distributions to our unitholders; or (iv) issue equity securities, including under the DRIP.
On December 8, 2021, the Partnership amended and restated its existing credit agreement by entering into the Credit Agreement. Please see “Revolving Credit Facility” below for additional information regarding the Credit Agreement.
Because we distribute all of our available cash, which excludes prudent operating reserves, we expect to fund any future expansion capital expenditures or acquisitions primarily with capital from external financing sources, such as borrowings under the Credit Agreement and issuances of debt and equity securities, including under the DRIP.
We are not aware of any regulatory changes or environmental liabilities that we currently expect to have a material impact on our current or future operations. Please see “Capital Expenditures” below.
Capital Expenditures
The compression services business is capital intensive, requiring significant investment to maintain, expand and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate that our capital requirements will continue to consist primarily of, the following:
•maintenance capital expenditures, which are capital expenditures made to maintain the operating capacity of our assets and extend their useful lives, to replace partially or fully depreciated assets, or other capital expenditures that are incurred in maintaining our existing business and related operating income; and
•expansion capital expenditures, which are capital expenditures made to expand the operating capacity or operating income capacity of assets, including by acquisition of compression units or through modification of existing compression units to increase their capacity, or to replace certain partially or fully depreciated assets that were not currently generating operating income.
We classify capital expenditures as maintenance or expansion on an individual asset basis. Over the long term, we expect that our maintenance capital expenditure requirements will continue to increase as the overall size and age of our fleet increases. Our aggregate maintenance capital expenditures for the years ended December 31, 2021 and 2020 were $19.5 million and $23.3 million, respectively. We currently plan to spend approximately $23.0 million in maintenance capital expenditures during 2022, including parts consumed from inventory.
Without giving effect to any equipment we may acquire pursuant to any future acquisitions, we currently have budgeted between $110.0 million and $120.0 million in expansion capital expenditures during 2022. Our expansion capital expenditures for the years ended December 31, 2021 and 2020 were $40.2 million and $95.6 million, respectively.
As of December 31, 2021, we had binding commitments to purchase $19.3 million of additional compression units and serialized parts, all of which is expected to be settled within the next twelve months. Subsequent to December 31, 2021, we ordered an additional 50,000 horsepower for delivery during 2022 which will cost an additional $43.7 million, which is also expected to be settled within the next twelve months.
Other Commitments
As of December 31, 2021, other commitments include operating and finance lease payments totaling $27.4 million, of which we expect to make payments of $4.8 million to be settled in the next twelve months. For a more detailed description of
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our lease obligations, please refer to Note 7 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
Cash Flows
The following table summarizes our sources and uses of cash for the years ended December 31, 2021 and 2020 (in thousands):
| Year Ended December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
| Net cash provided by operating activities | $ | 265,425 | $ | 293,198 | |||||||
| Net cash used in investing activities | (39,188) | (105,099) | |||||||||
| Net cash used in financing activities | (226,239) | (188,107) | |||||||||
Net cash provided by operating activities. The $27.8 million decrease in net cash provided by operating activities for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to a $18.8 million decrease in net income, as adjusted for non-cash items, and changes in other working capital.
Net cash used in investing activities. The $65.9 million decrease in net cash used in investing activities for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to a $63.9 million decrease in capital expenditures for purchases of new compression units, related equipment and reconfiguration costs and a $1.8 million increase in proceeds from disposition of property and equipment.
Net cash used in financing activities. The $38.1 million increase in net cash used in financing activities for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to (i) a $28.6 million decrease in net borrowings under our credit agreement, (ii) a $6.1 million increase in financing costs, due primarily to costs incurred related to the amendment and restatement of our credit agreement in the current period, (iii) a $2.0 million increase in cash paid related to the net settlement of unit-based awards and (iv) a $1.7 million increase in cash distributions paid on common units solely due to increased unit count.
Revolving Credit Facility
As of December 31, 2021, we were in compliance with all of our covenants under the Credit Agreement. As of December 31, 2021, we had outstanding borrowings under the Credit Agreement of $516.3 million, $1.1 billion of borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of $261.9 million.
As of February 10, 2022, we had outstanding borrowings under the Credit Agreement of $549.9 million.
On December 8, 2021, the Partnership amended and restated its existing credit agreement by entering into the Credit Agreement. The Credit Agreement matures on December 8, 2026, except that if any portion of the Senior Notes 2026 are outstanding on December 31, 2025, the Credit Agreement will mature on December 31, 2025.
The Credit Agreement provides for an asset-based revolving credit facility to be made available to the Partnership in an aggregate amount of $1.6 billion. The Partnership’s obligations under the Credit Agreement are guaranteed by the Guarantors, which currently consists of all of the Partnership’s existing subsidiaries. In addition, the Partnership’s obligations under the Credit Agreement are secured by: (i) substantially all of the Partnership’s assets and substantially all of the assets of the Guarantors, excluding real property and other customary exclusions; and (ii) all of the equity interests of the Partnership’s U.S. restricted subsidiaries (subject to customary exceptions).
Borrowings under the Credit Agreement bear interest at a per annum interest rate equal to, at the Partnership’s option, either the Alternate Base Rate or SOFR plus the applicable margin. “Alternate Base Rate” means the greatest of (i) the prime rate, (ii) the applicable federal funds effective rate plus 0.50% and (iii) one-month SOFR rate plus 1.00%. The applicable margin for borrowings varies (a) in the case of SOFR loans, from 2.00% to 2.75% per annum and (b) in the case of Base Rate loans, from 1.00% to 1.75% per annum, and are determined based on a total leverage ratio pricing grid. In addition, the Borrower is required to pay commitment fees based on the daily unused amount of the Credit Agreement in an amount per annum equal to 0.375%. Amounts borrowed and repaid under the Credit Agreement may be re-borrowed, subject to borrowing base availability.
The Credit Agreement contains various covenants with which the Partnership and its restricted subsidiaries must comply, including, but not limited to, limitations on the incurrence of indebtedness, investments, liens on assets, repurchasing equity and making distributions, transactions with affiliates, mergers, consolidations, dispositions of assets and other provisions customary
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in similar types of agreements. The Partnership must also maintain, on a consolidated basis, as of the last day of each fiscal quarter a Total Leverage Ratio (as defined in the Credit Agreement) of not greater than 5.75 to 1.00 through the second fiscal quarter of 2022; 5.50 to 1.00 from the third fiscal quarter of 2022 through the third fiscal quarter of 2023; and 5.25 to 1.00 thereafter (except that the Partnership may increase the applicable Total Leverage Ratio by 0.25 for any fiscal quarter during which a Specified Acquisition (as defined in the Credit Agreement) occurs and the following two fiscal quarters, but in no event shall the maximum Total Leverage Ratio exceed 5.50 to 1.00 for any fiscal quarter as a result of such increase), an Interest Coverage Ratio (as defined in the Credit Agreement) of not less than 2.50 to 1.00 and a Secured Leverage Ratio (as defined in the Credit Agreement) of not greater than 3.00 to 1.00 or less than 0.00 to 1.00. The Credit Agreement also contains various customary representations and warranties, affirmative covenants and events of default.
We expect to remain in compliance with our covenants under the Credit Agreement throughout 2022. If our current cash flow projections prove to be inaccurate, we expect to be able to remain in compliance with such financial covenants by taking one or more of the following actions: issue debt and equity securities in conjunction with the acquisition of another business; issue equity in a public or private offering; request a modification of our covenants from our bank group; reduce distributions from our current distribution rate or obtain an equity infusion pursuant to the terms of the Credit Agreement.
For a more detailed description of the Credit Agreement including the covenants and restrictions contained therein, please refer to Note 9 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
Senior Notes
As of December 31, 2021, we had $725.0 million and $750.0 million aggregate principal amount outstanding on our Senior Notes 2026 and Senior Notes 2027, respectively.
The Senior Notes 2026 are due on April 1, 2026 and accrue interest at the rate of 6.875% per year. Interest on the Senior Notes 2026 is payable semi-annually in arrears on each of April 1 and October 1.
The Senior Notes 2027 are due on September 1, 2027 and accrue interest at the rate of 6.875% per year. Interest on the Senior Notes 2027 is payable semi-annually in arrears on each of March 1 and September 1.
For more detailed descriptions of the Senior Notes 2026 and Senior Notes 2027, please refer to Note 9 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.
DRIP
During the years ended December 31, 2021 and 2020, distributions of $1.8 million and $1.9 million, respectively, were reinvested under the DRIP resulting in the issuance of 118,399 and 188,695 common units, respectively.
Such distributions are treated as non-cash transactions in the accompanying Consolidated Statements of Cash Flows included in Part II, Item 8 “Financial Statements and Supplementary Data” of this report.
See Note 11 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for more information regarding the DRIP.
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.
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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, | |||||||||||
| 2021 | 2020 | ||||||||||
| Total revenues | $ | 632,645 | $ | 667,683 | |||||||
| Cost of operations, exclusive of depreciation and amortization | (194,389) | (205,939) | |||||||||
| Depreciation and amortization | (238,769) | (238,968) | |||||||||
| Gross margin | $ | 199,487 | $ | 222,776 | |||||||
| Depreciation and amortization | 238,769 | 238,968 | |||||||||
| Adjusted gross margin | $ | 438,256 | $ | 461,744 | |||||||
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 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.
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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, | |||||||||||
| 2021 | 2020 | ||||||||||
| Net income (loss) | $ | 10,279 | $ | (594,732) | |||||||
| Interest expense, net | 129,826 | 128,633 | |||||||||
| Depreciation and amortization | 238,769 | 238,968 | |||||||||
| Income tax expense | 874 | 1,333 | |||||||||
| EBITDA | $ | 379,748 | $ | (225,798) | |||||||
| Interest income on capital lease | 48 | 383 | |||||||||
| Unit-based compensation expense (1) | 15,523 | 8,400 | |||||||||
| Transaction expenses (2) | 34 | 136 | |||||||||
| Severance charges | 494 | 3,130 | |||||||||
| Loss (gain) on disposition of assets | (2,588) | 146 | |||||||||
| Impairment of compression equipment (3) | 5,121 | 8,090 | |||||||||
| Impairment of goodwill (4) | — | 619,411 | |||||||||
| Adjusted EBITDA | $ | 398,380 | $ | 413,898 | |||||||
| Interest expense, net | (129,826) | (128,633) | |||||||||
| Non-cash interest expense | 9,765 | 8,402 | |||||||||
| Income tax expense | (874) | (1,333) | |||||||||
| Interest income on capital lease | (48) | (383) | |||||||||
| Transaction expenses | (34) | (136) | |||||||||
| Severance charges | (494) | (3,130) | |||||||||
| Other | (2,742) | 4,230 | |||||||||
| Changes in operating assets and liabilities | (8,702) | 283 | |||||||||
| Net cash provided by operating activities | $ | 265,425 | $ | 293,198 | |||||||
________________________
(1)For the years ended December 31, 2021 and 2020, unit-based compensation expense included $4.2 million and $3.2 million of cash payments related to quarterly payments of DERs on outstanding phantom unit awards, respectively, and $0.3 million and $0.5 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 on our goodwill impairment recorded for the year ended December 31, 2020, see below under the caption “Critical Accounting 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, 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.
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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, | |||||||||||
| 2021 | 2020 | ||||||||||
| Net income (loss) | $ | 10,279 | $ | (594,732) | |||||||
| Non-cash interest expense | 9,765 | 8,402 | |||||||||
| Depreciation and amortization | 238,769 | 238,968 | |||||||||
| Non-cash income tax expense (benefit) | (42) | 530 | |||||||||
| Unit-based compensation expense (1) | 15,523 | 8,400 | |||||||||
| Transaction expenses (2) | 34 | 136 | |||||||||
| Severance charges | 494 | 3,130 | |||||||||
| Loss (gain) on disposition of assets | (2,588) | 146 | |||||||||
| Impairment of compression equipment (3) | 5,121 | 8,090 | |||||||||
| Impairment of goodwill (4) | — | 619,411 | |||||||||
| Distributions on Preferred Units | (48,750) | (48,750) | |||||||||
| Proceeds from insurance recovery | — | 336 | |||||||||
| Maintenance capital expenditures (5) | (19,477) | (23,301) | |||||||||
| DCF | $ | 209,128 | $ | 220,766 | |||||||
| Maintenance capital expenditures | 19,477 | 23,301 | |||||||||
| Transaction expenses | (34) | (136) | |||||||||
| Severance charges | (494) | (3,130) | |||||||||
| Distributions on Preferred Units | 48,750 | 48,750 | |||||||||
| Other | (2,700) | 3,364 | |||||||||
| Changes in operating assets and liabilities | (8,702) | 283 | |||||||||
| Net cash provided by operating activities | $ | 265,425 | $ | 293,198 | |||||||
________________________
(1)For the years ended December 31, 2021 and 2020, unit-based compensation expense included $4.2 million and $3.2 million of cash payments related to quarterly payments of DERs on outstanding phantom unit awards, respectively, and $0.3 million and $0.5 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 on our goodwill impairment recorded for the year ended December 31, 2020, see below under the caption “Critical Accounting 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, | |||||||||||
| 2021 | 2020 | ||||||||||
| DCF | $ | 209,128 | $ | 220,766 | |||||||
| Distributions for DCF Coverage Ratio (1) | $ | 203,978 | $ | 203,409 | |||||||
| Distributions reinvested in the DRIP (2) | $ | 1,828 | $ | 2,064 | |||||||
| Distributions for Cash Coverage Ratio (3) | $ | 202,150 | $ | 201,345 | |||||||
| DCF Coverage Ratio | 1.03 | x | 1.09 | x | |||||||
| Cash Coverage Ratio | 1.03 | x | 1.10 | 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.
Critical Accounting Estimates
The discussion and analysis of our financial condition and results of operations is based upon our financial statements. These financial statements were prepared in conformity with GAAP. As such, we are required to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. We base our estimates on historical experience, available information and various other assumptions we believe to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates; however, actual results may differ from these estimates under different assumptions or conditions. The accounting estimates that we believe require management’s most difficult, subjective or complex judgments and are the most critical to its reporting of results of operations and financial position are as follows:
Business Combinations and Goodwill
Goodwill acquired in connection with business combinations represents the excess of consideration over the fair value of net assets acquired. Certain assumptions and estimates are employed in determining the fair value of assets acquired and liabilities assumed. Goodwill is not amortized, but is reviewed for impairment annually based on the carrying values as of October 1, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered.
Goodwill – Impairment Assessments
We evaluate goodwill for impairment annually on October 1 and whenever events or changes indicate that it is more likely than not that the fair value of our single business reporting unit could be less than its carrying value (including goodwill).
We estimate the fair value of our reporting unit based on a number of factors, including the potential value we would receive if we sold the reporting unit, enterprise value, discount rates and projected cash flows. Estimating projected cash flows requires us to make certain assumptions as it relates to future operating performance. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. Due to the imprecise nature of these projections and assumptions, actual results can, and often do, differ from our estimates.
During the first quarter of 2020 certain potential impairment indicators were identified, specifically (i) the decline in the market price of our common units, (ii) the decline in global commodity prices and (iii) the COVID-19 pandemic; which together indicated the fair value of the reporting unit was less than its carrying amount as of March 31, 2020.
We performed a quantitative goodwill impairment test as of March 31, 2020 and determined fair value using a weighted combination of the income approach and the market approach. Determining fair value of a reporting unit requires judgment and use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, EBITDA margins,
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weighted average costs of capital and future market conditions, among others. We believe the estimates and assumptions used were reasonable and based on available market information, but variations in any of the assumptions could have resulted in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the income approach, we determined fair value based on estimated future cash flows, including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflects the overall level of inherent risk of the Partnership. Cash flow projections were derived from four-year operating forecasts plus an estimate of later period cash flows, all of which were developed by management. Subsequent period cash flows were developed using growth rates that management believed were reasonably likely to occur. Under the market approach, we determined fair value by applying valuation multiples of comparable publicly-traded companies to the projected EBITDA of the Partnership and then averaging that estimate with similar historical calculations using a three-year average. In addition, we estimated a reasonable control premium representing the incremental value that would accrue to us if we were to be acquired.
Based on the quantitative goodwill impairment test described above, our carrying amount exceeded fair value and as a result, we recognized a goodwill impairment of $619.4 million for the year ended December 31, 2020.
Long-Lived Assets
Long-lived assets, which include property and equipment, and intangible assets, comprise a significant amount of our total assets. Long-lived assets to be held and used by us are reviewed to determine whether any events or changes in circumstances indicate the carrying amount of the asset may not be recoverable. For long-lived assets to be held and used, we base our evaluation on impairment indicators such as the nature of the assets, the future economic benefit of the assets, the consistency of performance characteristics of compression units in our idle fleet with the performance characteristics of our revenue generating horsepower, any historical or future profitability measurements and other external market conditions or factors that may be present. If such impairment indicators are present or other factors exist that indicate the carrying amount of the asset may not be recoverable, we determine whether an impairment has occurred through the use of an undiscounted cash flows analysis. If an impairment has occurred, we recognize a loss for the difference between the carrying amount and the estimated fair value of the asset. The fair value of the asset is measured using quoted market prices or, in the absence of quoted market prices, is based on an estimate of discounted cash flows, the expected net sale proceeds compared to other similarly configured fleet units we recently sold, a review of other units recently offered for sale by third parties, or the estimated component value of similar equipment we plan to continue to use.
Potential events or circumstances that could reasonably be expected to negatively affect the key assumptions we used in estimating whether or not the carrying value of our long-lived assets are recoverable include the consolidation or failure of crude oil and natural gas producers, which may result in a smaller market for services and may cause us to lose key customers, and cost-cutting efforts by crude oil and natural gas producers, which may cause us to lose current or potential customers or achieve less revenue per customer. If our projections of cash flows associated with our units decline, we may have to record an impairment of compression equipment in future periods.
For the years ended December 31, 2021 and 2020, we evaluated the future deployment of our idle fleet under current market conditions and determined to retire 26 and 37 compressor units, respectively, for a total of approximately 11,000 and 15,000 horsepower, respectively, that were previously used to provide compression services in our business. As a result, we recorded impairments of compression equipment of $5.1 million and $8.1 million for the years ended December 31, 2021 and 2020, respectively. The primary causes for these impairments were: (i) units were not considered marketable in the foreseeable future, (ii) units were subject to excessive maintenance costs or (iii) units were unlikely to be accepted by customers due to certain performance characteristics of the unit, such as the inability to meet current quoting criteria without excessive retrofitting costs. These compression units were written down to their respective estimated salvage values, if any.
Estimated Useful Lives of Property, Plant and Equipment
Property, plant and equipment is carried at cost. Depreciation is computed on a straight-line basis using useful lives that are estimated based on assumptions and judgments that reflect both historical experience and expectations regarding future use of our assets. The use of different assumptions and judgments in the calculation of depreciation, especially those involving useful lives, would likely result in significantly different net book values of our assets and results of operations.
Commitments and Contingencies
From time to time, we and our subsidiaries may be involved in various claims and litigation arising in the ordinary course of business. Additionally, our compliance with state and local sales tax regulations is subject to audit by various taxing authorities. Certain taxing authorities have either claimed or issued an assessment that specific operational processes, which we and others in our industry regularly conduct, result in transactions that are subject to state sales taxes. We and others in our
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industry have disputed these claims and assessments based on either existing tax statutes or published guidance by the taxing authorities.
We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. While we are unable to predict the ultimate outcome of these actions, the accounting standard for contingencies requires management to make judgments about future events that are inherently uncertain. We are required to record a loss during any period in which we believe a contingency is probable and can be reasonably estimated. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. We expense legal costs as incurred, and all recorded legal liabilities are revised, as required, as better information becomes available to us.
We are currently protesting certain assessments made by the Oklahoma Tax Commission (“OTC”). We believe it is reasonably possible that we could incur losses related to this assessment depending on whether the administrative law judge assigned by the OTC accepts our position that the transactions are not taxable and we ultimately lose any and all subsequent legal challenges to such determination. We estimate that the range of losses we could incur is from $0 to approximately $19.5 million, including penalty and interest.
As of December 31, 2021 and 2020, we have recorded a $44.9 million accrued liability and $44.9 million related party receivable from Energy Transfer related to open audits with the Office of the Texas Comptroller of Public Accounts (the “Comptroller”), wherein the Comptroller has challenged the applicability of the manufacturing exemption.
Allowance for Credit Losses
We maintain an allowance for credit losses for our two financial assets, (i) trade accounts receivable and (ii) net investment in lease related to our sales-type lease, based on specific customer collection issues and historical experience.
Our determination of the allowance for credit losses requires us to make estimates and judgments regarding our customers’ ability to pay amounts due. We continuously evaluate the financial strength of our customers and the overall business climate in which our customers operate, and make adjustments to the allowance for credit losses as necessary. We evaluate the financial strength of our customers by reviewing the aging of their receivables, our collection experience with the customer, correspondence, financial information and third-party credit ratings. We evaluate the business climate in which our customers operate by reviewing various publicly available materials regarding our customers’ industry, including the solvency of various companies in the industry.
For the year ended December 31, 2021, we recognized a reversal of $2.7 million of our provision for expected credit losses. Improved market conditions for customers due to the recovery in commodity prices was the primary factor contributing to the decrease to the allowance for credit losses for the year ended December 31, 2021.
For the year ended December 31, 2020, we recognized a $3.7 million provision for expected credit losses. Low commodity prices, driven by decreased demand for and global oversupply of crude oil as a result of the COVID-19 pandemic, was the primary factor contributing to the higher allowance for credit losses for the year ended December 31, 2020.
Recent Accounting Pronouncements
Please see Part II, Item 8 “Financial Statements and Supplementary Data”, Note 17 for other specific recent accounting pronouncements affecting us.
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Market risk is the risk of loss arising from adverse changes in market rates and prices. We do not take title to any natural gas or crude oil in connection with our services and, accordingly, have no direct exposure to fluctuating commodity prices. However, the demand for our compression services depends upon the continued demand for, and production of, natural gas and crude oil. Sustained low natural gas or crude oil prices over the long term could result in a decline in the production of natural gas or crude oil, which could result in reduced demand for our compression services. We do not intend to hedge our indirect exposure to fluctuating commodity prices. A one percent decrease in average revenue generating horsepower during the year ended December 31, 2021 would have resulted in a decrease of approximately $5.9 million and $4.0 million in our revenue and Adjusted gross margin, respectively. Adjusted gross margin is a non-GAAP financial measure. For a reconciliation of Adjusted gross margin to gross margin, its most directly comparable financial measure, calculated and presented in accordance with GAAP, please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Non-GAAP Financial Measures”. Please also read Part I, Item 1A “Risk Factors – Risks Related to Our Business – An
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extended 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.”
Interest Rate Risk
We are exposed to market risk due to variable interest rates under our Credit Agreement.
As of December 31, 2021, we had $516.3 million of variable-rate outstanding indebtedness at a weighted-average interest rate of 2.68%. A one percent increase or decrease in the effective interest rate on our variable-rate outstanding debt as of December 31, 2021 would result in an annual increase or decrease in our interest expense of approximately $5.2 million.
For further information regarding our exposure to interest rate fluctuations on our debt obligations, see Note 9 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”. Although we do not currently hedge our variable rate debt, we may, in the future, hedge all or a portion of such debt.
Credit Risk
Our credit exposure generally relates to receivables for services provided. If any significant customer of ours should have credit or financial problems resulting in a delay or failure to pay the amount it owes us, it could have a material adverse effect on our business, financial condition, results of operations and cash flows. Please see Part II, Item 1A. “Risk Factors – Risk Related to Our Business – We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, suppliers or vendors could reduce our revenues, increase our expenses and otherwise have a negative impact on our ability to conduct our business, operating results, cash flows and ability to make distributions to our unitholders.”
ITEM 8. Financial Statements and Supplementary Data
The financial statements and supplementary information specified by this Item are presented in Part IV, Item 15 “Exhibits and Financial Statement Schedules”.
ITEM 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
ITEM 9A. Controls and Procedures
Disclosure Controls and Procedures
As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2021 at the reasonable assurance level.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting for us. Our internal control system was designed to provide reasonable assurance regarding the preparation and fair presentation of our published financial statements.
There are inherent limitations to the effectiveness of any control system, however well designed, including the possibility of human error and the possible circumvention or overriding of controls. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Management must make judgments with respect to the relative cost and expected benefits of any specific control measure. The design of a control system also is based in part upon assumptions and judgments made by management about the likelihood of future events, and there can be no assurance that a control will be effective under all potential future conditions. As a result, even an effective system of internal control over financial reporting can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared.
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Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2021. In making this assessment, management used the criteria set forth by the 2013 Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework. Based on this assessment, our management believes that, as of December 31, 2021, our internal control over financial reporting was effective. Grant Thornton LLP, an independent registered public accounting firm that audited our consolidated financial statements included herein, has also audited the effectiveness of our internal control over financial reporting as of December 31, 2021, as stated in their report, which is included herein.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors of USA Compression GP, LLC and
Unitholders of USA Compression Partners, LP
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of USA Compression Partners, LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2021, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2021, and our report dated February 15, 2022 expressed an unqualified opinion on those financial statements.
Basis for opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ GRANT THORNTON LLP
Houston, Texas
February 15, 2022
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Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. Other Information
None.
ITEM 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
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PART III
ITEM 10. Directors, Executive Officers and Corporate Governance
Board of Directors
Our general partner, USA Compression GP, LLC (the “General Partner”), manages our operations and activities. The General Partner is wholly owned by Energy Transfer LP (“Energy Transfer”). The General Partner has a board of directors (the “Board”) that manages our business. The Board is not elected by our unitholders and is not subject to re-election on a regular basis in the future. As the sole member of the General Partner, Energy Transfer is entitled under the limited liability company agreement of the General Partner (the “GP LLC Agreement”) to appoint all directors of the General Partner, subject to rights and restrictions contained in other agreements. The GP LLC Agreement provides that the Board shall consist of between two and eleven persons.
The Board is comprised of ten members, nine of whom were designated by Energy Transfer and one of whom was designated by EIG Management Company, LLC (“EIG Management”) pursuant to that certain Board Representation Agreement (the “Board Representation Agreement”) among us, the General Partner, Energy Transfer and EIG Veteran Equity Aggregator, L.P. (along with its affiliated funds, “EIG”) entered into on April 2, 2018 (the “Transactions Date”) in connection with our private placement to EIG and FS Energy and Power Fund (“FS Energy”) of Preferred Units and warrants to purchase common units of the Partnership (the “Warrants”). Under the Board Representation Agreement, EIG Management has the right to designate one member of the Board for so long as EIG and FS Energy own, in the aggregate, more than 5% of the Partnership’s outstanding common units (taking into account the common units issuable upon conversion of the Preferred Units and exercise of the Warrants). EIG Management has designated Matthew S. Hartman to serve on the Board. Four members of the Board are independent as defined under the independence standards established by the NYSE and the SEC. Although the NYSE does not require a publicly traded limited partnership like us to have a majority of independent directors on the Board or to establish a compensation committee or a nominating committee, the Board has elected to have a standing compensation committee (the “Compensation Committee”). We do not have a nominating committee in light of the fact that Energy Transfer and EIG currently collectively appoint all of the members of the Board.
Eric D. Long, our President and Chief Executive Officer (“CEO”), is currently the only management member of the Board. The non-management members of the Board meet in executive session without any members of management present at least twice a year. Mr. William S. Waldheim presides at such meetings. Interested parties can communicate directly with non-management members of the Board by mail in care of the General Counsel and Secretary at USA Compression Partners, LP, 111 Congress Avenue, Suite 2400, Austin, Texas 78701. Such communications should specify the intended recipient or recipients. Commercial solicitations or similar communications will not be forwarded to the Board.
As a limited partnership, NYSE rules do not require us to seek unitholder approval for the election of any of our directors. We do not have a formal process for identifying director nominees, nor do we have a formal policy regarding consideration of diversity in identifying director nominees. We believe, however, that the individuals appointed as directors have experience, skills and qualifications relevant to our business and have a history of service in senior leadership positions with the qualities and attributes required to provide effective oversight of the Partnership.
Independent Directors. The Board has determined that Matthew S. Hartman, Glenn E. Joyce, W. Brett Smith and William S. Waldheim are independent directors under the standards established by the NYSE and the Exchange Act. The Board considered all relevant facts and circumstances and applied the independence guidelines of the NYSE and the Exchange Act in determining that none of these directors has any material relationship with us, our management, the General Partner or its affiliates or our subsidiaries.
Mr. Hartman is a Managing Director at EIG, and, since the Transactions Date, EIG owns over 80% of the Preferred Units and Warrants in the Partnership. The Board determined that EIG’s ownership of Preferred Units and Warrants did not preclude the independence of Mr. Hartman because (i) the Preferred Units and Warrants do not confer voting rights sufficient to participate in the control of the Partnership or influence its management, (ii) the Board Representation Agreement does not grant to EIG a sufficient number of seats on the Board to significantly influence or control its decision making or materially influence the management or operation of the Partnership and (iii) the Board has determined that ownership of even a significant amount of the Partnership’s securities does not, by itself, preclude a finding of independence.
Mr. Smith is President of, and owns limited partnership interests in, Promontory Exploration, LP, Rubicon Oil & Gas II LP and Quientesa Royalty LP, which entities own non-operating working or royalty interests in wells and receive proceeds from liquids production purchased by a subsidiary of Energy Transfer under agreements with well operators. The Board determined that Mr. Smith’s association with these entities did not preclude the independence of Mr. Smith.
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The Board’s Role in Risk Oversight
The Board administers its risk oversight function as a whole and through its committees. It does so in part through discussion and review of our business, financial reporting and corporate governance policies, procedures and practices, with opportunity to make specific inquiries of management. In addition, at each regular meeting of the Board, management provides a report of the Partnership’s operational and financial performance, which often prompts questions and feedback from the Board. The audit committee of the Board (the “Audit Committee”) provides additional risk oversight through its quarterly meetings, where it discusses policies with respect to risk assessment and risk management, reviews contingent liabilities and risks that may be material to the Partnership and assesses major legislative and regulatory developments that could materially impact the Partnership’s contingent liabilities and risks. The Audit Committee is also required to discuss any material violations of our policies brought to its attention on an ad hoc basis. Additionally, the Compensation Committee reviews our overall compensation program and its effectiveness at both linking executive pay to performance and aligning the interests of our executives and our unitholders.
Committees of the Board of Directors
Audit Committee. The Board appoints the Audit Committee, which is comprised solely of directors who meet the independence and experience standards established by the NYSE and the Exchange Act. The Audit Committee consists of Messrs. Hartman, Joyce, Smith and Waldheim, and Mr. Waldheim serves as chairman of the Audit Committee. The Board determined that Mr. Waldheim is an “audit committee financial expert” as defined in Item 407(d)(5)(ii) of SEC Regulation S-K, and that each of Messrs. Hartman, Joyce, Smith and Waldheim is “independent” within the meaning of the applicable NYSE and Exchange Act rules governing audit committee independence. The Audit Committee assists the Board in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements as well as the effectiveness of our corporate policies and internal controls. The Audit Committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The Audit Committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the Audit Committee.
The charter of the Audit Committee (the “Audit Committee Charter”) is available under the Investor Relations tab on our website at usacompression.com. We will provide a copy of the Audit Committee Charter to any of our unitholders without charge upon written request to Investor Relations, 111 Congress Avenue, Suite 2400, Austin, TX 78701.
Compensation Committee. The NYSE does not require a listed limited partnership like us to have a compensation committee. However, the Board established the Compensation Committee to, among other things, oversee our compensation program described below in Part III, Item 11 “Executive Compensation.” The Compensation Committee consists of Messrs. Joyce, Smith and Waldheim and is chaired by Mr. Joyce. The Compensation Committee establishes and reviews general policies related to our compensation and benefits and is responsible for making recommendations to the Board with respect to the compensation and benefits of the Board. In addition, the Compensation Committee administers the USA Compression Partners, LP 2013 Long-Term Incentive Plan, as amended and as may be further amended or replaced from time to time (the “LTIP”).
Under the charter of the Compensation Committee (the “Compensation Committee Charter”), a director serving as a member of the Compensation Committee may not be an officer of or employed by the General Partner, us or our subsidiaries. During 2021, none of Mr. Joyce, Mr. Smith or Mr. Waldheim was an officer or employee of Energy Transfer or any of its affiliates, or served as an officer of any company with respect to which any of our executive officers served on such company’s board of directors. In addition, none of Mr. Joyce, Mr. Smith or Mr. Waldheim is a former employee of Energy Transfer or any of its affiliates.
The Compensation Committee Charter is available under the Investor Relations tab on our website at usacompression.com. We will provide a copy of the Compensation Committee Charter to any of our unitholders without charge upon written request to Investor Relations, 111 Congress Avenue, Suite 2400, Austin, TX 78701.
Conflicts Committee. As set forth in the GP LLC Agreement, the General Partner may, from time to time, establish a conflicts committee to which the Board will appoint independent directors and which may be asked to review specific matters that the Board believes may involve conflicts of interest between us, our limited partners and Energy Transfer. Such conflicts committee will determine the resolution of the conflict of interest in any matter referred to it in good faith. The members of the conflicts committee may not be officers or employees of the General Partner or directors, officers or employees of its affiliates, including Energy Transfer, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on the Audit Committee, and certain other requirements. Any matters approved by the conflicts
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committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by the General Partner of any duties it may owe us or our unitholders.
Corporate Governance Guidelines and Code of Ethics
The Board has adopted Corporate Governance Guidelines (the “Guidelines”) that outline important policies and practices regarding our governance and provide a framework for the function of the Board and its committees. The Board has also adopted a Code of Business Conduct and Ethics (the “Code”) that applies to the General Partner and its subsidiaries and affiliates, including us, and to all of its and their directors, employees and officers, including its principal executive officer, principal financial officer and principal accounting officer. We intend to post any amendments to the Code, or waivers of its provisions applicable to our directors or executive officers, including our principal executive officer and principal financial officer, on our website. The Guidelines and the Code are available under the Investor Relations tab on our website at usacompression.com. We will provide copies of the Guidelines and the Code to any of our unitholders without charge upon written request to Investor Relations, 111 Congress Avenue, Suite 2400, Austin, TX 78701.
Note that the preceding internet addresses are for informational purposes only and are not intended to be hyperlinked. Accordingly, no information found on or provided at those internet addresses or on our website in general is intended or deemed to be incorporated by reference herein.
Directors and Executive Officers
The following table shows information as of February 10, 2022 regarding the current directors and executive officers of USA Compression GP, LLC.
| Name | Age | Position with USA Compression GP, LLC | ||||||||||||
| Eric D. Long | 63 | President and Chief Executive Officer and Director | ||||||||||||
| Matthew C. Liuzzi | 47 | Vice President, Chief Financial Officer and Treasurer | ||||||||||||
| Eric Scheller | 58 | Vice President and Chief Operating Officer | ||||||||||||
| Christopher W. Porter | 38 | Vice President, General Counsel and Secretary | ||||||||||||
| Sean T. Kimble | 57 | Vice President, Human Resources | ||||||||||||
| Christopher R. Curia | 66 | Director | ||||||||||||
| Matthew S. Hartman | 41 | Director | ||||||||||||
| Glenn E. Joyce | 64 | Director | ||||||||||||
| Thomas E. Long | 65 | Director | ||||||||||||
| Thomas P. Mason | 65 | Director | ||||||||||||
| Matthew S. Ramsey | 66 | Director | ||||||||||||
| W. Brett Smith | 62 | Director | ||||||||||||
| William S. Waldheim | 65 | Director | ||||||||||||
| Bradford D. Whitehurst | 47 | Director | ||||||||||||
The directors of the General Partner hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the Board. There are no family relationships among any of the directors or executive officers of the General Partner.
Eric D. Long has served as our President and CEO since September 2002 and has served as a director of the General Partner since June 2011. Mr. Long co-founded USA Compression in 1998 and has over 40 years of experience in the oil and gas industry. From 1980 to 1987, Mr. Long served in a variety of technical and managerial roles for several major pipeline and oil and natural gas producing companies, including Bass Enterprises Production Co. and Texas Oil & Gas. Mr. Long then served in a variety of senior officer level operating positions with affiliates of Hanover Energy, Inc., a company primarily engaged in the business of gathering, compressing and transporting natural gas. In 1993, Mr. Long co-founded Global Compression Services, Inc., a compression services company. Mr. Long was formerly on the board of directors of the Wiser Oil Company, an NYSE listed company from May 2001 until it was sold to Forest Oil Corporation in May 2004. Mr. Long received his bachelor’s degree, with honors, in Petroleum Engineering from Texas A&M University. He is a registered Professional Engineer in the state of Texas.
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As a result of his professional background, Mr. Long brings to us executive level strategic, operational and financial skills. These skills, combined with his over 40 years of experience in the oil and natural gas industry, including in particular his experience in the compression services sector, make Mr. Long a valuable member of the Board.
Matthew C. Liuzzi has served as our Vice President, Chief Financial Officer and Treasurer since January 2015. Prior to such time, Mr. Liuzzi served as our Senior Vice President – Strategic Development since joining us in April 2013. Mr. Liuzzi joined us after nine years in investment banking, since 2008 at Barclays, where he was most recently a Director in the Global Natural Resources Group in Houston. At Barclays, Mr. Liuzzi worked primarily with midstream clients on a variety of investment banking assignments, including initial public offerings, public and private debt and equity offerings, as well as strategic advisory assignments. He holds a B.A. and an M.B.A., both from the University of Virginia.
Eric A. Scheller has served as our Vice President, Chief Operating Officer since June 2020. Prior to that, Mr. Scheller served as our Vice President—Fleet Operations since April 2018, and prior to that was our Vice President, Operations & Performance Management beginning in August 2015. Prior to joining us, Mr. Scheller was a Director at Sapient Global Markets since August 2013. Before Sapient, Mr. Scheller was a consultant in private practice advising midstream and chemicals firms from January 2012 to July 2013. Prior to that, he held several positions with Enterprise Products Partners LP from November 2004 to December 2011, most recently as Regional Director, Pipeline & Storage Services. Mr. Scheller holds a B.S. in Chemical Engineering (Math minor), a Masters of Chemical Engineering and an M.B.A., all from the University of Houston. Mr. Scheller is also a CFA ® charterholder.
Christopher W. Porter has served as our Vice President, General Counsel and Secretary since January 2017, and, prior to that, had served as our Associate General Counsel and Assistant Secretary since October 2015. From January 2010 through October 2015, Mr. Porter practiced corporate and securities law at Hunton Andrews Kurth LLP, representing public and private companies, including master limited partnerships, in capital markets offerings and mergers and acquisitions. Mr. Porter holds a B.B.A. degree in accounting from Texas A&M University, a M.S. degree in finance from Texas A&M University, and a J.D. degree from The George Washington University.
Sean T. Kimble has served as our Vice President, Human Resources since June 2014. Mr. Kimble brings to us over twenty-five years of human resources leadership experience. Prior to joining us, he was most recently the Senior Vice President of Human Resources at Millard Refrigerated Services from January 2011 to May 2014 where he led all aspects of human resources. Before joining Millard, he was the Chief Administrative Officer and Executive Vice President of Human Resources at MV Transportation from March 2005 to February 2009 where he led human resources, safety, labor relations and various other operating support functions. Mr. Kimble holds a B.S. in marketing from Sacramento State University and an M.B.A. from Saint Mary’s College of California. Mr. Kimble also completed the University of Michigan’s Strategic HR and Strategic Collective Bargaining Programs.
Christopher R. Curia has served on the Board since April 2018. Mr. Curia has also served as a director on the board of directors of the general partner of Sunoco LP, a subsidiary of Energy Transfer LP, since August 2014 and as its Executive Vice President-Human Resources since April 2015. Mr. Curia was appointed the Executive Vice President and Chief Human Resources Officer of the general partner of Energy Transfer LP in January 2015. Mr. Curia joined Energy Transfer Operating, L.P. (“ETO”), a subsidiary of Energy Transfer LP which has since merged with Energy Transfer LP, in July 2008. Prior to joining ETO, Mr. Curia held HR leadership positions at both Valero Energy Corporation and Pennzoil and has more than three decades of Human Resources experience in the oil and gas field. Mr. Curia holds a master’s degree in Industrial Relations from the University of West Virginia.
Mr. Curia was selected to serve on the Board due to the valuable perspective he brings from his extensive experience working as a human resources professional in the energy industry, and the insights he brings to the Board on matters such as succession planning, compensation, employee management and acquisition evaluation and integration.
Matthew S. Hartman has served on the Board since April 2018. Mr. Hartman is a Managing Director at EIG Global Energy Partners and leads EIG’s infrastructure investment team, where he invests in and monitors energy infrastructure investments. Prior to joining EIG in 2014, Mr. Hartman served in various roles within the Citigroup and UBS investment banking divisions, where he advised on mergers as well as equity and debt financings for midstream energy companies. Mr. Hartman also previously worked in Ernst & Young’s tax practice. Mr. Hartman received a B.B.A. and B.P.A. from Oklahoma Baptist University and an M.B.A. from the University of Texas.
Mr. Hartman was selected to serve on the Board because of his financial and investment acumen and experience with the midstream and infrastructure energy sectors.
Glenn E. Joyce has served on the Board since April 2018. Mr. Joyce has served as Chief Administrative Officer of Apex International Energy (“Apex”) since January 2017. He previously served as Director – HR and Administration since he joined
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Apex in April 2016. Prior to joining Apex, he spent over 17 years with Apache Corporation where his last position was Director of Global Human Resources in which he managed the HR functions of the international regions of Apache (Australia, Argentina, UK, Egypt). Previously, he worked for Amoco and was involved in international operations in many different countries. Mr. Joyce received his bachelor’s degree in accounting from Texas A&M University.
Mr. Joyce was selected to serve on the Board due to his extensive experience in senior human resources leadership positions in the energy industry.
Thomas E. Long has served on the Board since April 2018. Mr. Long was appointed as Co-Chief Executive Officer of the general partner of Energy Transfer LP effective January 2021. Mr. Long previously served as their Chief Financial Officer from February 2016 until January 2021. Mr. Long has also served as a director of the general partner of Energy Transfer LP since April 2019. Mr. Long served as Co-Chief Executive Officer of ETO’s general partner from January 2021 until its merger into Energy Transfer LP in April 2021 and was previously its Chief Financial Officer. He also served on the board of directors of the general partner of Sunoco LP from May 2016 until May 2021. Mr. Long also served as the Chief Financial Officer and as a director of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Long also served as Executive Vice President and Chief Financial Officer of Regency GP LLC from November 2010 to April 2015.
Mr. Long was selected to serve on the Board because of his understanding of energy-related corporate finance gained through his extensive experience in the energy industry.
Thomas P. Mason has served on the Board since April 2018. Mr. Mason became Executive Vice President and General Counsel of the general partner of Energy Transfer LP in December 2015, and has also served as the Executive Vice President, General Counsel and President - LNG of the general partner of Energy Transfer LP since October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. In February 2021, Mr. Mason assumed leadership responsibility over Energy Transfer LP’s new Alternative Energy Group, which focuses on the development of alternative energy projects aimed at continuing to reduce Energy Transfer LP’s environmental footprint throughout its operations. Mr. Mason previously served as Senior Vice President, General Counsel and Secretary of ETO’s general partner from April 2012 to December 2015, as Vice President, General Counsel and Secretary from June 2008 and as General Counsel and Secretary from February 2007. Prior to joining ETO, he was a partner in the Houston office of Vinson & Elkins L.L.P. Mr. Mason has specialized in securities offerings and mergers and acquisitions for more than 25 years. Mr. Mason also previously served on the Board of Directors of the general partner of Sunoco Logistics Partners L.P. from October 2012 to April 2017 and also served on the Board of Directors of the general partner of PennTex Midstream Partners, LP from November 2016 to July 2017.
Mr. Mason was selected to serve on the Board because of his decades of legal experience in securities, mergers and acquisitions and corporate governance in the energy sector.
Matthew S. Ramsey has served on the Board since April 2018. Mr. Ramsey currently serves as the Chief Operating Officer of the general partner of Energy Transfer LP, a position he has held since October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. Since July 2012, Mr. Ramsey has also been a member of the board of directors of the general partner of Energy Transfer LP. Additionally, Mr. Ramsey serves as Chairman of the Board of Directors of the general partner of Sunoco, LP. Mr. Ramsey previously served as President, Chief Operating Officer and as a member of the Board of Directors of Energy Transfer Partners, L.P. Mr. Ramsey also served as President and Chief Operating Officer and Chairman of the board of directors of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Ramsey also served as the President and Chief Operating Officer of the general partner of ETO since November 2015, and was a member of their board since November 2015, each until its merger into Energy Transfer LP in April 2021. Mr. Ramsey formerly served as a board member of RSP Permian, Inc. and on its audit and compensation committees. Prior to joining management at Energy Transfer, Mr. Ramsey served as President of RPM Exploration, Ltd., a private oil and gas partnership. In addition to his work in the energy business, Mr. Ramsey serves on the board of directors of the National Association of Manufacturers, and as a Trustee of the Southwestern Medical Foundation. He is the former Chairman of the University of Texas Chancellor’s Council. Mr. Ramsey holds a B.B.A. in Marketing from the University of Texas at Austin and a J.D. from South Texas College of Law.
Mr. Ramsey was selected to serve on the Board in recognition of his vast knowledge of the energy space and valuable industry, operational and management experience.
W. Brett Smith has served on the Board since April 2021. Mr. Smith has also served as President and Managing Partner of Rubicon Oil & Gas, LLC since October 2000, President of Rubicon Oil & Gas II, LP since May 2005, President of Quientesa Royalty LP since February 2005, President of Acton Energy LP since October 2008 and President of Promontory Exploration, LP since 2017. Mr. Smith was President of Rubicon Oil & Gas, LP from October 2000 to May 2005. For more than 30 years Mr. Smith has been active in assembling exploration prospects in the Permian Basin, Oklahoma, New Mexico and the Rocky Mountain areas. Mr. Smith served on the board of directors of the general partner of ETO and on its audit committee from
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February 2018 through April 2021. Mr. Smith also previously served on the board of directors of Sunoco LP and was a member of its audit and compensation committees.
Mr. Smith was selected to serve on the Board based on his experience as an executive in the oil and gas industry, as well as his recent experience on the board of another publicly traded limited partnership.
William S. Waldheim has served on the Board since April 2018. Mr. Waldheim has also served on the board of directors of Southcross Energy Partners GP, LLC since February 2020. Mr. Waldheim served as a director and a member of the Audit, Finance & Risk Committee of Enbridge Energy Company, Inc. and Enbridge Energy Management, L.L.C. from February 2016 through December 2018. He previously served as President of DCP Midstream LP where he had overall responsibility for DCP Midstream’s affairs including commercial, trading and business development until his retirement in 2015. Prior to this, Mr. Waldheim was President of Midstream Marketing and Logistics for DCP Midstream and managed natural gas, crude oil and natural gas liquids marketing and logistics. From 2005 to 2008, he was Group Vice President of Commercial for DCP Midstream, managing its upstream and downstream commercial business. Mr. Waldheim started his professional career in 1978 with Champlin Petroleum as an auditor and financial analyst and served in roles involving NGL and crude oil distribution and marketing. He served as Vice President of NGL and Crude Oil Marketing for Union Pacific Fuels from 1987 until 1998 at which time it was acquired by DCP Midstream.
Mr. Waldheim was selected to serve on the Board because of his broad and extensive experience in senior leadership roles in the energy industry and his financial and accounting expertise.
Bradford D. Whitehurst has served on the Board since April 2019. Mr. Whitehurst currently serves as the Chief Financial Officer of the general partner of Energy Transfer LP, a position he has held since January 2021. Prior to that, Mr. Whitehurst served as their Executive Vice President – Head of Tax since August 2014. Mr. Whitehurst also served as the Chief Financial Officer of the general partner of ETO from January 2021 until its merger into Energy Transfer LP in April 2021, and prior to that was their Executive Vice President—Head of Tax since August 2014. Prior to joining Energy Transfer LP, Mr. Whitehurst was a partner in the Washington, DC office of Bingham McCutchen LLP and an attorney in the Washington, DC offices of both McKee Nelson LLP and Hogan & Hartson. Mr. Whitehurst has specialized in partnership taxation and has advised Energy Transfer LP in his role as outside counsel since 2006.
Mr. Whitehurst was selected to serve on the Board because of his strong background in the energy sector and specialized knowledge of the taxation structure and issues unique to partnerships.
Delinquent Section 16(a) Reports
Section 16(a) of the Exchange Act requires that the members of the Board, our executive officers and persons who own more than 10 percent of a registered class of our equity securities file initial reports of ownership and reports of changes in ownership of our common units and other equity securities with the SEC and any exchange or other system on which such securities are traded or quoted. To our knowledge and based solely on a review of Section 16(a) forms filed electronically with the SEC, we believe that all reporting obligations of the members of the Board, our executive officers and greater than 10 percent unitholders under Section 16(a) were satisfied during the year ended December 31, 2021.
Common Unit Ownership by Directors and Executive Officers
We encourage our directors and executive officers to invest in and retain ownership of our common units, but we do not require such individuals to establish and maintain a particular level of ownership.
Reimbursement of Expenses of the General Partner
The General Partner does not receive any management fee or other compensation for its management of us, but we reimburse the General Partner and its affiliates for all expenses incurred on our behalf, including the compensation of employees of the General Partner or its affiliates that perform services on our behalf. These expenses include all expenditures necessary or appropriate to the conduct of our business and that are allocable to us. The Partnership Agreement provides that the General Partner will determine in good faith the expenses that are allocable to us. There is no cap on the amount that may be paid or reimbursed to the General Partner or its affiliates for compensation or expenses incurred on our behalf.
ITEM 11. Executive Compensation
As is commonly the case with publicly traded limited partnerships, we have no officers, directors or employees. Under the terms of the Partnership Agreement, we are ultimately managed by the General Partner, which is controlled by Energy Transfer. All of our employees, including our executive officers, are employees of USA Compression Management Services, LLC
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(“USAC Management”), a wholly owned subsidiary of the General Partner. References to “our officers” and “our directors” refer to the officers and directors of the General Partner.
Compensation Discussion & Analysis
Named Executive Officers
The following disclosure describes the executive compensation program for the named executive officers identified below (the “NEOs”). For the year ended December 31, 2021, the NEOs were:
•Eric D. Long, President and CEO;
•Matthew C. Liuzzi, Vice President, Chief Financial Officer and Treasurer;
•Eric A. Scheller, Vice President and Chief Operating Officer;
•Christopher W. Porter, Vice President, General Counsel and Secretary; and
•Sean T. Kimble, Vice President, Human Resources.
Compensation Philosophy and Objectives
Since our initial public offering in 2013, we have consistently based our compensation philosophy and objectives on the premise that a significant portion of each NEO’s total compensation should be incentive-based or “at-risk” compensation. We share Energy Transfer’s philosophy that the NEOs’ total compensation levels should be competitive in the marketplace for executive talent and abilities. The Compensation Committee generally targets a competitive range at or near the 50th percentile of the market for aggregate compensation consisting of the three main components of our compensation program: base salary, annual discretionary cash bonus and long-term equity incentive awards. The Compensation Committee believes that a desirable balance of incentive-based compensation is achieved by: (i) the payment of annual discretionary cash bonuses that consider (a) the achievement of the financial and operational performance objectives for a fiscal year set at the beginning of such fiscal year and (b) the individual contributions of each NEO to our level of success in achieving the annual financial and operational performance objectives, and (ii) the annual grant of time-based restricted phantom unit awards under the LTIP, which awards are intended to incentivize and retain our key employees for the long-term and motivate them to focus their efforts on increasing the market price of our common units and the level of cash distributions we pay to our common unitholders.
The following charts illustrate the level of at-risk incentive compensation we awarded in 2021 to our CEO and, on an averaged basis, the other NEOs. “Variable/at-risk” compensation is comprised of long-term equity incentive awards and annual discretionary cash bonuses, and “fixed” compensation is comprised of base salary.
Our compensation program is structured to achieve the following:
•compensate executive officers with an industry-competitive total compensation package of competitive base salaries and significant incentive opportunities yielding a total compensation package in a competitive range at or near the 50th percentile of the market;
•attract, retain and reward talented executive officers and key members of management by providing a total compensation package competitive with those of their counterparts at similarly situated companies;
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•motivate executive officers and key employees to achieve strong financial and operational performance;
•ensure that a significant portion of each executive officer’s compensation is performance-based or “at risk” compensation; and
•reward individual performance.
Methodology to Setting Compensation Packages
Our executive compensation program is administered by the Compensation Committee. The Compensation Committee considers market trends in compensation, including the practices of identified competitors, and the alignment of the compensation program with the Partnership’s compensation philosophy described above. Specifically, for the NEOs, the Compensation Committee:
•establishes and approves target compensation levels for each NEO;
•approves Partnership performance measures and goals;
•determines the mix between cash and equity compensation, short-term and long-term incentives and benefits;
•verifies the achievement of previously established performance goals; and
•approves the resulting cash or equity awards to the NEOs.
The Compensation Committee also considers other factors such as the role, contribution, skills, experience and performance of an individual relative to his or her peers at the Partnership. The Compensation Committee does not assign a specific weight to these factors, but rather makes a subjective judgment taking all of these factors into account.
The Compensation Committee reviews and approves all compensation for the NEOs. In determining the compensation for the NEOs, the Compensation Committee takes into account input from the CEO, for the compensation of the other NEOs. The CEO considers comparative compensation data and evaluates the individual performance of each NEO and their respective contributions to the Partnership. The recommendations are then reviewed by the Compensation Committee, which may accept the recommendations or make adjustments to the recommended compensation based on the Compensation Committee’s assessment of the individual’s performance and contributions to the Partnership. The CEO’s compensation is reviewed and approved by the Compensation Committee based on comparative compensation data and the Compensation Committee’s independent evaluation of the CEO’s contributions to the Partnership’s performance.
The Compensation Committee regularly compares results for the annual base salary, annual short-term cash bonus and long-term equity incentive awards of the NEOs against data for compensation levels for specific executive positions reported in published executive compensation surveys within each of the (i) energy industry and (ii) overall market. The Compensation Committee also reviews publicly filed peer group executive compensation disclosures pertaining to certain executive roles, but because of limited sample size due to the relatively small number of publicly traded natural gas compression companies, the Compensation Committee uses this data as a reference point rather than a primary data source.
Periodically, we engage a third-party consultant to provide the Compensation Committee with market information about compensation levels at peer companies to assist in evaluating compensation levels for our executives, including the NEOs. In 2019, Longnecker & Associates (“Longnecker”), who was also the independent compensation advisor to Energy Transfer in 2019, was engaged to provide an updated targeted market review and benchmarking for certain members of our senior leadership team (the “2019 Longnecker Report”). In 2020, the Compensation Committee determined that the 2019 Longnecker Report was completed recently enough to be utilized as a data source in reviewing and setting 2021 NEO compensation levels. As a result, the Compensation Committee relied on the results of the 2019 Longnecker Report for information on base salary, bonus and general compensation items for 2021 for the NEOs (as discussed below, our Compensation Committee utilized another report in determining the number of equity awards that should be granted to our NEOs in December 2021).
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For purposes of the 2019 Longnecker Report, our peer group, as selected by the Compensation Committee in consultation with Longnecker, included the following companies:
| Company | Ticker | |||||||
| 1. Antero Midstream Corporation | AM | |||||||
| 2. Archrock, Inc. | AROC | |||||||
| 3. Crestwood Equity Partners LP | CEQP | |||||||
| 4. Genesis Energy, L.P. | GEL | |||||||
| 5. Holly Energy Partners, L.P. | ||||||||