WASHINGTON D.C. 20549
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,” and "emerging“emerging growth company"company” in Rule 12b-2 of the Exchange Act.
Forward-Looking Statements
This Annual Report on Form 10-K (this “Annual Report”) contains “forward-looking statements” and information based on our beliefs and those of our general partner. Forward-looking statements in this annual reportAnnual Report are identifiable by the use of the following words, the negative of such words, and other similar words: “anticipates”, “assumes”, “believes”, “budgets”, “could”, “estimates”, “expects”, “forecasts”, “goal”, “intends”, “may”, “might”, “plans”, “predicts”, “projects”, “schedules”, “seeks”, “should, “targets”, “will” and “would”.
Such forward-looking statements reflect our current views with respect to future events and financial performance and are based on assumptions that we believe to be reasonable but such forward-looking statements
are subject to numerous risks, and uncertainties, including, but not limited to:
•economic and operating conditions that are outside of our control, including the trading price of our common units, and the supply, demand, and prices of oil and natural gas;
•the availability of adequate sources of capital to us;us, including changes to interest rates;
•our existing debt levels and our flexibilityability to obtain additional financing;
•our ability to continue to make cash distributions, or increase cash distributions from current levels, after the establishment of reserves, payment of debt service, and other contractual obligations;
•the restrictions on our business that are imposed under our long-term debt agreements;
•our dependence upon a limited number of customers and the activity levels of our customers;
•the levels of competition we encounter;
•our ability to replacerenew our contracts with customers, which are generally short-term contracts;
•the availability of raw materials and labor at reasonable prices;
•risks related to acquisitions and our growth strategy;
our operational performance;
risks related to our foreign operations;
•the credit and risk profile of TETRA;Spartan;
the ability of our general partner to retain key personnel;
•information technology risks including the risk from cyberattack;
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•acts of terrorism, war or political or civil unrest in the United States or elsewhere, including the Russian military invasion of Ukraine; •operating hazards, natural disasters, weather-related impacts, casualty losses and other matters beyond our control; •the effects of existing and future laws and governmental regulations; •global or national health concerns, including the outbreak of pandemics or epidemics such as the COVID-19 pandemic; •operational challenges relating to COVID-19, distribution and administration of COVID-19 vaccines 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; • | global or national health concerns, including the outbreak of pandemics or epidemics such as the coronavirus(COVID-19),
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the effect and results of litigation, regulatory matters, settlements, audits, assessments, and contingencies,contingencies; and
•other risks and uncertainties under “Item 1A. Risk Factors” in this Annual Report and as included in our other filings with the U.S. Securities and Exchange Commission (“SEC”), which are available free of charge on the SEC website at www.sec.gov.
The risks and uncertainties referred to above are generally beyond our ability to control and we cannot predict all the risks and uncertainties that could cause our actual results to differ from those indicated by the forward-looking statements. If any of these risks or uncertainties materialize, or if any of the underlying assumptions prove incorrect, actual results may vary from those indicated by the forward-looking statements, and such variances may be material.
All subsequent written and oral forward-looking statements made by or attributable to us or to persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and we undertake no obligation to update or revise any forward-looking statements we may make, except as may be required by law.
Summary Risk Factors
Our business is subject to varying degrees of risk and uncertainty. Investors should consider the risks and uncertainties summarized below, as well as the risks and uncertainties discussed in Part I, Item 1A, “Risk Factors” of this Annual Report. Additional risks not presently known to us or that we currently deem immaterial may also affect us. If any of these risks occur, our business, financial condition or results of operations could be materially and adversely affected.
Our business is subject to the following principal risks and uncertainties:
•Reduced demand for or production levels of oil and gas adversely affect the demand for and prices we charge for our services, which could cause our revenue and cash available for distribution to our unitholders to decrease.
•Our results of operations, cash flows and financial condition could continue to be adversely impacted by the COVID-19 pandemic.
•Our substantial leverage.
•We may be unable to repurchase or refinance our senior secured notes in the event of a change of control as required by their respective indentures.
•The loss of any of our most significant customers would result in a decline in our revenue and cash available to pay distributions to our common unitholders.
•Our ability to manage and grow our business effectively and provide quality services to our customers may be adversely affected if our general partner loses its management or we are unable to retain trained personnel.
•Pressure from competitors may result in price reductions and periods of reduced demand for our products.
•Our operations in non-U.S. markets expose us to legal, political and economic risks that could have a material impact on our business.
•Regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and gas wells that may reduce demand for our services.
•A cyberattack or other failure or security breach of our information technology infrastructure, or the theft, loss or misuse of personal data, could adversely affect our business and operations.
•The market price of our common units has been and may continue to be volatile.
•Spartan has conflicts of interest, which may permit it to favor its own interests to our unitholders’ detriment.
•Our partnership agreement limits our general partner’s fiduciary duties to our common unitholders and restricts the remedies available to our common unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
•Our common unitholders have limited voting rights and are not entitled to elect our general partner or its directors.
•We are exempt from certain corporate governance requirements that provide additional protection to stockholders of other public companies.
•Our tax treatment depends on our status as a partnership for federal income tax purposes. Our cash available for distribution to unitholders may be substantially reduced if we become subject to entity-level taxation as a result of the Internal Revenue Service (“IRS”) treating us as a corporation or legislative, judicial or administrative changes, and may also be reduced by any audit adjustments if imposed directly on the Partnership.
•Even if unitholders do not receive any cash distributions from us, unitholders will be required to pay taxes on their share of our taxable income. A unitholder’s share of our taxable income may be increased as a result of the IRS successfully contesting any of the federal income tax positions we take.
•Tax-exempt entities and non-U.S. unitholders face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Certain Defined Terms
Unless the context requires otherwise, when we refer to “we,” “us,” “our,” and “the Partnership,” we are describing CSI Compressco LP and its wholly owned subsidiaries on a consolidated basis. References to “CSI Compressco GP” or “our general partner” refer to our general partner, CSI Compressco GP LLC (f/k/a CSI Compressco GP Inc.). References to “TETRA” refer to TETRA Technologies, Inc., the former owner of our general partner, and TETRA’s controlled subsidiaries, other than us.subsidiaries. References to “Compressco”“Spartan” refer to Compressco, Inc. and its controlled subsidiaries, other than us. References to “TETRA International” refer to TETRA International Incorporated and TETRA International’s controlled subsidiaries.Spartan Energy Partners LP. References to the “Initial Public Offering” refer to the Partnership’s initial public offering of 2,670,000 common units representing limited partner interests in the Partnership ("(“common units"units”) at $20.00 per common unit completed on June 20, 2011 pursuant to a Registration Statement on Form S-1, as amended (File No. 333-155260) (the "Registration Statement"), initially filed on November 10, 2008 by the Partnership with the Securities and Exchange Commission (the "SEC")SEC pursuant to the Securities Act of 1933, as amended (the "Securities Act"“Securities Act”), including a prospectus regarding the Initial Public Offering (the "Prospectus") filed with the SEC on June 16, 2011 pursuant to Rule 424(b).
PART I
Item 1. Business.
The financial statements presented in this annual reportAnnual Report are the consolidated financial statements of CSI Compressco LP, a Delaware limited partnership and its subsidiaries. When the terms “the Partnership,” “we,” “us” or “our” are used in this document, those terms refer to CSI Compressco LP and its consolidated subsidiaries.
We were formed in October 2008. Our headquarters are located at 24955 Interstate 45 North,1735 Hughes Landing Boulevard, Suite 200, The Woodlands, Texas, 77380. Our phone number is 281-364-2244,(832) 365-2257 and our website is www.csicompressco.com. Our commonunits aretraded on theNASDAQ Exchange (“NASDAQ”)under the symbol “CCLP.”
Our Corporate Governance Guidelines, Code of Conduct, Financial Code of Ethics, and Audit Committee Charter, as well as 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 are all available, free of charge, on our website at www.csicompressco.com as soon as practicable after we file the reports with the SEC. Information contained on or connected to our website is not, and shall not be deemed to be, a part of this Annual Report on Form 10-K or incorporated into any other filings with the SEC. The documents referenced above are available in print at no cost to any unitholder who requests them from our Corporate Secretary.
About CSI Compressco LP
We are a provider of contract services including natural gas compression services and equipmenttreating services. Natural gas compression is used for oil and natural gas and oil production, gathering, artificial lift, transmission, processing, and storage. Treating services include removal of contaminants from a natural gas stream and cooling to reduce the temperature of produced gas and liquids. We also sell bothused standard and custom-designed, engineered compressor packages and provide aftermarket services and compressor package parts and components manufactured by third-party suppliers. We provide thesecontract compression and treating services and equipmentcompressor parts and component sales to a broad base of natural gas and oil exploration and production, midstream, transmission, and transmissionstorage companies operating throughout many of the onshore producing regions of the United States, as well as in a number of international locations, including the countries of Mexico, Canada, Argentina, Egypt and Argentina. We designChile. Previously, our equipment sales (new unit sales) business included the fabrication and fabricate a majoritysale of thenew standard and custom-designed, engineered compressor packages thatfabricated primarily at our facility in Midland, Texas. In the fourth quarter of 2020, we use to provide compression services or sell to customers.fully exited the new unit sales business.
We are one of the largest service providers of natural gas compression services in the United States, using our fleet of compressor packages that employ a full spectrum of low-, medium-, and high-horsepower engines. Low-horsepower compressor packages enhance production for dry gas wells and liquids-loaded gas wells by deliquefying the wells, lowering wellhead pressure, and increasing gas velocity. These packages are also used in connection with oil and liquids production and in vapor recovery and casing gas system applications. Low- to medium-horsepower compressor packages are typically selected for wellhead and natural gas gathering systems, artificial lift systems, and other applications primarily in connection with natural gas and oil production. Our high-horsepower compressor package offerings are typically deployed in natural gas production, natural gas gathering, centralized gas lift, centralized compression facilities, and midstream applications.
Our equipment sales business includes the fabrication and sale of both standard and custom-designed, engineered compressor packages, primarily at our facility in Midland, Texas. We design, fabricate, and assemble natural gas reciprocating and rotary compressor packages up to 2,500 horsepower for use in our service fleet and up to 8,000 horsepower for sale to our broadened customer base. The compressor packages that we fabricate are sold to customers for their use in various applications including gas gathering, gas lift, carbon dioxide injection, wellhead compression, gas storage, refrigeration plant compression, gas processing, pressure maintenance, pipeline transmission, vapor recovery, gas transmission, fuel gas boosters, and coal bed methane systems.
Our aftermarket business provides a wide range of services and compressor package parts and components manufactured by third-party suppliers to support the needs of customers who own compression equipment. These services include operations, maintenance, overhaul, and reconfiguration services and may be provided under turnkey engineering, procurement and construction contracts. Our aftermarket services are provided by our factory- and internally trainedinternally-trained technicians in most of the major oil and natural gas producing basins in the United States.States and Mexico.
Our long-term growth strategy includes expanding our existing businesses through organic growth and accretive acquisitions, both domesticin the U.S. and international.internationally.
Our operations are organized into a single business segment. See "Note 13Note 16 - Segments"“Segments” in the Notes to Consolidated Financial Statements in this Annual Report for further information. For financial information regarding our revenues and total assets, see "Note 14Note 17 - Geographic Information"“Geographic Information” contained in the Notes to Consolidated Financial Statements in this Annual Report.
Contribution of Spartan entities
On November 10, 2021, the Partnership entered into a Contribution Agreement (the “Contribution Agreement”) by and among the Partnership, CSI Compressco GP, Spartan, and CSI Compressco Sub Inc., a Delaware corporation (“Compressco Sub”). Pursuant to the terms of the Contribution Agreement, Spartan contributed to the Partnership 100% of the limited liability company interest in Treating Holdco, LLC, a Delaware limited liability company (“Treating Holdco”), 100% of the common stock in Spartan Terminals Operating, Inc., a Delaware corporation (“Spartan Terminals”), and 99% of the limited liability company interests in Spartan Operating Company LLC, a Delaware limited liability company (“Spartan Operating” and together with Treating Holdco and Spartan Terminals, “Spartan Treating”) (such interests in Spartan Treating, the “Contributed Interests”) and the Partnership, CSI Compressco GP and Spartan agreed to cancel the incentive distribution rights (the “IDRs”) in the Partnership in exchange for the issuance of 48.4 million common units. We refer to the acquisition of the Contributed Interests as the “Spartan Acquisition.” As the Partnership and Spartan Treating were under common control at the time of the Spartan Acquisition, the results of operations have been combined for the Partnership and Spartan Treating from the date of common control which was January 29, 2021.
Certain of our domesticU.S. services are performed by our wholly owned subsidiary CSI Compressco Operating LLC, a Delaware limited liability company (our “Operating LLC”), pursuant to contracts that our outside legal counsel has concluded generate qualifying income under Section 7704 of the Internal Revenue Code of 1986, as amended (the “Code”), or “qualifying income.” We do not pay U.S. federal income taxes on the portion of our business conducted by Operating LLC. CSI Compressco Sub, Inc., which is also a wholly owned subsidiary of ours, conducts substantially all of our operations that our outside legal counsel has not concluded generate qualifying income, and we pay U.S. federal income tax with respect to such operations. We strive to ensure that all new domesticU.S. compression contracts are entered into by our Operating LLC and generate qualifying income. We also pay state and local income taxes in certain states, and we incur income taxes related to our foreign operations.
As a limited partnership, we are managed and controlled by our general partner. For the year ended December 31, 2020, our general partner was a wholly owned subsidiary of TETRA. On January 29, 2021, Spartan acquired from TETRA our general partner, our IDRs and 10.95 million of our common units in the Partnership (the “GP Sale”). As of March 10, 2022, common units held by the public represented approximately a 50.9% ownership interest, which is exclusive of Spartan’s 45.0% limited partner interest and 0.5% general partner interest, and TETRA’s 3.7% limited partner interest. In connection with the GP Sale, on January 29, 2021, TETRA entered into a Transition Services Agreement (the “Transition Services Agreement”) with the Partnership, pursuant to which TETRA provided certain accounting, information technology and back office support services to the Partnership for a period of one year following closing. The Transition Services Agreement with TETRA expired on January 31, 2022.
Through TETRA’sSpartan’s wholly owned subsidiary and our general partner, CSI Compressco GP Inc., TETRALLC, Spartan manages and controls us. We rely on our general partner’s board of directors and executive officers to manage our operations and make decisions on our behalf. Our general partner is an indirect, wholly owned subsidiary of TETRA.Spartan. Unlike shareholders in a publicly traded corporation, our unitholders are not entitled to elect our general partner or its directors. AllFollowing the GP Sale, all of our general partner’s directors are elected by TETRA.Spartan. Our general partner does not receive any management fee in connection with its management of our business. However, our general partner is reimbursed for certain expenses, including compensation expenses, incurred on our behalf. In addition, our general partner receives distributions based on its limited and general partner interests and incentive distribution rights. As of December 31, 2019, common units held by the public represent approximately a 65.6% ownership interest in us.interests.
Products and Services
We are a provider of contract services including natural gas compression services and equipment for natural gas and oil production, gathering, artificial lift, transmission, processing, and storage.treating services. Natural gas compression is a mechanical process in which the pressure of a given volume of natural gas is increased to a higher pressure. It is essential to the production and movement of natural gas. Compression is typically required numerous times in the natural gas production and sales cycle, including (i) at the wellheads, (ii) throughout gathering and distribution systems, (iii) into and out of processing and storage facilities, and (iv) in natural gas pipelines. Compression is also utilized for gas lift, an artificial lift technique for producing oil that has insufficient reservoir pressure. We fabricateNatural gas treating encompasses several processes used to remove contaminants and sell both standard compressor packages and custom-designed, engineered compressor packages.improve the marketability of gas. We also provide aftermarket compression services and compressor package parts and components manufactured by third-party suppliers.
Contract Services
We use our fleet of compressor packages to provide a variety of compression services to our customers to meet their specific requirements. Our fleet includes approximately 5,2004,800 compressor packages that provide approximately 1.2 million in aggregate horsepower, employing a wide spectrum of low-, medium-, and high-horsepower engines. We fabricate our compressor packages primarily at our facility in Midland, Texas. The horsepower of our natural gas compressor package fleet as of December 31, 20192021 is summarized in the following table:
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| | | | | | | | | |
| Range of Horsepower Per Package | | Number of Packages | | Aggregate Horsepower | | % of Aggregate Horsepower |
| | | | | | | |
| Low horsepower (0-100) | | 3,265 |
| | 153,062 |
| | 13.0 | % |
| Medium-horsepower (101-1,000) | | 1,554 |
| | 436,058 |
| | 37.0 | % |
| High-horsepower (1,001 and over) | | 426 |
| | 588,625 |
| | 50.0 | % |
| Total | | 5,245 |
| | 1,177,745 |
| | 100.0 | % |
| | | | | | | | | | | | | | | | | | | | |
| Range of Horsepower Per Package | | Number of Packages | | Aggregate Horsepower | | % of Aggregate Horsepower |
| | | | | | |
| Low-horsepower (0-100) | | 2,936 | | | 138,982 | | | 12 | % |
| Medium-horsepower (101-1,000) | | 1,438 | | | 409,290 | | | 34 | % |
| High-horsepower (1,001 and over) | | 459 | | | 648,570 | | | 54 | % |
| Total | | 4,833 | | | 1,196,842 | | | 100 | % |
Low-Horsepower (0-100 Horsepower) Compression Services. Our natural gas-powered, low-horsepower compressor packages include our GasJack® compressor packages that are relatively compact and easy to transport to our customer’s well site. We utilize our electric powered, low-horsepower VJack™ compressor packages to provide production enhancement services on wells where electric power is available. Our low-horsepower packages allow us to perform wellhead compression, fluids separation, and optional gas metering
services all from one skid, thereby providing services that otherwise would generally require the use of multiple, more costly pieces of equipment. We utilize our low-horsepower compressor packages to provide production enhancement for dry gas wells and liquid-loaded gas wells and backside auto injection systems (“BAIS”). BAIS monitors tubing pressure to redirect gas flow into the casing annulus as needed to help gas wells unload liquids that hinder production. We also utilize our low-horsepower compressor packages to collect hydrocarbon vapors that are a by-product of oil production and storage (“vapor recovery”) and to reduce casing pressure of pumping oil wells to enhance oil production (“casing gas systems”).
Medium-horsepower (101-1,000 Horsepower) Compression Services. Our medium-horsepower compressor packages are primarily utilized to move natural gas from the wellhead through the field gathering system by boosting the pressure of the natural gas flowing through the system. Additionally, these compressor packages are used to reinject natural gas into producing vertical and horizontal oil wells that have insufficient reservoir pressure, to help lift liquids to the surface ("(“gas lift operations"operations”). Typically, these applications require medium-horsepower compressor packages located at or near the wellhead. These compressor packages are also used to increase the efficiency of low-capacity natural gas fields by providing a central compression point from which the natural gas can be further processed and transported. These compressor packages feature primarily two- and three-stage compressors powered by natural gas engines ranging from 101 to 1,000 horsepower and equipped with interstage cooling.
High-Horsepower (Over 1,000 Horsepower) Compression Services. Our high-horsepower compressor packages are primarily utilized in midstream applications including natural gas gathering, gas lift, and centralized compression facilities. They boost the pressure of natural gas flowing from individual wells or a group of wells into a gathering pipeline that leads to various types of processing facilities. A significant number of these compressor packages in midstream applications also serve the dual purpose of gas lift operations by injecting a percentage of the compressed natural gas into producing oil wells. Our high-horsepower compressor packages are also used in connection with the transmission of natural gas from gathering systems to storage facilities or end users. These compressor packages feature primarily two- and three-stage compressors powered by natural gas engines.
Gas Treating. We provide a variety of natural gas treating services for natural gas producers and midstream companies, such as providing equipment for lease or sale, equipment installation services and the operation of equipment which Spartan Treating refers to as contract services. Spartan Treating’s two primary gas treating services provided for customers are the removal of contaminants from the customer’s gas stream and natural gas cooling to reduce the gas temperature. Spartan Treating maintains a fleet of amine plants ranging in size used to treat varying customer gas flow volumes by removing hydrogen sulfide and carbon dioxide to meet required pipeline specifications. Additionally, Spartan Treating’s equipment fleet includes natural gas cooling units used to reduce the temperature of natural gas so that it can be further treated, processed or compressed.
Other Related Services. In certain Latin America markets,Mexico, we provide well monitoring and sand separation services in connection with our compression services. Well monitoring services include a variety of services that monitor and optimize production from oil and gas wells. We utilize automated sand separators, which are high-pressure vessels with automated valve operation functions, at the well to remove solids that would otherwise cause abrasive wear damage to compression and other equipment that is installed downstream and inhibit production from the well.
CompressionContract Services Contract Terms. Our compressioncontract services are primarily performed under service contracts using our low-, medium-, and high-horsepower compressor packages.packages and our treating assets. A significant portion of these compression services are provided under services contracts that our outside legal counsel has concluded generate qualifying income that is not subject to U.S. federal income taxes.income. Under these services contracts, we are responsible for providing our services in accordance with the particular specifications of a job. As owner and operator, we are responsible for operating and maintaining the equipment we utilize to provide our services. Our low horsepower compression service contracts typically have an initial term of one month and, unless terminated by us or our customers with 30-days'30-days’ notice, continue on a month-to-month basis thereafter. Our medium- and high- horsepower compression service and treating contracts typically have an initial term of twelve months, but range from six months to twenty-fourthirty-six months. After the initial terms on our medium- and high-horsepower compression service and treating contracts, customers typically continue on a month-to-month basis or renew for additional extensions. We charge our customers a fixed monthly fee for the services provided under the services contracts. IfAside from factors beyond our control, if the level of services we provide falls below certain contractually specified percentages, other than as a result of factors beyond our control, our customers are generally entitled to request limited credits against our service fees. To date, these credits have been insignificant as a percentage of revenue.
We generally own the equipment we use to provide services to our customers, and we bear the risk of loss to this equipment to the extent not caused by (i) a breach of certain obligations of the customer, primarily involving the service site and the fuel gas being supplied to us, or (ii) an uncontrolled well condition. Utilizing our proprietary, satellite telemetry-based reporting system, which is included on most of our equipment, we remotely monitor, in real time, whether our services are being continuously provided at our domesticU.S. customer well sites.
As owner of the equipment, we are obligated to pay ad valorem taxes levied on the equipment and related insurance expenses, and we do not seek reimbursement for such taxes and expenses from our service agreement customers.
Equipment and Parts SalesAftermarket Services
We fabricate and sell natural gas compressor packages for various applications, including: gas gathering, gas lift, carbon dioxide injection, wellhead compression, gas storage, refrigeration plant compression, gas processing, pressure maintenance, pipeline transmission, vapor recovery, pipeline station optimization, gas transmission, fuel gas boosters, and coal bed methane systems.
Aftermarket Business
Through our aftermarket operations, we provide a wide range of services to support the needs of customers who own compression equipment. The services provided are primarily operation, maintenance, overhaul and reconfiguration services, which may be provided under turnkey engineering, procurement and construction contracts. We also sell engine parts, compressor package parts and other parts manufactured by third parties that are utilized in natural gas compressor packages. We have factory- and internally trainedinternally-trained technicians in most of the major oil and natural gas producing basins in the United States to perform these services.
Compressor Package Fabrication Facilities and Sources of Raw Materials
At our fabrication facility in Midland, Texas, we design, fabricate, and assemble natural gas reciprocating and rotary compressor packages up to 8,000 horsepower, including both standard field compression equipment meeting industry standards and specially engineered compression equipment designed for unique customer specifications. We internally fabricate skids, pressure vessels built to American Society of Mechanical Engineers code, and piping systems and integrate them with engines, compressors and other components obtained from third-party suppliers. The compressor packages are used in our services business or they are sold to major and independent oil and natural gas exploration and production companies as well as midstream processing and transmission companies. We design, engineer, fabricate, assemble, and market high-quality gas compressor packages that have a superior reputation in the industry as evidenced by occasional sales to competitive fleets and to end users who have their own compressor package fabrication capabilities.
A majority of the components we use to fabricate compressor packages are obtained from third-party suppliers. These components represent a significant portion of the cost of the compressor packages. Some of the components used in the assembly of our compressor packages are obtained from a single supplier or a limited group of suppliers. Typical contracts with these suppliers are for a period of twelve months. Should we experience a lack of availability of the components we use to fabricate our packages and systems, we believe that there are adequate, alternative suppliers and that any impact would not be severe, although short-term disruptions could be material. We occasionally experience long lead times for components from suppliers and, therefore, at times make purchases in anticipation of future orders.
Market Overview and Competition
Our operations are significantly dependent upon the demand for, and production of, oil and the associated natural gas from unconventional oil production along with natural gas production in the domesticU.S. and international markets in which we operate. BeginningThe COVID-19 pandemic, along with oil supply disruptions from certain oil-producing nations, drove a significant drop in 2017oil demand and continuingoil prices in 2020, resulting in unprecedented production curtailments, negatively impacting demand for compression and related services. Amidst the challenging and uncertain market conditions, our customers drastically reduced capital budgets and took actions to reduce operating expenses. During the second quarter of 2020, customers released compression that was in excess of previously anticipated needs and on wells deemed uneconomic to produce at the lower commodity price levels. Commodity prices stabilized in the third and fourth quarters of 2020 and gained strength throughout all2021. This improvement in commodity prices, as well as the beginning of 2019, shale production for oila recovery in the general economy and the associated natural gas producedenergy sector, have resulted in an increase in activity levels from our contract services and aftermarket services customers. Revenue from contract services has increased each quarter in 2021. In addition, we secured orders from key customers for new high-horsepower compressors that started generating revenues in the fourth quarter of 2021 and will continue to be deployed in the first half of 2022. Our customers continue to be focused on capital discipline; however, we continue to see improvement in the levels of quote activity and awards. As the market environment continues to evolve, competition for field employees has increased and inflationary pressures have driven certain costs higher. In
addition, supply chain disruptions have impacted the availability of parts and supplies. We will continue to monitor these wells provided improved compression demand opportunities for our productsrisks and services. Further, overtake the same period, the shiftnecessary actions to gas lift as a preferred lifting method improved demand for our complete range of product offerings.mitigate them.
Customers
We provide services to a broad base of natural gas and oil exploration and production, midstream, pipeline transmission, and storage companies operating throughout many of the onshore producing regions of the United States. We also have operations in Latin AmericaCanada, Mexico, Argentina, Egypt and certain other regions outside of the United States.Chile. While most of our domestic services in the U.S. are performed throughout Texas (with a concentration in the Permian Basin), the Haynesville shale, the San Juan Basin, the Rocky Mountain region, and the Mid-Continent region, of the United States, we also have a presence in
the Marcellus / Utica and other producing regions. We continue to seekevaluate opportunities to further expand our operations into other regions in the United StatesU.S. and elsewhere in the world.
Our service contracts are generally terminable uponthirtydays’notice after Following the expiration of the primary term, has expired.our service contracts generally continue month to month until terminated upon thirty days’ notice. Our low-horsepower compression fleet is generally deployed on short-term contracts while our medium- and high-horsepower fleet is generally deployed with an initial term of 12 months or greater. Although we enter into short-term contracts, many of our largest customers have beenthe average duration a typical unit stays deployed with us for over five years.the same customer is greater than 30 months. Our significant customers for the year ended December 31, 20192021 include various major integrated oil companies, public and private independent exploration and production companies and midstream companies, noneone of which individually accounted for more than 10% of our consolidated revenues for the year ended December 31, 2019.2021. The loss of any of our major customers could have a material adverse effect on our business, results of operations, financial condition, and our ability to make cash distributions to our unitholders.
Competition
The natural gas compression services and compressor package fabrication and sale businesses arebusiness is highly competitive. We experience competition from 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 technologies, and adopt more aggressive pricing policies. Primary competition for our low-horsepower compression services business comes from smaller local and regional companies that utilize packages consisting of a screw or reciprocating compressor with a separate engine driver. These local and regional competitors tend to compete with us on the basis of price and availability, as opposed to our focus of adding value to the customer. Competition for our medium- and high-horsepower compression services business comes primarily from large companies that may have greater financial resources than we do. Such competitors include Archrock Compression Services, Kodiak Gas Services, USA Compression Partners and Natural Gas Compression Systems, Inc. Competitors for natural gas treating contract services include USA Compression. Our competition in the standard compressor package fabricationCompression Partners and sale markets includes several large companies and a large number of small, regional fabricators, including some of those with whom we also compete for compression services, including Enerflex, Exterran and others. Our competition in the custom-designed, engineered market generally consists of larger companies with the ability to provide integrated projects and product support after the sale, including some of the competitors noted above. The ability to fabricate these large custom-designed, engineered packages at our facilities near the point of end-use of many customers is often a competitive advantage.Kinder Morgan.
Many of our compression services competitors compete on the basis of price. We believe our pricing has proven to be competitive because of the significant increase in value that results from use of our services, our customer service, trained field personnel, and the quality of the compressor packages we use to provide our services.
Other Business Matters
Marketing
We use various marketing strategies to promote our services and compressor package products. Our account managers attemptwork to build close working relationships with our existing and potential future customers, to educateeducating them about our services and products by scheduling personal visits, hosting and attending workshops, tradeshows and conferences, and participating in industry organizations. We sponsor and make presentations at industry events that are targeted to production managers, compression specialists and other decision makers. Our marketing representatives also use these marketing opportunities to promote our value-added service initiatives, such as the use of our proprietary satellite telemetry-based system, our wellsite optimization program and our callfleet reliability center.
BacklogHuman Capital Management
Our equipmentWe collaborate as a team to execute for each other, our customers, and parts sales business includes the design, fabrication, assembly, and sale of both standard compressor packages and custom-designed, engineered compressor packages. Our custom-designed, engineered packages are typically greater in size and scope than standard fabrication packages, requiring more labor, materials, and overhead resources. This business requires diligent planning of those resources and project and backlog management in order to meet the customer's desired delivery dates and performance criteria, and achieve fabrication efficiencies. As ofour shareholders. On December 31, 2019, our equipment sales backlog was $35.5 million, compared to $105.2 million as of December 31, 2018, all of which is expected to be recognized in the year ended December 31, 2020.2021, we employed approximately 817 people worldwide. Our new equipment sales backlog consists of firm customer orders for which a purchase or work order has been received, satisfactory credit or financing arrangements exist, and target delivery dates have
been established based on customer requirements. Our new equipment sales backlog is a measure of overall demand that allows us to plan future labor and raw material needs and measure our success in winning bids from our customers.
Employees
As of December 31, 2019,our general partner and certain of our subsidiarieshadapproximately 791 full-timeemployeeswho provideservices to conduct our operations. Our general partner’s U.S. employees and our employees in Canada and Egypt are not subject to collective bargaining agreements. Under our Omnibus Agreement with TETRA, certain employees of TETRA and its affiliates also provide services to our general partner, us and our subsidiaries, and we reimburse TETRA for these services. Our employees in Argentina and Mexico are subject to collective bargaining agreements. The employees of TETRA who provide services to us in Argentina and Mexico are
subject to collective bargaining agreements. We believe that the various employers of these employees have good relations with these employees and we have not experienced work stoppages in the past.
Diversity and Inclusion
The diversity of our global workforce stimulates creativity and innovation as we use our collective talents to develop unique solutions to address the world's energy challenges. We seek to attract, retain, develop, and reward a high-performing and diverse workforce. To that end, we sponsor training activities to share best practices concerning diversity and inclusion education.
Career Development
Our executive team evaluates executive development and succession planning to prepare us for future success. The succession planning process covers all senior management positions and certain other key positions. This review of executive talent determines readiness to take on additional leadership roles and identifies developmental opportunities needed to prepare our executives for greater responsibilities. Our short and long-term business strategy is considered when evaluating candidates and their skills.
Compensation and Benefits
Our compensation programs are designed to incentivize performance, maximize returns, and build unitholder value. We work with consultants to benchmark our compensation and benefits programs to help us offer competitive compensation packages to attract and retain high-performing talent. We also offer competitive benefits to attract and retain exceptional talent.
Safety
Recognizing that safety, service quality, and environmental protection are conditions of employment, all employees and contractors are responsible for their safety, the safety of those around them, the quality of their work, and protection of the environment. As part of our safety-focused culture, it is customary that each meeting starts with an employee-led safety moment.
To ensure our work remains safe and of the highest quality, we have a comprehensive HSEQ Management System and program designed to improve the capacity of the organization by controlling worksite risks, developing proper work practices and procedures, and empowering employees with stop-work authority if they observe unsafe conditions, omissions, errors, or actions that could result in safety or environmental incidents, or product and service quality issues. If an incident takes place, we investigate all serious occurrences to root causes and implement corrective actions to ensure we expand our capacity to operate safely.
Driving is one of the highest exposure activities that we undertake in our day-to-day operations. We maintain a fleet of DOT and non-DOT vehicles and provide positive, real-time behavior feedback to our drivers via real-time monitors. Coupled with vehicle selection guidelines, and driver training, we have a comprehensive approach to reducing our driving exposure and incidents.
Proprietary Technology and Trademarks
It is our practice to enter into confidentiality agreements with employees, consultants, and third parties to whom we disclose our confidential and proprietary information. There can be no assurance, however, that these measures will prevent the unauthorized disclosure or use of our trade secrets and expertise or that others may not independently develop similar trade secrets or expertise. Our management believes, however, that it would require a substantial period of time and substantial resources to independently develop similar know-how or technology.
We sell various services and products under a variety of trademarks and service marks, some of which are registered in the United States.
Health, Safety, and Environmental Affairs Regulations
We believe that ourOur service and sales operations are subject to stringent and fabricating plants are in substantial compliance with all applicablecomplex U.S. and foreign health, safety, and environmental laws and regulations. Weregulations, and, although we are committed to conducting all of our operations under the highest standards of safety and respect for the environment. However,environment, risks of substantial costs and liabilities pursuant to laws
and regulations are inherent in certain of our operations. Because of these risks, there can be no assurance that significant costs and liabilities will not be incurred now or in the future. Changes in health, safety, and environmental laws and regulations could subject us to more rigorous standards and could affect demand for our customer'scustomer’s product which in turn would impact demand for our products. We cannot predict the extent to which our operations may be affected by futureany changes to existing laws, regulations, and enforcement policies.policies, new interpretations of existing laws, regulations, and policies, or any new laws, regulations, or policies promulgated in the future.
We are subject to numerous federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of human health and the environment. The primary environmental laws that impact our operations in the United StatesU.S. include:
•the Clean Air Act ("CAA"(“CAA”) and comparable state laws and regulations thereunder, which regulate air emissions;
•the Federal Water Pollution Control Act of 1972 (the "Clean“Clean Water Act"Act”) and comparable state laws, and regulations thereunder, which regulate the discharge of pollutants into regulated waters, including industrial wastewater discharges and storm water runoff;
•the Resource Conservation and Recovery Act or (“RCRA”), and comparable state laws and regulations thereunder, which regulate the management and disposal of solid and hazardous waste; and
•the federal Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA” or (“CERCLA”“Superfund”), and comparable state laws, and regulations thereunder, known more commonly as “Superfund,” which impose liability for the cleanup of releases of hazardous substances in the environment.
Our operations in the United StatesU.S. are also subject to regulation under the Occupational Safety and Health Act ("OSHA"(“OSHA”) and comparable state laws, and regulations thereunder, which regulate the protection of the health and safety of workers.
The CAA and implementing regulations, and comparable state laws and regulations, regulate emissions of air pollutants from various industrial sources and also impose various monitoring and reporting requirements, including requirements related to emissions from certain stationary engines, including our compressor packages. These laws and regulations impose limits on the levels of various substances that may be emitted into the atmosphere from our compressor packages and require us to meet more stringent air emission standards and install new emission control equipment on all of our engines built after July 1, 2008. Our compressor packages may be subject to additional regulatory requirements under the CAA. For example,In addition, regulations under the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) provisions of the CAA require control of hazardous air pollutants from new and existing stationary reciprocal internal combustion engines. Our equipment is also subject to additional prescribed maintenance practices and catalyst installation may also be required. More recently,Furthermore, in June 2016, the EPAEnvironmental Protection Agency (“EPA”) finalized rules that establish new air emission controls under the EPA'sEPA’s New Source Performance Standards ("NSPS"(“NSPS”) and NESHAP for natural gas and natural gas liquids production, processing and transportation activities. These rules establish specific requirements associated with volatile organic compounds and methane emissions from compressor packages and controllers at natural gas gathering and boosting stations. However, these rules areWhile the subject of a recently proposed rule modifying or removing certain requirements. In addition,EPA under the Environmental Protection Agency ("EPA") issued regulations in April 2012 that require the reduction of emissions of volatile organic compounds, air toxins, and methane, a greenhouse gas, at certain oil and gas operations. The current administration has proposedTrump Administration finalized rules to removerescind or modify certain of these requirements in September 2020, including removing sources in the transmission and storage segment from the source category and rescinding the methane-specific requirements applicable to sources in the production and processing segments of the oil and gas industry, various states and industry and environmental groups are separately challenging the EPA’s June 2016 standards and its September 2020 final rule. However, the U.S. Congress passed, and President Biden signed into law, a revocation of the 2020 rulemaking effectively reinstating the 2016 standards. Additionally, in November 2021, the EPA issued a proposed rule that, if finalized, would establish OOOOb new source and OOOOc first-time existing source standards of performance for GHG and volatile organic compound (“VOC”) emissions for crude oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities. Owners or operators of affected emission units or processes would have to comply with specific standards of performance that may include leak detection using optical gas imaging and subsequent repair requirements, reduction of emissions by 95% through capture and control systems, zero-emission requirements, operations and maintenance requirements, and so-called “green well” completion requirements. WeThe EPA plans to issue a supplemental proposal enhancing this proposed rulemaking in 2022 that will contain proposed rule text, which was not included in the November 2021 proposed rule, and anticipates issuing a final rule by the end of 2022. While we are not currently aware of any material impacts to our operations associated with these rules.
The EPA has determined that greenhouse gases ("GHGs"(“GHGs”) present an endangerment to public health and the environment because, according to the EPA, they contribute to global warming and climate change. As a result, the EPA has begun to regulate certain sources of GHGs, including air emissions associated with oil and gas production particularly as they relate to the hydraulic fracturing of natural gas wells. In addition, the EPA has issued regulations requiring the reporting of GHG emissions from certain sources including onshore and offshore oil and natural gas production facilities and onshore oil and gas processing, transmission, storage, and distribution facilities. Reporting of GHG emissions from such facilities is required on an annual basis. The EPA’s rules relating to emissions of GHGs from large stationary sources of emissions have been the subject of a number of legal challenges. TheseWhile these rules have also beenwere the subject of EPA's currentEPA’s recent deregulatory agenda whichunder the Trump Administration, the EPA under the Biden Administration is expected to reconsider any relaxation of such rules, and potentially impose more stringent GHG emissions requirements from large stationary sources, as President Biden has resulted in further legal challengesissued executive orders that commit to attemptssubstantial action on climate change and the reduction of GHG emissions, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to modify these rules.the fossil fuel industry, and an increased emphasis on climate-related risk across government agencies and economic sectors. Further, Congress has considered, and almost one-half of the states have adopted, legislation that seeks to control or reduce emissions of GHGs from a wide range of sources.
The Clean Water Act and implementing regulations, and comparable state laws and regulations, prohibit the discharge of pollutants into regulated waters without a permit and establish limits on the levels of pollutants contained in these discharges. In addition, the Clean Water Act and other comparable laws and regulations regulate storm water discharges associated with industrial activities depending on a facility’s primary standard industrial classification. Our facilities are in compliance with these requirements, as applicable.
RCRA and implementing regulations, and comparable state laws and regulations, address the management and disposal of solid and hazardous waste. These laws and regulations govern the generation, storage, treatment, transfer, and disposal of wastes including, but not limited to, used oil, antifreeze, filters, sludges, paint, solvents and sandblast materials. The EPA and various state agencies have limited the approved methods of disposal for these types of wastes. We believe we are in substantial compliance with all applicable requirements.
CERCLA and comparable state laws and regulations impose strict, joint, and several liabilities 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 or operator of a disposal site where a hazardous substance release occurred and any company that transported, disposed of, or arranged for the transport or disposal of such hazardous substances released at a 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.
We Although we believe that we have properly disposed of all historical waste streams and that we have no outstanding liability regarding any past waste handling or spill activities; however,activities, there is always the possibility that future spills and releases of petroleum hydrocarbons, wastes, or other regulated substances into the environment could cause us to become subject to remediation costs and liabilities under CERCLA, RCRA, or other environmental laws. The costs and liabilities associated with the future imposition of remedial obligations could have the potential for a material adverse effect on our operations or financial position.
We are also subject to the requirements of OSHA and comparable state statutes. These laws and regulations 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 maintain and/or disclose information about hazardous materials used or produced in our operations. We
While we do not believe that we are in substantial compliance with theseexisting requirements under applicable U.S. environmental laws and other applicable similar laws.regulations will have a material adverse effect on our business and results of operations, we cannot guarantee that we will not incur substantial costs now or in the future with respect to compliance with or liability under such laws and regulations.
We design, fabricate, and assemble our compressor packages to meet applicable customer and government regulatory health, safety, and environmental requirements. Our operations outside the United StatesU.S. are subject to foreign governmental laws and regulations relating to health, safety, and the environment and other regulated activities. WeWhile we do not believe that our operations are in substantial compliance with existing foreign governmentalenvironmental laws and regulations will have a material adverse effect on our business and results of operations, we cannot guarantee that we will not incur substantial costs now or in the future with respect to compliance with or liability under such foreign laws and regulations.
Related Party Agreements
Under our OmnibusIn connection with the Contribution Agreement, with TETRA,the Partnership entered into a Management Services Agreement, dated November 10, 2021, by and among the Partnership, our general partner, providesSpartan, Spartan Energy Partners GP LLC, the general partner of Spartan (“Spartan GP”), and Spartan Operating (the “Management Services Agreement”). Under the terms of the Management Services Agreement, our general partner, Spartan Operating and Spartan GP will provide certain services reasonably necessary for the operation of the businesses of the Partnership and its subsidiaries, Spartan, Spartan GP and Spartan Treating, including certain corporate and general and administrative services. Pursuant to the Management Services Agreement, our general partner and Spartan GP will allocate any costs and expenses incurred on a reasonable basis, and the parties will reimburse such other parties for costs and expenses allocated to them.
Prior to the acquisition of our general partner by Spartan on January 29, 2021, TETRA provided all personnel and services reasonably necessary to manage our operations and conduct our business other than in Mexico and Argentina, and certain of TETRA’s Latin American subsidiaries provideprovided personnel and services necessary for the conduct of certain of our Latin American business. In addition, underbusiness pursuant to the Omnibus Agreement. The Omnibus Agreement terminated upon the closing of the GP Sale. In connection with the acquisition of our general partner by Spartan, the Partnership entered into a Transition Services Agreement with TETRA providesthrough which TETRA provided certain corporate and general and administrative services requested by our general partner including certain legal, accounting and financial reporting, treasury, insurance administration, claims processing and risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit and tax services. Pursuant to the Omnibus Agreement, we reimburse our general partner and TETRA and its subsidiaries for services they provide to us. At various times, we and TETRA have agreed that our reimbursement for corporate general and administrative services performed by TETRA would be paid using common units rather than cash, and that interest is to be paid on any past due balances. We may sometimes refer herein to the personnel of our general partner and TETRA and its subsidiaries who provide services for the conduct of our business as “our personnel” or other similar references.up to one year. The Transition Services Agreement with TETRA expired on January 31, 2022.
Under the Omnibus Agreement, we or TETRA may, but neither of us is under any obligation to, perform for the other such production enhancement or other oilfield services on a subcontract basis as are needed or desired by the other, for such periods of time and in such amounts as may be mutually agreed upon by TETRA and our general partner. Any such services are required to be performed on terms that are (i) approved by the conflicts committee of our general partner’s board of directors, (ii) no less favorable to us than those generally being provided to or available from non-affiliated third parties, as determined by our general partner, or (iii) fair and reasonable to us, taking into account the totality of the relationships between TETRA and us (including other transactions that may be particularly favorable or advantageous to us), as determined by our general partner.
Under the Omnibus Agreement, we or TETRA may, but neither of us is under any obligation to, sell, lease, or like-kind exchange to the other such production enhancement or other oilfield services equipment as is needed or desired, in such amounts, upon such conditions, and for such periods of time, as may be mutually agreed upon by TETRA and our general partner. Any such sales, leases, or like-kind exchanges are required to be on terms that are (i) approved by the conflicts committee of our general partner’s board of directors, (ii) no less favorable to us than those generally being provided to or available from non-affiliated third parties, as determined by our general partner, or (iii) fair and reasonable to us, taking into account the totality of the relationships between TETRA and us (including other transactions that may be particularly favorable or advantageous to us), as determined by our general partner. In addition, TETRA may purchase newly fabricated equipment from us at a negotiated price provided that such price may not be less than the sum of the total costs (other than any allocations of general and administrative expenses) incurred by us in fabricating such equipment plus a fixed margin percentage thereof, and TETRA may purchase from us previously fabricated equipment for a price that is not less than the sum of the net book value of such equipment plus a fixed margin percentage thereof, unless otherwise approved by the conflicts committee of our general partner’s board of directors.
The Omnibus Agreement, as amended in June 2014 to extend its term, will terminate (other than the indemnification obligations contained therein) upon the earlier to occur of a change of control of the general partner or TETRA or upon either party providing at least 180 days' prior written notice of termination.
In addition to the Omnibus Agreement, we have entered into other operational agreements with TETRA. For a more comprehensive discussion of the Omnibus Agreement and other agreements we have entered into with TETRA,related parties, please see “Item 13 - Certain Relationships and Related Transactions, and Director Independence.”
Item 1A. Risk Factors.
Certain Business Risks
Although it is not possible to identify all of the risks we encounter, we have identified the following significant risk factors that could affect our actual results and cause actual results to differ materially from any such results that might be projected, forecasted, or estimated by us in this Annual Report.
We depend on domesticand international demand for and production of oil and natural gas, and a reduction in this demand or production could adversely affect the demand or the prices we charge for our services, which could cause our revenue and cash available for distribution to our unitholders to decrease.
Our operations are significantly dependent upon the demand for, and production of, oil and natural gas in the various domesticU.S. and international markets in which we operate. Oil and natural gas production rates are volatile and may be affected by, among other factors, prices for such commodities, market uncertainty, weather and availability of alternative energy sources.
Although oil Oil prices steadily rose during late 20172020 and early 2018, they fell during2021 with a slight decrease in late 2018, with 20182021. West Texas Intermediate oil prices dropping fromreached a high of $76.90$85.64 per barrel in October 2018 to2021 and a low of $42.36$47.47 per barrel in December 2018.January 2021. The West Texas Intermediate price averaged $57.05$68.14 per barrel during 2019.2021. Over this same period, U.S. natural gas prices have also been volatile, with the Henry Hub price ranging from a high of $4.93$23.86 per million British thermal units ("MMBtu") in November 2018February 2021, due to a supply shortage as a result of colder-than-normal weather leading to higher demand and temporary interruptions in production, to a low of $2.03$2.43 per MMBtu in August 2019. Beginning in February 2020, there has been a severe drop in theApril 2021. The Henry Hub price of oil.averaged $3.89 per MMBtu during 2021. As of March 12, 2020,7, 2022, the price of West Texas Intermediate oil was $31.50$119.26 per barrel andbarrel. As of March 8, 2022, the Henry Hub price for natural gas was $1.84$4.61 per MMBtu. Despite the previousThe prolonged volatility of oil prices, demand for medium- and high-horsepower compression services and equipment has remained strong; however, we anticipate that the recent significant decline in oil prices will have some impact on demand for our compression services and equipment. Demand for low-horsepower compression services used for natural gas production enhancement remains challenged. If the drop in oil and natural gas prices and persisting supply and demand imbalances have impacted the levels of exploration, development, and production activity. If oil and natural gas prices decline significantly like we have experienced in 2020, continues or further declines, thisand the supply and demand imbalance persists, there would be a material adverse effect on our business, consolidated results of operations, and consolidated financial condition. Should
current market conditions worsen for an extended period of time, we may negatively impact the operating cash flows and exploration and development activities and plans of many of our customers andbe required to record additional asset impairments. Such potential impairment charges could have a negativematerial adverse impact on the demand for our compression products and services.operating results.
Factors affecting the prices of oil and natural gas include: the levels of supply and demand for oil and natural gas, worldwide; governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves; weather conditions, natural disasters, and health or similar issues, such as pandemics or epidemics; worldwide political, military, and economic conditions; the ability or willingness of the Organization of Petroleum Exporting Countries ("OPEC") and non-OPEC countries, such as Russia, to set and maintain oil production levels; the levels of oil production in the U.S. and by other non-OPEC countries; oil refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas; the cost of producing and delivering oil and natural gas; and acceleration of the development of, and demand for, alternative energy sources.
The recent announcement by Saudi ArabiaCOVID-19 pandemic has had, or may in the future have, certain negative impacts on our business, and such impacts have had, or may in the future have, an adverse effect on our business, our financial condition, results of operations, or liquidity.
In 2020, the COVID-19 pandemic and the resulting economic impact had a significant reductionnegative impact on the oil and gas industry. The deterioration in its export prices as well as a recent announcementdemand for oil caused by Russia that previously agreed upon production cuts will expirethe pandemic, coupled with oil oversupply had an adverse impact on April 1, 2020, have contributed to the recent significant decline in the price of oil.
The coronavirus (COVID-19) pandemic that began in early 2020 provides an illustrative example of how a pandemic or epidemic can also impactdemand for our operations and business by reducingservices. Although global and national economic activity resulting in a decline in the demand for oil and fornatural gas began to rebound in 2021, a worsening of the pandemic, and the resulting actions that may be taken in the future by governments, various regulatory agencies, our compression servicescustomers and equipment, and affectingour suppliers may in the healthfuture have certain negative impacts on our financial condition, results of our workforce and rendering employees unable to work or travel. The price of oil has fallen significantly since the beginning of 2020, due in part to the factors discussed above and to concerns about the coronavirus (COVID-19) and its impact on the worldwide economy and demand for oil. In addition, if a pandemic or epidemic such as the coronavirus (COVID-19) pandemic were to impact a location where we have a high concentration of business and resources, our local workforce could be affected by such an occurrence or outbreak which could also significantly disrupt our operations, and decrease our ability to provide compression services and equipment to our customers. The duration ofliquidity, including, without limitation, the business disruption and related financial impact from the coronavirus (COVID-19)following:
pandemic cannot be reasonably estimated at this time. If the impact of the coronavirus (COVID-19) pandemic continues for an extended period of time, it could materially adversely affect the •demand for our compression services declining as our customers continue to adjust their operations in response to potentially lower oil and equipmentgas prices and decreased demand for oil and natural gas;
•logistical complications and increased costs adapting our disclosure controls and procedures and our abilityinternal control over financial reporting in a changing environment that includes work-from-home arrangements and furloughs. In the future we may encounter operational challenges or disruptions stemming from the pandemic that require us to operateimplement new or enhanced internal controls to mitigate the risks of operating in a remote environment or increased risks of material misstatements resulting from changes to the business and other uncertainties;
•restrictions on importing and exporting products;
•impacts related to late customer payments and contractual defaults associated with customer and supplier bankruptcies;
•a credit rating downgrade of our businessdebt and potentially higher borrowing costs in the mannerfuture;
•cybersecurity issues, as our network may become more vulnerable to cyberattacks due to increased remote access associated with work-from-home arrangements;
•increased costs associated with possible facility closures to meet expected customer activity levels; and
•we may be required to record significant impairment charges with respect to assets, whose fair values may be negatively affected by the effects of the COVID-19 pandemic on our operations. Also, we may be required to write off obsolete inventory, and such charges may be significant.
The resumption of our normal business operations after the disruptions caused by the COVID-19 pandemic may be delayed or constrained by its lingering effects on the timelines previously planned.oil and gas industry. Any of the negative impacts of the COVID-19 pandemic, including those described above, alone or in combination with others, may have a significant adverse effect on our financial condition, results of operations, or liquidity. Any of these negative impacts, alone or in combination with others, could exacerbate many of the risks discussed elsewhere in these Risk Factors. The full extent to which the coronavirus (COVID-19)COVID-19 pandemic will negatively affect our financial condition, results of operations, or other health pandemics or epidemics may impact our resultsliquidity will depend on future developments whichthat are highly uncertain and cannot be predicted.
We may be unable to repurchase our 7.50% First Lien Notes due 2025 and 10.000%/10.750% Second Lien Notes due 2026 in the event of a change of control as required by their respective indentures.
Holders of our 7.50% First Lien Notes due 2025 (the “First Lien Notes”) and 10.000%/10.750% Second Lien Notes due 2026 (the “Second Lien Notes”) have the right to require us to repurchase their notes at a price equal to 101% of the principal amount, in each case, upon the occurrence of any specified change of control event.
Any change of control also would constitute a default under our Credit Agreement. Therefore, upon the occurrence of a change of control, the lenders under our Credit Agreement would have the right to accelerate the payment obligations with respect to our Credit Agreement, and if so accelerated, we would be required to pay all of our outstanding obligations under our Credit Agreement. We may not be able to repay or repurchase our First Lien Notes and Second Lien Notes at that time because we may not have available funds to repay the debt or pay the repurchase price as applicable. Any requirement to repay or to offer to purchase any outstanding First Lien Notes and Second Lien Notes may result in us having to refinance our outstanding indebtedness, which we may not be able to do. In addition, even if we were able to refinance our outstanding indebtedness, such financing may be on terms unfavorable to us. A change of control under the indentures governing our First Lien Notes and Second Lien Notes could have a material adverse effect on our business, results of operations, and financial condition.
Our current capital structure, along with current debt and equity market conditions, may continue to limit our ability to obtain financing to pursue business growth opportunities.
Conditions in the markets for debt and equity securities in the energy sector have increased the difficulty of obtaining debt and equity financing to grow our business. We expect that the stock market decline beginningvolatility, which started in March 2020 willand continued throughout 2021 and into 2022, may make it more difficult to obtain debt and equity financing in the near future. As of December 31, 2019,2021, the market price for our common units was $2.71$1.19 per common unit, down from the 20192020 high of $3.98$2.70 per common unit during August 2019. Due, in part, to recent stock market decline, theunit. The closing price of our common units was $0.82$1.46 as of March 12, 2020.10, 2022. The issuance of new common units or debt convertible into common units in the future, could be significantly dilutive to current common unitholders. In addition, as of December 31, 2019,2021, we had approximately $649.4$632.6 million aggregate principal amount of debt outstanding, ofincluding the our 7.25% Seniorcredit agreements, First Lien Notesand 7.50% Senior SecuredSecond Lien Notes. Obtaining equity or debt financing in the current market environment is particularly difficult for us, given our current levels of long-term debt.
During the year ended December 31, 2019,2021, our aggregate capital expenditures totaled $75.8$43.4 million, which were primarily growth capital expenditures to increase our compression services equipment fleet. The majority of these capital expenditures were funded from our operating cash flows and $14.8 million of financing obtained from TETRA.cash. As of December 31, 2019,2021, our total cash balance was $2.4$6.6 million. We anticipateexpect capital expenditures in 20202022 to range from $47.0$50.0 million to $56.0$60.0 million. These capital expenditures include approximately $23.0$18.0 million to $25.0$22.0 million of maintenance capital expenditures, and approximately $20.0$24.0 million to $25.0$28.0 million of capital expenditures primarily associated with the expansion of our compressioncontract services fleet, and $4.0$8.0 million to $6.0$10.0 million of capital expenditures related to investments in technology, primarily software and systems. The foregoing estimates were based on assumptions prior to the March 2020 decline in oil prices and the stock market and weWe will continue to monitor such estimates going forward. We expect that the combination of $2.4$6.6 million of cash on hand at the beginning of 20202022 and operating cash flows expected to be generated during the year will be sufficient to fund these capital expenditures without having to incur additional long-term debt and without having to access the equity markets. However, our ability to grow our business through capital expenditures or acquisitions beyond these sources of financing may be significantly limited or curtailed. Without the ability to increase our compression equipment fleet or otherwise grow our operations, our ability to continue to retain customers whose compression services needs are expanding and to increase distributions to our common unitholders in the future may be limited.
Our long-term debt levels result in a significant amount of our operating cash flows being used to fund debt service requirements.
The aggregate carrying value of our 7.50% Senior SecuredFirst Lien Notes and Second Lien Notes as of December 31, 2019 is $344.2 million.2021 are $399.8 million and $173.0 million, respectively. In addition, we have an aggregate carrying value of $291.4$58.0 million ofand $0.3 million outstanding on our 7.25% Senior Notes outstandingSpartan Credit Agreement and our Credit Agreement, respectively, as of December 31, 2019.2021. The interest expense related to our long-term indebtedness reduces our cash available to fund capital expenditures or for distribution. Our ability to service our indebtedness in the future will depend upon, among other things, our future financial and operating performance, which will be impacted by prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we may be forced to consider taking actions such as reducing or delaying our business activities, acquisitions, investments and/or capital
expenditures, delaying any desired increase of distributions, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to take any of these courses of action.
We may not have sufficient cash from operations following the establishment of cash reserves and payment of debt service and other contractual obligations, fees and expenses, including cost reimbursements to our general partner, to enable us to increase cash distributions to our common unitholders.
Beginning with the first quarter of 2019, our common unit distributions decreased from $0.75 per unit per year (or $0.1875 per quarter) to $0.04 per unit per year (or $0.01 per quarter). Our Second Lien Notes indenture further restricts our ability to make distributions in respect of our common units in any amount exceeding $0.04 per common unit per year, unless such increased distribution is funded by proceeds from an equity offering. Under the terms of our partnership agreement, the amount of cash otherwise available for distribution is reduced by our operating expenses and the
amount of cash reserves that our general partner establishes to provide for future operations, future capital expenditures, future debt service requirements, and future cash distributions to our common unitholders. In order to make cash distributions at this current distribution rate of $0.01 per common unit per quarter, or $0.04 per common unit per year, we will require available cash of approximately $0.5$1.4 million per quarter, or $1.9$5.6 million per year, based on the number of common units outstanding as of March 12, 2020.10, 2022. We may not have sufficient available cash each quarter to enable us to increase cash distributions or make any distribution at all. To the extent we issue additional partnership units in connection with our growth, the payment of distributions on those additional partnership units may further increase the risk that we will be unable to increase our per-unit distribution. There are no limitations in our partnership agreement or our Loan and Security Agreement (the "Credit Agreement") on our ability to issue additional common units. The amount of cash we can distribute to our common unitholders principally depends upon the amount of cash we generate from our operations, which fluctuates from quarter to quarter based on, among other things, the market conditions described in these Risk Factors.
Many of our operating expenses have been volatile and may continue to be volatile or increase in the future. To the extent our efforts to contain these costs are not successful, our generation of operating cash flows to fund or increase our quarterly distributions will be negatively impacted.
Our long-term debt agreements contain covenants and other provisions that restrict our ability to take certain actions and may limit our ability to grow our business in the future.
Our Credit Agreement includes a maximum credit commitment of $50.0$35.0 million, which is available for loans, letters of credit (with a sublimit of $25.0 million), and swingline loans (with a sublimit of $5.0 million), subject to a borrowing base determined by reference to the value of certain of our accounts receivable.receivable and inventory. We are required to maintain a $5 million reserve with respect to the borrowing base, which results in reduced liquidity. The maximum credit commitment may be increased by $25.0 million, subject to the terms and conditions of the Credit Agreement. The Credit Agreement contains certain affirmative and negative covenants, including covenants that restrict our ability to take certain actions including, among other things and subject to certain significant exceptions, incurring debt, granting liens, making investments, entering into or amending existing transactions with affiliates, paying dividends, and selling assets. The Credit Agreement also contains a provision that requires our compliance with a fixed charge coverage ratio (as defined in the Credit Agreement) of not less than 1.0 to 1.0 in the event that certain conditions associated with outstanding borrowings and cash availability occur.
In addition, the indentures governing our 7.50% Senior SecuredFirst Lien Notes and our 7.25% SeniorSecond Lien Notes contain customary covenants restricting our ability and the ability of our restricted subsidiaries to: (i) pay distributions on, purchase, or redeem our common units, make certain investments and other restricted payments, or purchase or redeem any subordinated debt; (ii) incur or guarantee additional indebtedness or issue certain kinds of preferred equity securities; (iii) create or incur certain liens securing indebtedness; (iv) sell assets, including dispositions of the collateral securing our 7.50% Senior SecuredFirst Lien Notes and Second Lien Notes; (v) consolidate, merge, or transfer all or substantially all of our assets; (vi) enter into transactions with affiliates; and (vii) enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us. Our Second Lien Notes indenture further restricts our ability to make distributions in respect of our common units in any amount exceeding $0.04 per common unit per year, unless such increased distribution is funded by proceeds from an equity offering. These covenants are subject to a number of important limitations and exceptions, including certain provisions permitting us, subject to the satisfaction of certain conditions, to transfer assets to certain of our unrestricted subsidiaries. The indentures also contain customary events of default and acceleration provisions relating to events of default, which provide that upon an event of default under the indentures, the Trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 7.50% Senior SecuredFirst Lien Notes and 7.25% SeniorSecond Lien Notes may declare all of the 7.50% Senior SecuredFirst Lien Notes and 7.25% SeniorSecond Lien Notes to be due and payable immediately.
The loss of any of our most significant customers would result in a decline in our revenue and cash available to pay distributions to our common unitholders.
Our five most significant customers collectively accounted for approximately 29%30% of our 20192021 revenues. Our services and products are provided to these customers pursuant to short-term contract compression services agreements, many of which are cancellable with 30-days' notice, and equipment sales agreements.30 days’ notice. The loss of all or even a portion of the services we provide to these customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations, financial condition, and our ability to make cash distributions to our unitholders.
The credit and risk profile of TETRASpartan could adversely affect our business and our ability to make distributions to our common unitholders.
The credit and business risk profile of TETRASpartan could adversely affect our ability to incur indebtedness in the future or obtain a credit rating, as credit rating agencies may consider the leverage and credit profile of TETRASpartan and its affiliates in assigning a rating because of TETRA'sSpartan’s control of us, their performance of certain administrative functions for us, and our contractual relationships with them. Furthermore, the trading price of our common units may be adversely affected by financial or operational difficulties or excessive debt levels at TETRA.Spartan. If the pledge of TETRA'sSpartan ownership of our general partner becomes effective in the future, control over our general partner could be transferred to TETRA’sSpartan’s lenders in the event of a default by TETRA.Spartan.
Our ability to manage and grow our business effectively and provide quality services to our customers may be adversely affected if our general partner loses its management or is unable to retain trained personnel.
We rely primarily on the executive officers and other senior management of our general partner and Spartan to manage our operations and make decisions on our behalf. Our ability to provide quality compression services depends to a significant extent upon our general partner’s and Spartan’s ability to hire, train, and retain an adequate number of trained personnel. The departure of any of our general partner’s executive officers or other senior management could have a significant negative effect on our business, operating results, financial condition, and our ability to compete effectively in the marketplace. In connection with Spartan’s acquisition of our general partner, most of our general partner’s executive officers and other senior management resigned their positions, and Spartan appointed new officers in their place. Such significant turnover in management of our general partner could have negative impact on our business. We operate in an industry characterized by highly competitive labor markets, and, similar to many of our competitors, we have experienced high employee turnover in certain regions. It is possible that our labor expenses could increase if there is a shortage in the supply of skilled regional service supervisors and other service professionals. Our general partner may be unable to negotiate extensions or replacements ofmaintain an adequate skilled labor force necessary for us to operate efficiently and to support our contracts withgrowth strategy. Failure to do so could impair our ability to operate efficiently and to retain current customers and attract prospective customers, which are generally cancellablecould cause our business to suffer materially. Additionally, increases in labor expenses may have an adverse impact on 30-days' notice, which could adversely affect our operating results of operations and cash available for distribution to our common unitholders.
We generally provide compression services to our customers under contracts that, aftermay reduce the initial term, are cancellable on thirty days’ notice. We may be unable to negotiate extensions or replacementsamount of these contracts on favorable terms, if at all, which could adversely affect our results of operations and cash available for distribution to our common unitholders.
Further changes in the economic environment could result in further significant impairments of certain of our long-lived assetsWe depend on particular suppliers and are vulnerable to engine and compressor component shortages and.
price increases, which could have
Beginning in 2020, decreased commodity prices had a negative impact on oil and gas drilling and capital expenditure activity, which affected the demand for a portion of our products and services. In 2021, the prices of and demand for oil and natural gas began to recover to prior levels. If prices or demand levels begin to decline, demand for our products and services may significantly decrease, which could impact the expected utilization rates of our compressor package fleet. Under U.S. GAAP, we review the carrying value of our long-lived assets when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable, based on their expected future cash flows. The impact of reduced expected future cash flow could require the write-down of all or a portion of the carrying value for these assets, which would result in impairments, resulting in decreased earnings.
We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.
Our assets and operations are subject to inherent risks such as vehicle accidents, equipment defects, malfunctions and failures, as well as other incidents that result in releases or uncontrolled flows of gas or well fluids, fires, or explosions. These risks could expose us to substantial liability for personal injury, death, property damage, pollution, and other environmental damages. On occasion, we have experienced fires that have damaged or destroyed certain of our compression services fleet, and additional accidents or fires could occur in the future. We
do not insure all of our assets and the insurance we do obtain 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 feasible. If we were to incur substantial liability and such damages were not covered by insurance or were in excess of policy limits, or if we were to incur liability at a time when we did not maintain liability insurance, our business, results of operations, and cash available for
distribution to our common unitholders.
We fabricate most of our new compressor packages. We obtain some of the components used in our compressor packages from a single source or a limited group of suppliers. Significant suppliers of material components include Caterpillar, Inc. and Ariel Corporation for engines and compressor components, respectively. Our reliance on these and other suppliers involves several risks, including our potential inability to obtain an adequate supply of required components in a timely manner. We do not have long-term contracts with these suppliers and the partial or complete loss of certain of these suppliersfinancial condition could have a negative impact on our results of operations and could damage our customer relationships. Further, since any increase in component prices for compressor packages fabricated by us could decrease our margins, a significant increase in the price of one or more of these components could have a negative impact on our results of operations and cash available for distribution to our common unitholders.
Operating cash flows from the sale of compressor packages are inconsistent.
A significant portion of our revenues and cash flows is typically derived from the sales of newly fabricated compressor packages. During 2019, we reported revenues of $142.6 million from the sale of compressor packages. As of December 31, 2019, we had a compressor package sales order backlog of $35.5 million, compared to $105.2 million as of December 31, 2018. Demand to purchase our compressor packages is affected by numerous factors, including the prices of natural gas and oil and the level of capital spending by our customers. A change inbe adversely affected. In addition, our business strategyinterruption insurance does not cover all potential losses. Please read “Health, Safety, and Environmental Affairs Regulations” for a description of how we are subject to federal, state, and local laws and regulations governing the discharge of materials into the environment or anyotherwise relating to protection of these factors could cause cash flows from the sale of compressor packages to decrease.
Our sales to and operations in foreign countriesnon-U.S. markets exposes us to additional risks and uncertainties, including with respect to U.S. trade and economic sanctions, export control laws, and the Foreign Corrupt Practices Act
(“FCPA”), and similar anti-bribery laws. If we are not in compliance with applicable legal requirements, we may be subject to civil or criminal penalties and other remedial measures that could have a material impact on our business.
We have operations in Mexico, Canada, Argentina, Chile and ArgentinaEgypt as well as a number of other foreign countries.non-U.S. markets. A portion of our expected future growth could include expansion in these and other foreign countries. Foreignnon-U.S. markets. Non-U.S. operations carry special risks. Our operations in the countries in which we currently operate and those countries in which we may operate in the future, could be adversely affected by:
•government controls and actions, such as expropriation of assets and changes in legal and regulatory environments;
•import and export license requirements;
•political, social, or economic instability;
•trade restrictions;
•changes in tariffs and taxes;
•currency exposure;
•restrictions on repatriating foreign profits back to the United States; and
•the impact of anti-corruption laws.
Sanctions imposed by the U.S. Office of Foreign Assets Control (“OFAC”) prohibit our operations in or sales to customers in certain foreign countries.non-U.S. markets. We are also subject to the FCPA, which prohibits U.S. companies and their intermediaries from bribing foreignoverseas officials for the purpose of obtaining or keeping business or otherwise obtaining favorable treatment, and other similar laws governing our foreign operations. The FCPA’s foreignnon-U.S. counterparts, including the UK Bribery Act, contain similar prohibitions, although varying in both scope and jurisdiction. We operate in parts of the world that have experienced governmental corruption in the past.
We have policies and procedures to maintain our compliance with the FCPA, OFAC sanctions, export controls, and similar laws and regulations. The implementation of such policies and procedures may be time consuming and expensive, and could result in the discovery of issues or violations with respect to the foregoing by us or our employees, independent contractors, subcontractors, or agents of which we were previously unaware. If we violate any of these regulations, significant administrative, civil, and criminal penalties could be assessed on us. In addition, foreign governments and agencies often establish permit and regulatory standards different from those in the U.S. If we cannot obtain foreign regulatory approvals or cannot obtain them in a timely manner, our growth and profitability from international operations could be adversely affected.
Security disruptions in regions of Mexico served by us could adversely affect our Mexican operations, and, as a result, the levels of revenue and operating cash flow from our Mexican operations could be reduced.
In recent years, incidents of security disruptions throughout many regions of Mexico have increased. Drug-related gang activity has grown in Mexico. Certain incidents of violence have occurred in regions in which we operate and have resulted in the interruption of our operations, and these interruptions could increase in the future. To the extent that such security disruptions increase, the levels of revenue and operating cash flow from our Mexican operations could be reduced.
Our operations in Argentina, Chile and Egypt expose us to the changing economic, legal, and political environment in that country,those countries, including changing regulations governing the repatriation of cash generated from our operations in Argentina.
The current economic, legal, and political environment in Argentina and the recent devaluations of the Argentinian peso have created increased instability for foreign investment in Argentina. The Argentinian government is currently attempting to address the current high rate of inflation and the continuing currency devaluation pressure. Fiscal and monetary expansion in Argentina has led to devaluations of the Argentinian peso. Additional devaluation may be necessary to help boost the current Argentina economy, and they may be accompanied by fiscal and monetary tightening, including additional restrictions on the transfer of U.S. dollars out of Argentina. On June 30, 2018, we determined the economy in Argentina to be highly inflationary. As a result of this determination and in accordance with U.S. generally accepted accounting principles ("GAAP"), on July 1, 2018, the functional currency of our operations in Argentina was changed from the Argentine peso to the U.S. dollar. The remeasurement did not have a material impact on our consolidated financial position or results of operations.
As a result of our operations in Argentina, consolidated revenues and operating cash flow generated in Argentina have increasedexperienced growth over the past threefive years. The process of repatriating this cash to the U.S. is subject to increasingly complex regulations. There can be no assurances that our growing Argentinian operations will not expose us to the loss of liquidity, foreign exchange losses, and other potential financial impacts.
The Chilean government is currently attempting to address the current high rate of inflation and the continuing currency devaluation pressure. The government has raised borrowing costs, higher commodity prices are keeping consumer prices under pressure and the central bank has begun to withdraw monetary stimulus by raising the benchmark interest rate.
Our abilityOperations in Egypt can be a challenge due to managethe country’s complex regulatory and grow our business effectivelyoperating environment. In addition, tight government control of political discourse, increasing poverty and provide quality services to our customers may be adversely affected if our general partner loses its management or is unable to retain trained personnel.
We rely primarily onrising costs of living, could increase the executive officersrisk of social unrest and other senior management of our general partner and TETRA to manage our operations and make decisions on our behalf. Our ability to provide quality compression services
depends to a significant extent upon our general partner’s and TETRA's ability to hire, train, and retain an adequate number of trained personnel.political instability. The departure of any of our general partner’s executive officers or other senior management could have a significant negative effect on our business, operating results, financial condition, and our ability to compete effectivelymilitary’s role in the marketplace. We operateeconomy has continued to expand in an industry characterized by highly competitive labor markets, and, similar to many of our competitors, we have experienced high employee turnover in certain regions. It is possible that our labor expenses could increase if there is a shortage in the supply of skilled regional service supervisors and other service professionals. Our general partner may be unable to maintain an adequate skilled labor force necessary for us to operate efficiently and to support our growth strategy. Failure to do so could impair our ability to operate efficiently and to retain current customers and attract prospective customers,recent years, which could cause ourhas dampened private sector business to suffer materially. Additionally, increases in labor expenses may have an adverse impact on our operating results and may reduce the amount of cash available for distribution to our common unitholders.confidence.
The employees conducting our operations in Mexico and Argentina are party to collective labor agreements, and a prolonged work stoppage of our operations in Mexico or Argentina could adversely impact our revenues, cash flows and net income.
The personnel conducting our operations in Mexico are currently subject to collective labor agreements. These collective labor agreements consist of “evergreen” contracts that have no expiration date and whose terms remain in full force and effect from year-to-year, unless the parties agree to negotiate new terms. The employees subject to these “evergreen” agreements may, however, request a renegotiation of their employee compensation terms on an annual basis or a renegotiation of the entire agreement on a biannual basis, although we are not required to honor any such request. The personnel conducting operations in Argentina are also subject to collective labor agreements. We have not experienced work stoppages in Mexico or Argentina in the past, but cannot guarantee that we will not experience work stoppages in the future. A prolonged work stoppage could adversely impact our revenues, cash flows, and net income. Mexico’s Federal Labor Law was reformed effective August 1, 2021 in relation to labor subcontracting which resulted in an increase in Statutory Profit Sharing (PTU).
A terrorist attack, armed conflict or political or civil unrest could harm our business.
Terrorist activities, anti‑terrorist efforts, war and other armed conflicts and political or civil unrest could adversely affect the U.S. and global economies and could prevent us from meeting financial and other obligations. We could experience loss of business, delays or defaults in payments from payors or disruptions of fuel supplies and markets if pipelines, production facilities, processing plants, refineries or transportation facilities are direct targets or indirect casualties of an act of terror or war. Such activities could reduce the overall demand for oil and natural gas, which, in turn, could also reduce the demand for our services. War and other armed conflicts, including conflict related to Russia’s invasion of Ukraine, and any resulting economic downturn could adversely affect our results of operations, impair our ability to raise capital or otherwise adversely impact our ability to realize certain business strategies. In addition, sanctions imposed on foreign countries by the U.S. or other foreign governments could adversely affect our results of operations, impair our ability to raise capital or otherwise adversely impact our ability to realize certain business strategies.
Our exposure to currency exchange rate fluctuations may result in fluctuations in our cash flows and could have an adverse effect on our results of operations.
Because we have operations in Mexico, Canada, Argentina, Chile and Argentina,Egypt, and in certain other foreign countries,non-U.S. jurisdictions, a portion of our business is conducted in foreign currencies. As a result, we are exposed to currency exchange rate fluctuations that could have an adverse effect on our results of operations. If a foreign currency weakened significantly, we would be required to convert more of that foreign currency to U.S. dollars to satisfy our obligations, which would cause us to have less cash available for distribution. A significant strengthening of the U.S. dollar could result in an increase in our financing expenses and could materially affect our financial results under U.S. GAAP. Because we report our operating results in U.S. dollars, changes in the value of the U.S. dollar also result in fluctuations in our reported revenues and earnings. Most of our billings under the contracts with PEMEX and other clients in Mexico are in U.S. dollars; however, a large portion of our expenses and costs under those contracts are incurred in Mexican pesos. In addition, future contract awards with PEMEX may require us to bill a larger portion of our revenues in Mexican pesos, which would expose us to additional foreign currency exchange rate risks.
As a result of the above, we are exposed to fluctuations in the values of the Mexican andpeso, Argentinian peso, Chilean peso, and the Egyptian pound against the U.S. dollar. A material increase in the values of these foreign currencies relative to the U.S. dollar would adversely affect our cash flows and net income. On June 30, 2018, we determined the economy in Argentina to be highly inflationary. As a result of this determination and in accordance with U.S. GAAP, on July 1, 2018, the functional currency of our operations in Argentina was changed from the Argentine peso to the U.S. dollar. In addition, for our operations in Canada, where the Canadian dollar is the functional currency under U.S. GAAP, all U.S. dollar-denominated monetary assets and liabilities, such as cash and cash equivalents, accounts receivable, restricted cash, accounts payable, long-term debt and capital lease obligations, are revalued and reported based on the prevailing exchange rate at the end of the reporting period. This revaluation may cause us to report significant foreign currency exchange gains and losses in certain periods.
Further changes in theeconomic environment could result in further significant impairments of certain of our long-lived assets.
Decreased commodity prices have,Environmental and may continue to have, a negative impact on oil and gas drilling and capital expenditure activity, which affects the demand for a portion of our products and services. The prices of oil and natural gas have declined significantly since the beginning of 2020, which is expected to adversely affect drilling levels, activity levels, and spending in the oil and natural gas industry. If these price levels continue or further
decline, demand for our products and services may significantly decrease, which could impact the expected utilization rates of our compressor package fleet. Under U.S. GAAP, we review the carrying value of our long-lived assets when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable, based on their expected future cash flows. The impact of reduced expected future cash flow could require the write-down of all or a portion of the carrying value for these assets, which would result in impairments, resulting in decreased earnings.
We are exposed to significant credit risks.
We face credit risk associated with the significant amounts of accounts receivable we have with our customers in the energy industry. Many of our customers, particularly those associated with our low-horsepower compression service operations, are small- to medium-sized oil and gas operators that may be more susceptible to fluctuating oil and gas commodity prices or generally increased operating expenses than larger companies. Our customers' ability to pay is impacted by a decreased oil and natural gas price environment and we may face increased credit risks if the current reduced price of oil and natural gas continues for an extended period of time.
We do not insure against all potential losses and could be seriously harmed by unexpected liabilities
.
Our assets and operations are subject to inherent risks such as vehicle accidents, equipment defects, malfunctions and failures, as well as other incidents that result in releases or uncontrolled flows of gas or well fluids, fires, or explosions. These risks could expose us to substantial liability for personal injury, death, property damage, pollution, and other environmental damages. On occasion, we have experienced fires that have damaged or destroyed certain of our compression services fleet, and additional accidents or fires could occur in the future. We do not insure all of our assets and the insurance we do obtain 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 feasible. If we were to incur substantial liability and such damages were not covered by insurance or were in excess of policy limits, or if we were to incur liability at a time when we did not maintain liability insurance, our business, results of operations, and financial condition could be adversely affected. In addition, we do not maintain business interruption insurance. Please read “Health, Safety, and Environmental Affairs Regulations” for a description of how we are subject to federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of human health and environment.
We are subject to environmental regulations, and changes in these regulations could increase our costs or liabilities.
We are subject to federal, state, local, and foreign laws and regulatory standards, including laws and regulations regarding the discharge of materials into the environment, emission controls, and other environmental protection and occupational health and safety concerns. Environmental laws and regulations may, in certain circumstances, impose strict and joint and several liability for environmental contamination, rendering us liable for remediation costs, natural resource damages, and other damages resulting from our ownership of property or 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 landowners 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 adversely affect our financial condition or results of operations. Moreover, failure to comply with these environmental laws and regulations may result in the imposition of administrative, civil and criminal penalties, and the issuance of injunctions delaying or prohibiting operations.
We routinely deal with natural gas, oil, and other petroleum products. Hydrocarbons or other hazardous wastes may have been released during our operations or by third parties on wellhead sites where we provide services or store our equipment or on or under other locations where wastes have been taken for disposal. These properties may be subject to investigatory, remediation, and monitoring requirements under foreign, federal, state, and local environmental laws and regulations.
The EPA has adopted regulations under the CAA to control emissions of hazardous air pollutants from reciprocal internal combustion engines and more recently the EPA adopted regulations that establish air emission
controls for natural gas and natural gas liquids production, processing and transportation activities, including NSPS as well as emission standards to address hazardous air pollutants. Certain of our compressor packages are subject to these new requirements and additional control equipment and maintenance operations are required. While we do not believe that compliance with current regulatory requirements will have a material adverse effect on our business, additional regulations could impose new air permitting or pollution control requirements on our equipment that could require us to incur material costs.
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 adversely affect oil and natural gas exploration and production, which in turn could have an adverse effect on us.
Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas our customers produce, while the physical effects of climate change could disrupt production and cause us to incur costs in preparing for or responding to those effects.
The EPA has adopted regulations to restrict emissions of GHGs under existing provisions of the CAA. Such EPA rules regulate GHG emissions under the CAA and require a reduction in emissions of GHGs from motor vehicles and from certain large stationary sources. TheFor example, the EPA published final rules alsoin June 2016 that require the reduction of volatile organic compounds and methane emissions from certain hydraulically fractured natural gas wells and further require that most wells use so-called “green” completions at certain hydraulically fractured natural gas wells. UnderThese regulations also established new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. Certain of our compressor packages are subject to these requirements and additional control equipment and maintenance operations are required. While the EPA under the Trump Administration finalized rules to rescind or modify certain of these requirements in September 2020, including rescission of the methane-specific requirements applicable to sources in the production and processing segments of the oil and gas industry, various states and industry and environmental groups are separately challenging the EPA’s 2016 standards and its September 2020 final rule. However, the U.S. Congress passed, and President Biden signed into law, a revocation of the 2020 rulemaking effectively reinstating the 2016 standards. Additionally, in November 2021, the EPA issued a proposed rule that, if finalized, would establish OOOOb new source and OOOOc first-time existing source standards of performance for GHG and volatile organic compound (“VOC”) emissions for the crude oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities. Owners or operators of affected emission units or processes would have to comply with specific standards of performance that may include leak detection using optical gas imaging and subsequent repair requirements, reduction of emissions by 95% through capture and control systems, zero-emission requirements, operations and maintenance requirements, and so-called “green well” completion requirements. The EPA plans to issue a supplemental proposal enhancing this proposed rulemaking in 2022 that will contain proposed rule text, which was not included in the November 2021 proposed rule, and anticipates issuing a final rule by the end of 2022. While we do not believe that compliance with current administration, EPA proposed rules in 2019regulatory requirements will have a material adverse effect on our business, additional or more stringent regulations could impose new air permitting or pollution control requirements on our equipment that could require us to loosen these requirements; however the rules have not yet been finalized.incur material costs. In addition, the EPA requires the annual reporting of GHG emissions from specified large GHG emission sources in the United States,U.S., including petroleum refineries, as well as from certain oil and gas production facilities.
In addition, in December 2015, over 190 countries, including the United States,U.S., reached an agreement to reduce global GHG emissions (the “Paris Agreement”). The Paris Agreement entered into force in November 2016 after more than 170 nations, including the United States,U.S., ratified or otherwise indicated their intent to be bound by the Paris Agreement. However, in June 2017, President Trump announced thatAlthough the United States intends to withdrawU.S. withdrew from the Paris Agreement and to seek negotiations either to reenter the Paris Agreement on different terms or a separate agreement. In August 2017, the U.S. Department of State officially informed the United Nations of the United States’ intent to withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which2020, President Biden recommitted the United States may re-enterin February 2021, and, in April 2021, announced a new, more rigorous nationally determined emissions reduction level of 50-52% reduction from 2005 levels in economy-wide net GHG emissions by 2030. The international community gathered in Glasgow in November 2021 at the Paris Agreement or26th Conference to the Parties (“COP26”) during which multiple announcements were made, including a separately negotiated agreement are unclear at this time. In November 2019call for parties to eliminate fossil fuel subsidies, amongst other measures. Relatedly, the United States submitted formal noticeand European Union jointly announced at COP26 the launch of the Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector.
There are also increasing financial risks for fossil fuel producers as stockholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required underto adopt policies that have the Paris Agreement. The withdrawaleffect of reducing the funding provided to the fossil fuel sector. In late 2020, the Federal Reserve announced that it had joined Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Subsequently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Although we cannot predict the effect of these actions, such limitation of investments in and financing for fossil fuel energy companies could adversely impact our customers and, therefore, our operations. Additionally, the SEC announced its intention to promulgate rules requiring climate
disclosures. Although the form and substance of these requirements is schedulednot yet known, this may result in additional costs to be effective November 4, 2020. To the extentcomply with any such disclosure requirements.
President Biden has also issued executive orders that other countries implement the Paris Agreement or the United States imposes othercommit to substantial action on climate change, regulationscalling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and an increased emphasis on the oilclimate-related risk across government agencies and natural gas industry, it could have an adverse effect on our business.
economic sectors. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our facilities and operations could require us to incur costs. Further, Congress has considered and almost one-half of the states have adopted legislation that seeks to control or reduce emissions of GHGs from a wide range of sources. Any such legislation could adversely affect demand for the oil and natural gas our customers produce and, in turn, demand for our products and services. Litigation risks are also increasing as a number of parties have sought to bring suit against certain oil and natural gas companies in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time, but defrauded their investors or customers by failing to adequately disclose those impacts.
Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as the increased frequency or intensity of extreme weather events or changes in meteorological and severity of storms, floods,hydrological patterns, that could adversely impact our operations. Such physical risks may result in damage to our customers’ facilities and other climatic events;otherwise adversely impact their operations, such as if they become subject to water use curtailments in response to drought, or demand for their products, such as to the extent warmer winters reduce the demand for energy for heating purposes. If any such effects were to occur, they could have an adverse effect on our operations and cause us to incur costs in preparing for or responding to those effects.
Regulatory initiatives related to hydraulic fracturing in the countries where we and our customers operate could result in operating restrictions or delays in the completion of oil and gas wells that may reduce demand for our services.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from dense subsurface rock formations. The process involves the injection of water, sand or other proppants and chemical additives under pressure into targeted geological formations to fracture the surrounding rock and stimulate production.
Hydraulic fracturing typically is regulated by state oil and gas commissions or similar state agencies, but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA asserted regulatory authority pursuant to the federal Safe Drinking Water Act, Underground Injection Control program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities; published final rules under the CAA in 2012 and published additional final regulations in June 2016 governing methane and volatile organic compound performance standards, including standards for the capture of air emissions released during forby the oil and natural gas hydraulic fracturing industry (however, rules have been proposed in 2019 to modify or rescind some of these requirements);industry; published in June 2016 an effluent limitations guidelines final rule prohibiting the discharge of waste water from shale natural-gas extraction operations before discharging to a treatment plant; and in 2014 published an Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the U.S. Bureau of Land Management ("BLM") published a final rule in March 20152016 that established new or more stringent standards for performing hydraulic fracturing on federal and Indian lands. BLM hasunder the Trump Administration issued a final rule in late 2018 rescinding the 20152016 action; thishowever, a California federal court vacated the 2018 final rule in July 2020, and a Wyoming federal court subsequently vacated the 2016 final rule in October 2020. Accordingly, the 2016 final rule is no longer in effect, but the Wyoming decision is expected to be appealed. Moreover, the Biden Administration is expected to pursue regulatory initiatives that regulate hydraulic fracturing activities on federal lands as well as other actions to more stringently regulate certain aspects of oil and gas development such as air emissions and water discharges. On January 20, 2021, the Acting Secretary of the U.S. Department of the Interior issued an order, effective immediately, that suspends new rule remainsoil and gas leases and drilling permits on non-Indian federal lands and waters for a period of 60 days. In addition, President Biden issued an executive order on January 27, 2021, that suspends new leasing activities for oil and gas exploration and production on non-Indian federal lands and offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices that take into consideration potential climate and other impacts associated with oil and gas activities on such lands and waters. The suspension of these federal leasing activities prompted legal action by several states against the Biden Administration resulting in the issuance of a nationwide preliminary injunction by a federal district judge in Louisiana in June 2021, effectively halting implementation of the leasing suspension. Relatedly, the Department of the Interior released its report on federal
gas leasing and permitting practices in November 2021, referencing a number of recommendations and an overarching intent to modernize the federal oil and gas leasing program, including by adjusting royalty and bonding rates, prioritizing leasing in areas with known resource potential, and avoiding leasing that conflicts with recreation, wildlife habitat, conservation, and historical and cultural resources. Implementation of many of the recommendations in the report will require Congressional action and provisions of the reforms have been subject to legal challenge.litigation. On February 19, 2022, the Department of the Interior announced that decisions on permits to drill for oil and gas on federal lands will be delayed in response to a court ruling preventing agencies from using the social cost of carbon in their decision making. We cannot predict the extent to which the recommendations may be implemented now or in the future, but restrictions on federal oil and gas activities have the potential to result in increased costs on our customers, decreased demand for our services on federal lands, and an adverse impact on our business. However, these orders do not apply to operations under existing leases and permits.
The U.S. Congress (“Congress”) has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states, including Texas, Oklahoma and New Mexico have adopted, and other states are considering adopting legal requirements that could impose new or more stringent permitting, public disclosure, or well construction requirements on hydraulic fracturing activities. States could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted, our customers could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs for our customers in the production of oil and gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of additional regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and an associated decrease in demand for our services and increased compliance costs and time, which could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.
Increased attention to Environmental, Social, and Governance (“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 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 investigation and litigation, and negative impacts on the value of our services 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 our customers or us. 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 or contribution to the asserted damage, or to other mitigating factors. While we may in the future participate in various voluntary frameworks and certification programs to improve the ESG profile of our operations and services, we cannot guarantee that such participation or certification will have the intended results on our ESG profile.
Moreover, while we may create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures will be based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith.] Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring, and reporting on many ESG matters. Additionally, while we may also announce various voluntary ESG targets in the future, such targets are aspirational. We may not be able to meet such targets in the manner or on such a timeline as initially contemplated, including, but not limited to as a result of unforeseen costs or technical difficulties associated with achieving such results. To the extent that we do meet such targets, it may be achieved through various contractual arrangements, including the purchase of various credits or
offsets that may be deemed to mitigate our ESG impact instead of actual changes in our ESG performance. Also, despite these aspirational goals, we may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.
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, which may adversely impact our business, financial condition, or results of operations.
Our operations and reputation may be impaired if certain information technology systems fail to perform adequately or if we are the subject of a data breach or cyberattack.
The Our information technology systems (including the information technology systems of our general partner and TETRA, provided through January 31, 2022 under the Transition Services Agreement), are critically important to operating our business efficiently. We rely on these information technology systems to manage business data, communications, supply chain, customer invoicing, employee information, and other business processes. Our general partner outsourcesWe outsource certain business process functions to TETRA and third-party providers and similarly relieswe rely on TETRA and these third-parties to maintain and store confidential information on their systems. The failure of these information technology systems to perform as we anticipate could disrupt our business and could result in transaction errors, processing inefficiencies, and the loss of sales and customers, causing our business and results of operations to suffer.
Although our general partner allocateswe allocate significant resources to protect these information technology systems, we have experienced within the past year varying degrees of cyber-incidents in the normal conduct of our business, including viruses, worms, other destructive software, process breakdowns, phishing and other malicious activities. On January 6, 2020, the Department of Homeland Security issued a public warning that indicated companies in the energy industry might be specific targets of cybersecurity threats. Such breaches have in the past and could again in the future result in unauthorized access to information including customer, supplier, employee, or other company confidential data. Our general partner carries insurance against these risks, although the potential damages we might incur could exceed our available insurance coverage. Our general partner also investsWe are investing in security technology performs penetration tests from time to time, and designs ourdesigning business processes to attempt to mitigate the risk of such breaches. While we believe these measures are generally effective, there can be no
assurance that security breaches will not occur. Moreover, the development and maintenance of these measures requires continuous monitoring as technologies change and efforts to overcome security measures evolve. We continue to experiencehave experienced and expect to continue to experience, cybersecurity threats and incidents, none of which has been material to us to date. However, a successful breach or attack could have a material negative impact on our operations or business reputation and subject us to consequences such as litigation and direct costs associated with incident response.
Risks Inherent in an Investment in Us
The market price of our common units has been and may continue to be volatile.
The market price of our common units has fluctuated in the past and is subject to significant fluctuations in response to many factors, some of which are beyond our control, including the following:
•our operational performance;
•supply, demand, and prices of oil and natural gas;
•the activity levels of our customers;
•deviations in our earnings from publicly disclosed forward-looking guidance or analysts’ projections;
•recommendations by research analysts that cover us and other companies in our industry:
•risks related to acquisitions and our growth strategy;
•uncertainty about current global economic conditions; and
•other general economic conditions.
During 2019,2021, the market price for our common units ranged from a high of $3.98$2.21 per common unit to a low of $2.18$1.00 per common unit. In connection with the stock market decline that began in March 2020, the closing market price of our common units has declined below $1.00 per common unit with a closing price of $0.82 per common unit on March 12, 2020. In recent years, the stock market in general has experienced extreme price and volume
fluctuations that have affected the market price for many companies in industries similar to ours. Some of these fluctuations have been unrelated to operating performance and are attributable, in part, to outside factors such as the recent coronavirus (COVID-19) outbreakCOVID-19 pandemic and its potential impact on the world economy. The volatility of our common units may make it difficult for youinvestors to resell our common units when you want at attractive prices.
We are listedIf we cannot meet the continued listing requirements of the NASDAQ Exchange (the “NASDAQ”), the NASDAQ may delist our common units.
The Partnership has been notified by the NASDAQ in the past from time to time that the closing price of the Partnership’s common units over the prior 30 consecutive trading day period was below $1.00 per unit, which is the minimum closing price per unit required to maintain listing on the NASDAQ Exchangeunder Rule 5450 (“NASDAQ”Rule 5450”). We are requiredWhile the Partnership is currently in compliance with Rule 5450, there can be no assurance that the Partnership will maintain compliance with such rule or the NASDAQ’s other listing rules in the future. On March 10, 2022, the trading price of our common units closed at $1.46 per unit.
Upon receipt of notice of noncompliance from NASDAQ, the Partnership has a period of six months to meet NASDAQ’sregain compliance with Rule 5450, during which time our common units continue to be listed and traded on the NASDAQ, subject to our compliance with other continued listing standards. If we fail to regain compliance with Rule 5450 by the end of the cure period, the common units will be subject to the NASDAQ’s suspension and delisting procedures. If necessary, to regain compliance with NASDAQ listing standards, includingwe may, subject to approval of the board of directors of our general partner, implement a requirement thatreverse split of our common units. A delisting of our common units from the closingNASDAQ could negatively impact us by, among other things, reducing the liquidity and market price of our common units, not be below $1.00 per common unit for any periodreducing the number of thirty consecutive trading days. As indicated above, the closing market price ofinvestors willing to hold or acquire our common units, was recently below $1.00. In addition,limiting our ability to issue securities or obtain financing in the continued listing standards have minimum market capitalizationfuture, and partners’limiting our ability to use a registration statement to offer and sell freely tradable securities, thereby restricting our ability to access the public capital requirements. If we are unable to meet these continued listing standards, including the minimum common unit price, and are unable to cure any such non-compliance within the applicable cure period provided by NASDAQ, NASDAQ will delist our common units. In that event, it is possible that our common units would be quoted on the over-the-counter bulletin board. This could have negative consequences for us, including reduced liquidity for unitholders, reduced trading levels, limited availability of market quotations or analyst coverage, stricter trading rules for brokers trading our common units, and reduced access to financing alternatives. We also could be subject to greater state securities regulation if our common units are no longer listed on a national exchange.
Our partnership agreement requires us to distribute all of the available cash that we generate each quarter after paying expenses and establishing prudent operating reserves, which could limit our ability to grow.
Our partnership agreement requires us to distribute all of the available cash we generate each quarter. Under the terms of our partnership agreement, the amount of cash otherwise available for distribution will be reduced by our operating expenses and the amount of cash reserves that our general partner establishes to provide for future operations, future capital expenditures, future debt service requirements (including the redemption of our remaining outstanding Preferred Units) and future cash distributions to our common unitholders. As a result, our general partner relies primarily upon external financing sources, including existing debt arrangements and the issuance of additional debt and equity securities, as well as cash flows from operations to a certain extent, to fund our expansion capital expenditures. To the extent that we are unable to finance growth externally, this requirement significantly impairs our ability to grow. In addition, also as a result of this requirement, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent that we
issue additional units in connection with any expansion of capital expenditures, the payment of distributions on those additional units willmay decrease the amount we distribute on each outstanding unit.
On January 20, 2020, Our Second Lien Notes indenture further restricts our general partner declared a cash distribution attributableability to the quarter ended December 31, 2019 of $0.01 per common unit. This distribution equates to a distribution of $0.04 per outstanding common unit, on an annualized basis. This cash distribution was paid on February 14, 2020 to all common unitholders of record as of the close of business on February 1, 2020. The amount of quarterlymake distributions is determined based on a variety of factors, including our estimates of cash needs to fund our future operating, investing, and debt service requirements (including the redemptionin respect of our remaining outstanding Preferred Units). Our estimates of these future cash requirements are usedcommon units in the determination of available cash, as defined in our Partnership Agreement. We will continue to monitor the uncertain levels of cash flows from operating activities and the levels of cash flows from investing activities necessary to maintain our equipment fleet, and use these estimates in the determination of the levels of our future quarterly distributions. There can be no assurance that our quarterly distributions will increase from this reducedany amount exceeding $0.04 per common unit or that there will not be further decreases in the amount of distributions in the future.
per year, unless such increased distribution is funded by proceeds from an equity offering.
TETRA
Spartan controls our general partner, which has sole responsibility for conducting our business and managing our operations, and thereby controls us. TETRASpartan has conflicts of interest, which may permit it to favor its own interests to our unitholders’ detriment.
TETRA Spartan controls our general partner, and through the general partner controls us. Some of our general partner’s directors are directors or officers of TETRASpartan or its affiliates that own our general partner. Therefore, conflicts of interest may arise between TETRASpartan and its affiliates, including our general partner, on the one hand, and us and our common unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of TETRASpartan and its affiliates over the interests of our common unitholders. These conflicts include, among others, the following situations:
•neither our partnership agreement nor any other agreement requires TETRASpartan to pursue a business strategy that favors us. The directors and officers of TETRASpartan and its affiliates have a fiduciary duty to make these decisions in the best interests of TETRA,Spartan, which may be contrary to our interests;
•our general partner controls the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and TETRA,Spartan, on the other hand, including provisions governing administrative services, acquisitions, and non-competition provisions;
•our general partner is allowed to take into account the interests of parties other than us, including TETRASpartan and its affiliates, in resolving conflicts of interest;
•our general partner has limited its liability and reduced its fiduciary duties to our common unitholders and us, and has also restricted the remedies available to our common unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;
•our general partner will determine the amount and timing of asset purchases and sales, capital expenditures, borrowings, repayment of indebtedness, and issuances of additional partnership interests, each of which can affect the amount of cash that is available for distribution to our common unitholders;
•our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus, and this determination can affect the amount of cash that is distributed to our common unitholders;
•our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions;
our partnership agreement permits us to distribute up to $15 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings, or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on the incentive distribution rights;
•our general partner determines which costs incurred by it and its affiliates are reimbursable by us and TETRASpartan will determine the allocation of shared overhead expenses;
•our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
•our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;
•our general partner decides whether to retain separate counsel, accountants, or others to perform services for us; and
•our general partner may elect to cause us to issue common units to it in connection with a resettingdetermines the amount and timing of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or the common unitholders. This election may result in lower distributions to the common unitholders in certain situations.
Our reliance on TETRA for certain general and administrative support services and our limited ability to control certain costs could have a material adverse effect on our business, results of operations, financial condition, and ability to make cash distributions to our unitholders. Cost reimbursements due to our general partner and its affiliates for services provided, which will be determined by our general partner, will be substantial and will reduce our cash available for distribution to our unitholders.
Pursuant to an Omnibus Agreement entered into between TETRA, our general partner and us, TETRA provides to us certain general and administrative services, including, without limitation, legal, accounting, treasury, insurance administration and claims processing and risk management, health, safety and environmental, information technology, human resources, credit, payroll, internal audit and tax services. Our ability to execute our growth strategy depends significantly upon TETRA’s performance of these services. Our reliance on TETRA could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. Additionally, TETRA will receive reimbursement for the provision of various general and administrative services for our benefit. Our general partner is also entitled to significant reimbursement for certain expenses it incurs on our behalf, including reimbursement for a portion of the cost of its employees who perform services for us. Payments for these services are substantial and reduce the amount of cash available for distribution to our common unitholders. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.
Our partnership agreement limits our general partner’s fiduciary duties to our common unitholders and restricts the remedies available to our common unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:
•permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to consider any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the partnership units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;
•provides that our general partner will not have any liability to us or our common unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;
•generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not involving a vote of our common unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;
•provides that our general partner and its executive officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general
partner or those other persons 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 in resolving conflicts of interest, it will be presumed that in making its decision our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of its board of directors or our common unitholders. This could result in lower distributions to our common unitholders.
Our general partner has the right, at any time when it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution. If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and will retain its then-current general partner interest. The number of common units to be issued to our general partner will equal the number of common units that would have entitled the holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such reset. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units to our general partner in connection with resetting the target distribution levels.
Our common unitholders have limited voting rights and are not entitled to elect our general partner or its directors.
Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right to elect our general partner or its board of directors. The board of directors of our general partner will be chosen indirectly by TETRASpartan through its subsidiary that is the sole shareholder of our general partner. Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The vote of the holders of at least 66.7% of all outstanding common units is required to remove our general partner. As of March 10, 2022, our general partner and its affiliates own 45.0% of our aggregate outstanding common units. Due to these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Even if our common unitholders are dissatisfied, they cannot currently remove our general partner without its consent.
Our common unitholders are currently unable to remove our general partner without its consent because our general partner and its affiliates own sufficient units to prevent its removal. The vote of the holders of at least 66.7% of all outstanding common units is required to remove our general partner. As of March 12, 2020, our general partner and its affiliates own 34% of our aggregate outstanding common units.
We can issue an unlimited number of partnership units in the future, including units that are senior in right of distributions, liquidation and voting to the common units, without the approval of our common unitholders and our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of the conflicts committee of its board of directors or our common unitholders, each ofgeneral partner, which would dilute our common unitholders’ existing ownership interests.
Our partnership agreement does not limit the number of additional partnership units that we may issue at any time without the approval of our common unitholders. In addition, we may issue an unlimited number of
partnership units that are senior to the common units in right of distribution, liquidation, or voting. Our general partner also has the right, at any time when it has received incentive distributions at the highest level to which it is entitled (48.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and will retain its then-current general partner interest.
The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
•our previously existing common unitholders’ proportionate ownership interests in us will decrease;
•the amount of cash available for distribution on each common unit may decrease;
•the ratio of taxable income to distributions may increase;
•the relative voting strength of each previously outstanding common unitholders may be diminished; and
•the market price of the common units may decline.
Control of our general partner has been and may be transferred to a third party without common unitholder consent.
On January 29, 2021, control of our general partner was transferred from TETRA to Spartan.Our 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 our unitholders. Furthermore, our partnership agreement does not restrict the ability of TETRASpartan or its subsidiaries from transferring all or a portion of its indirect ownership interest in our general partner to a third party. The new owners of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with its own choices and thereby influence the decisions taken by the board of directors and executive officers.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units, other than our general partner and its affiliates, including TETRA.Spartan. Accordingly, such unitholders’ voting rights may be limited.
Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any partnership units held by a person that owns 20% or more of any class of partnership units then outstanding, other than our general partner, its affiliates, including TETRA,Spartan, its transferees and persons who acquired such partnership units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of our common unitholders to call meetings or to acquire information about our operations, as well as other provisions.
Our general partner has a limited call right that may require our unitholders to sell common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 90% of the common units, our 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 the common units held by unaffiliated persons at a price not less than the then-current market price. As a result, our unitholders may be required to sell common units at an undesirable time or price and may not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of common units. As of March 12, 2020,10, 2022, our general partner and its affiliates own an aggregate of 34%45.0% of our common units.
Our common unitholders’ liability may not be limited if a court finds that common unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to our general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. 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 other states in which we do business. Our common unitholders could be liable for any and all of our obligations as if they were a general partner if:
•a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or
•our common unitholders’ right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other actions under our partnership agreement constitutes “control” of our business.
Our common unitholders may have liability to repay distributions that were wrongfully distributed to them.
Under certain circumstances, our common unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our common unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners because of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended.
While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by affiliates of TETRA)Spartan). As of March 12, 2020,10, 2022, our general partner and its affiliates own an aggregate of 34%45.0% of our common units.
We are exempt from certain corporate governance requirements that provide additional protection to stockholders of other public companies.
Companies listed on the NASDAQ are required to meet the high standards of corporate governance, as set forth in the NASDAQ Listing Rules. These requirements generally do not apply to limited partnerships or to a “controlled company,” within the meaning of the NASDAQ rules. We are a limited partnership and a “controlled company,” within the meaning of the NASDAQ rules, and, as a result, we rely on exemptions from certain corporate governance requirements that provide protection to stockholders of other public companies.
Tax Risks to Common Unitholders
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes. If the IRS were to treat us as a corporation for U.S. federal income tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in theour common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. Despite the fact that we are a limited partnership under Delaware law, we will be treated as a corporation for U.S. federal income tax purposes unless we satisfy a "qualifying income" requirement. Based upon our current operations and current Treasury Regulations, we believe that we satisfy the qualifying income requirement. However, no ruling has been or will be requested regarding our treatment as a partnership for U.S. federal income tax purposes. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on all of our taxable income at the corporate tax rate and would likely pay additional state and local income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in 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.
We have subsidiaries that are treated as corporations for U.S. federal income tax purposes and are subject to corporate-level income taxes.
We conduct a portion of our operations through subsidiaries that are organized as corporations for U.S. federal income tax purposes. We may elect to conduct additional operations through these corporate subsidiaries in the future. These corporate subsidiaries are subject to U.S. corporate-level tax, which reduces the cash available for distribution to us and, in turn, to our unitholders. If the IRS were to successfully assert that these corporations have more tax liability than we anticipate or legislation were enacted that increases the corporate tax rate, our cash available for distribution to our unitholders would be further reduced. Distributions from any such corporate subsidiary will generally be treated as dividend income to the extent of the current and accumulated earnings and profits of such corporate subsidiary. An individual unitholder's share of dividend income from any corporate subsidiary would constitute portfolio income that could not be offset by the unitholder's share of our other losses or deductions.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial, or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. 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 interpretationchanges or differing interpretations at any time. From time to time, members of the U.S. Congress have proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including elimination ofproposals that would eliminate our ability to qualify for partnership tax treatmenttreatment. Recent proposals have provided for certain publicly traded partnerships. For example, the “Clean Energy for America Act,” which is similar to legislation that was commonly proposed during the Obama Administration, was introduced in the Senate on May 2, 2019. If enacted, this proposal would, among other things, repealexpansion of the qualifying income exception within Section 7704(d)(1)(E)for publicly traded partnerships in certain circumstances, and other proposals have provided for the total elimination of the Internal Revenue Code of 1986, as amended,qualifying income exception upon which we rely for our status as a partnership for U.S. federal income tax purposes.treatment.
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 U.S. 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 U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any similar or future legislative changes could negatively impact the value of an investment in our common units. You are urged to consult with your own tax
advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.
If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.
Changes in current state law may subject us to additional entity-level taxation by individual states. Because of state budget deficits and other reasons, several states have been 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 subject to an entity-level Texas franchise tax. Imposition of any such taxes may substantially reduce the cash available for distribution to our unitholders.
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to additional amounts of entity-level taxation, for U.S. federal, state, or local tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
Although we are not subject to U.S. federal income tax other than with respect to our operating U.S. subsidiaries that are treated as corporations for U.S. federal income tax purposes, certain of our foreign operations are subject to certain non-U.S. taxes. If a taxing authority were to successfully assert that we have more tax liability than we anticipate or legislation were enacted that increased the taxes to which we are subject, our cash available for distribution to our unitholders could be further reduced.
Approximately 8.2%13.9% of our consolidated revenues for the year ended December 31, 2019, was2021, were generated in non-U.S. jurisdictions, primarily Mexico, Canada, Argentina, Chile and Argentina.Egypt. Our non-U.S. operations and subsidiaries are generally subject to income, withholding, and other taxes in the non-U.S. jurisdictions in which they are organized or from which they receive income, reducing the amount of cash available for distribution. In computing our tax obligation in these non-U.S. jurisdictions, we are required to take various tax accounting and reporting positions on matters that are not entirely free from doubt and for which we have not received rulings from the governing tax authorities, such as whether withholding taxes will be reduced by the application of certain tax treaties. Upon review of these positions the applicable authorities may not agree with our positions. A successful challenge by a tax authority could result in additional taxes being imposed on us, reducing the cash available for distribution to our unitholders. In addition, changes in our operations or ownership could result in higher than anticipated taxes being imposed in jurisdictions in which we are organized or from which we receive income and further reduce the cash available for distribution. Although these taxes may be properly characterized as foreign income taxes, our unitholders may not be able to credit them against the liability for U.S. federal income taxes on the unitholders’ share of our earnings. In addition, our operations in countries in which we operate now or in the future may involve risks associated with the legal structure used and the taxation on assets transferred into a particular country. Tax laws of non-U.S. jurisdictions are subject to potential legislative, judicial, or administrative changes and differing interpretations, possibly on a retroactive basis. Any such changes may result in additional taxes above the amounts we currently anticipate and further reduce our cash available for distribution to our unitholders.
If the IRS contests the U.S. 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 to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner, because the costs will reduce our cash available for distribution.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders may be substantially reduced.
Legislation applicable to partnership tax years beginning after December 31, 2017 alters the procedures for auditing large partnerships and for assessing and collecting taxes due (including penalties and interest) as a result of a partnership-level U.S. federal income tax audit. Under this legislation, unless we are eligible to (and do) elect to issue revised information statements to our unitholders and former unitholders with respect to an audited and adjusted partnership tax return, the IRS (and some states) may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed. If we are required to pay taxes, penalties and interest as a result of audit adjustments, cash available for distribution to our unitholders may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited tax year. These rules are not applicable for tax years beginning on or prior to December 31, 2017.
Unitholders’Our unitholders are required to pay taxes on their share of our income, will be taxable for U.S. federal income tax purposes, even if they do not receive any cash distributions from us.
Because our Our unitholders will be treated as partnersare required to whom we will allocate taxable income that could be different in amount than the cash we distribute, a unitholder’s allocable share of our taxable income will be taxable
to the unitholder, which may require the payment ofpay any U.S. federal income taxes, and, in some cases, state and local income taxes on the unitholder’stheir share of our taxable income, even if the unitholder receives nothey do not receive cash distributions from us. Unitholders with a greater than 10% interest in us may also be required to include their pro rata share of any global intangible low-taxed income attributable to our foreign corporate subsidiaries in the year in which such income is earned, even if the unitholder receives no 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 liability that results from that income.
In response to current market conditions, we may engage in transactions to delever the Partnership and manage our liquidity that may result in income and gain to our unitholders without a corresponding cash distribution. 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 without receiving a cash distribution. 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 to them of COD income.
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 U.S. 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 the tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the units our unitholders sell will, in effect, become taxable income to our unitholders if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if our unitholders sell their units, they may incur a tax liability in excess of the amount of cash the unitholders receive from the sale.
A substantial portion of the amount realized from a unitholder’s sale of our units, whether or not representing gain, may be taxed as ordinary income to such unitholder due to potential recapture items, including depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than such unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells its units, such unitholder may recognize ordinary income from our allocations of income and gain to such unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.
Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion to the extent such depreciation, amortization, or depletion is not capitalized into cost of goods sold with respect to inventory. This limitation could result in an increase in the taxable income allocable to a unitholder for such taxable year without any corresponding increase in the cash available for distribution to such unitholder.
If our “business interest” is subject to limitation under these rules, our unitholders will be limited in their ability to deduct their share of any interest expense that has been allocated to them. As a result, unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
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. Further, with respect to taxable years beginning after December 31, 2017, subject to the proposed aggregation rules for certain similarly situated business or activities issued by the Treasury Department, a tax-exempt entity with more than one unrelated trades or businesses (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our common units.
Non-U.S. Unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.
Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United StatesU.S. on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a Non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a Non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.
Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the amount realized“amount realized” by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold fromperson. While the transferee amounts that should have been withheld by the transferees but were not withheld. Because thedetermination of a partner’s “amount realized” generally includes any decrease of a partner’s share of the partnership’s liabilities, 10%the Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership, such as our units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the amount realized could exceed the total cash purchase price for the units. However, pending the issuance of final regulations, the IRS has suspended the application of this withholding ruletransferor, and thus will be determined without regard to transfers of publicly traded interestsany decrease in publicly traded partnerships. If recently promulgated regulations are finalized as proposed, such regulations would provide, with respect to transfers of publicly traded interests in publicly traded partnerships effected through a broker, that the obligation to withhold is imposed on the transferor’s broker and that a partner’s “amount realized” does not include a partner’s share of a publicly traded partnership’s liabilities for purposesliabilities. The Treasury regulations and other guidance from the IRS provide that withholding on a transfer of determiningan interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to January 1, 2023. Thereafter, the amount subjectobligation to withholding. However, itwithhold on a transfer of interests in a publicly traded partnership that is not clear when such regulations will be finalizedeffected through a broker is imposed on the transferor’s broker. Current and if they will be finalizedprospective Non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in their current form.our common units.
We will 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 the common units.
Due to a number of factors, including our inability to match transferors and transferees of common units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns.
We prorate our items of income, gain, loss, and deduction for U.S. 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 aspects of our proration method and could change the allocation of items of income, gain, loss, and deduction among our unitholders.
We prorate our items of income, gain, loss, and deduction for U.S. 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. Although final Treasury Regulations allow publicly traded partnerships to use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, these regulations do not specifically authorize all aspects of the proration
method we have adopted. If the IRS were to successfully challenge our proration method, we may be required to change our allocation of items of income, gain, loss, and deduction among our unitholders.
Taxable income from our non-U.S. businesses is not eligible for the 20% deduction for qualified publicly traded partnership income.
For taxable years beginning after December 31, 2017 and ending on or before December 31, 2025, a unitholder is generally allowed a deduction equal to 20% of our “qualified publicly traded partnership income” that is allocated to such unitholder. For purposes of the deduction, the term qualified publicly traded partnership income includes the net amount of such unitholder’s allocable share of our income that is effectively connected to our U.S. trade or business activities. Because our non-U.S. business operations earn income that is not effectively connected with a U.S. trade or business, unitholders may not apply the 20% deduction for qualified publicly traded partnership income to that portion of our income.
A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those 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 to the short seller, any of our income, gain, loss, or deduction with respect to those units may not be reportable by the unitholder, and any cash distributions received by the unitholder as to those 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 loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates ourselves using a methodology based on the market value of our common units as a means to determine the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction for U.S. federal income tax purposes.
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 from our unitholders’ sale of common units and could 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.
Unitholders will likely be subject to non-U.S., state and local taxes, and return filing requirements in jurisdictions where they do not live as a result of investing in our common units.
In addition to U.S. federal income taxes, unitholders will likely be subject to other taxes, including non-U.S., state and local taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or control property now or in the future, even if they do not live in any of those jurisdictions. Unitholders will likely be required to file non-U.S., state, and local income tax returns and pay non-U.S., state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. In the United States, we own assets and conduct business in many states, most of which currently impose a personal income tax on individuals and an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own or control assets or conduct business in additional jurisdictions that impose a personal income tax. It is our unitholders’ responsibility to file all U.S. federal, non-U.S., 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.
Unitholders may be subject to tax in one or more non-U.S. jurisdictions, including Canada, Mexico, Argentina, Egypt and Argentina,Chile as a result of owning our common units if, under the laws of any such jurisdiction, we are considered to be carrying on business there. If unitholders are subject to tax in any such jurisdiction, they may be required to file a tax return with, and pay taxes to, that jurisdiction based on their allocable share of our income. We may be required to reduce distributions to unitholders on account of any withholding obligations imposed upon us by that jurisdiction in respect of such allocation to the unitholders. In addition, the United StatesU.S. may not allow a tax credit for any foreign income taxes that unitholders directly or indirectly incur.
Item 1B. Unresolved Staff Comments.
None.
Item 2. Properties.
As of December 31, 2019,2021, we owned a fabrication facility in Midland, Texas, consisting of an aggregate of approximately 177,000 square feet of structures that are located on 38.5 acres of land. In addition, we own a facilitytwo facilities in Oklahoma City, Oklahoma, and additional service facilities in North Dakota, Oklahoma, Texas, and Utah. We lease 2318 additional service facilities in Alabama, Arkansas, California, Colorado, Kansas, Louisiana, New Mexico, Oklahoma, Texas and West Virginia, Wyoming,Virginia. We also lease service facilities and foreign locationsadministrative offices in Argentina, Canada, Egypt and Mexico. We lease a number of storage facilities located across the geographic markets we serve. We utilizeDuring 2021 we utilized a portion of TETRA’s headquarters in The Woodlands, Texas as our headquarters office. As of January 2022, we are leasing our own office space in The Woodlands, Texas for our headquarters. Our primary assets include our fleet of compression and other equipment. See "Item“Item 1 Business - CompressionProducts and Services" - Contract Services,” for a discussion and description of our compression fleet. All obligations under our 7.50% Senior SecuredFirst Lien Notes and our Second Lien Notes are secured by a first-lien security interestinterests in substantially all of our assets, including our fabrication facilities in Midland, Texas and Oklahoma City, Oklahoma, but excluding other real property assets. As of January 2022, we sold our facilities in Oklahoma City, and we currently own no real property in Oklahoma.
Item 3. Legal Proceedings.
From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of business. While the outcome of lawsuits against us cannot be predicted with certainty, management does not consider it reasonably possible that a loss resulting from such lawsuits in excess of any amounts accrued has been incurred that is expected to have a material adverse effect on our financial condition, results of operations, or cash flows.
Item 4. Mine Safety Disclosures.
Not applicable.
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Repurchases of Equity Securities.
Market Information
Our common units are traded on the NASDAQ Global Market ("NASDAQ") under the symbol “CCLP.” As of March 12, 2020,10, 2022, there were 3184 holders of record of the common units. The actual number of common unitholders is greater than this number of record holders and includes common unitholders who are beneficial owners but whose shares are held in street name by banks, brokers and other nominees.
Distribution Policy
Our partnership agreement requires us to distribute, no later than 45 days after the end of each quarter, all of our available cash, as defined below, at the end of each quarter. Our ability to pay our minimum quarterly distribution is subject to various restrictions and other factors, and thereThere is no guarantee that we will pay any specific distribution in any quarter.
Definition of Available Cash. We define Available Cash in the partnership agreement, and it generally means, for each fiscalany quarter, the sum of all cash and cash equivalents on hand at the end of thethat quarter:
•less the amount of cash reserves established by our general partner to:
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◦ | provide for the proper conduct of our business after the end of the quarter; |
| |
◦ | comply with applicable law, any of our future debt instruments or other agreements; or |
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◦ | provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for future distributions, unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages for such quarter); |
◦provide for the proper conduct of our business after the end of the quarter;
◦comply with applicable law, any of our future debt instruments or other agreements; or
◦provide funds for future distributions;
•plus, if our general partner so determines, all or any portion of any additional cash and cash equivalents on hand on the date of determination of Available Cash for the quarter resulting from working capital borrowings made after the end of the quarter.
Working capital borrowings are borrowings that are made under a credit agreement, commercial paper facility, or 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 additional working capital borrowings.
Common Units. We pay quarterly distributions to the holders of common units to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of debt service and other contractual obligations, fees and expenses, including cash payments to our general partner and its affiliates. On December 20, 2018, we announced that, given the decline in our common unit price, we were reducing our common unit distributions from $0.75 per unit per year (or $0.1875 per quarter) to $0.04 per unit per year (or $0.01 per quarter) for a period of up to four quarters, beginning with the fourth quarter of 2018. We used a portion of the approximately $34 million of savings from the reduced distribution to redeem the remaining Preferred Units for cash and avoid the dilution to our common unitholders that would occur if the Preferred Units were converted into common units.expenses. Beginning with the distribution for the fourth quarter of 2018, we have paid a distribution of $0.01 per common unit, or $0.04 on an annualized basis. As a result, no payments are due under our incentive distribution rights to our general partner in connection with these quarterly distributions. (See discussion of incentive distribution rights below.) There is no guarantee that we will continue to pay the reduced current quarterly distribution on the common units or be able to increase it in the future. Our Second Lien Notes indenture further restricts our ability to make distributions in respect of our common units in any amount exceeding $0.04 per common unit per year, unless such increased distribution is funded by proceeds from an equity offering. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Distributions attributable to the year ended 20192021 totaled $0.04 per common unit. See "Item“Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources - Cash Flows - Financing Activities"Activities” for a discussion of restrictions on our ability to make distributions.
General Partner Interest and Incentive Distribution Rights. Initially, our general partner was entitled to approximately 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its initial 2.0% general partner interest. Our general partner’s initial 2.0% interest in our distributions has been reduceddecreased to approximately 1.4%0.5% and may be reduced further reduced if we issue additional limited partner units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its current general partner interest.
Our general partner also holds incentive distribution rights ("Incentive Distribution Rights") that entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from operating surplus in excess of $0.445625 per common unit per quarter. The maximum distribution of 50.0% includes distributions paid to our general partner on its 2.0% general partner interest and assumes that our general partner maintains its general partner interest at 2.0%. The maximum distribution of 50.0% does not include any distributions that our general partner may receive on any limited partner units that it owns.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Period | | Total Number
Purchased | | Average
Unit | | Total Number of Units
Purchased as Part of
Publicly Announced
Plans or Programs
| | Maximum Number (or
Approximate Dollar Value) of
Units that May Yet be
Purchased Under the Publicly Announced Plans or Programs |
OctOctober 1 – OctOctober 31, 20192021 | | — |
| | —$ |
| | | N/A | | N/A |
NovNovember 1 – NovNovember 30, 20192021 | | — |
| | — |
| | N/A | | N/A |
DecDecember 1 – DecDecember 31, 20192021 | | — |
| | — |
| | N/A | | N/A |
| Total | | — |
| | |
| N/A | | N/A | | N/A |
Securities Authorized for Issuance under Equity Compensation Plans.
See "Item“Item 12. Security Ownership of Certain Beneficial Owners and Management"Management” for information regarding our equity compensation plans as of December 31, 2019.2021.
Item 6. Selected Financial Data.
The following tables set forth our selected consolidated financial data for the years ended December 31, 2019,2018,2017, 2016, and 2015. The selected consolidated financial data does not purport to be complete and should be read in conjunction with, and is qualified by, the more detailed information, including the Consolidated Financial Statements and related Notes and "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation” appearing elsewhere in this Annual Report. Please read “Item 1A. Risk Factors” for a discussion of the material uncertainties that might cause the selected consolidated financial data not to be indicative of our future financial condition or results of operations. During 2016 and 2015, we recorded significant impairments of long-lived assets and goodwill.Not required.
|
| | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | | (In Thousands, Except Per Unit Amounts) |
| Income Statement Data | | |
| | |
| | |
| | |
| | |
|
| Revenues | | $ | 476,581 |
| | $ | 438,663 |
| | $ | 295,566 |
| | $ | 311,363 |
| | $ | 457,641 |
|
| Cost of revenues | | 317,499 |
| | 308,397 |
| | 193,498 |
| | 191,260 |
| | 290,660 |
|
| Depreciation and amortization expense | | 76,663 |
| | 70,500 |
| | 69,140 |
| | 72,123 |
| | 81,838 |
|
| Impairments and other charges | | 3,160 |
| | 681 |
| | — |
| | 10,223 |
| | 11,797 |
|
| Insurance recoveries | | (555 | ) | | — |
| | (2,352 | ) | | — |
| | — |
|
| Selling, general, and administrative expenses | | 43,100 |
| | 39,600 |
| | 33,438 |
| | 36,222 |
| | 43,479 |
|
| Goodwill impairment | | — |
| | — |
| | — |
| | 92,334 |
| | 139,444 |
|
| Interest expense, net | | 53,375 |
| | 52,585 |
| | 43,135 |
| | 38,055 |
| | 34,964 |
|
| Series A Preferred fair value adjustment | | 1,470 |
| | (838 | ) | | (3,402 | ) | | 5,036 |
| | — |
|
| Other expense, net | | (511 | ) | | 2,101 |
| | (216 | ) | | 2,383 |
| | 2,190 |
|
| Income (loss) before income tax provision | | (17,620 | ) | | (34,363 | ) | | (37,675 | ) | | (136,273 | ) | | (146,731 | ) |
| Net income (loss) | | $ | (20,973 | ) | | $ | (36,978 | ) | | $ | (40,459 | ) | | $ | (138,138 | ) | | $ | (146,630 | ) |
| Net income (loss) per common unit, basic | | $ | (0.44 | ) | | $ | (0.88 | ) | | $ | (1.13 | ) | | $ | (4.07 | ) | | $ | (4.36 | ) |
| Weighted average common units outstanding, basic | | 47,006,543 |
| | 41,552,804 |
| | 35,035,428 |
| | 33,262,376 |
| | 33,169,413 |
|
| Net income (loss) per common unit, diluted | | $ | (0.44 | ) | | $ | (0.88 | ) | | $ | (1.13 | ) | | $ | (4.07 | ) | | $ | (4.36 | ) |
| Weighted average common units outstanding, diluted | | 47,006,543 |
| | 41,552,804 |
| | 35,035,428 |
| | 33,262,376 |
| | 33,169,413 |
|
| Cash distributions declared per common unit | | $ | 0.04 |
| | $ | 0.57 |
| | $ | 0.75 |
| | $ | 1.51 |
| | $ | 1.98 |
|
32
|
| | | | | | | | | | | | | | | | | | | | |
| | | December 31, |
| | | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
| | | (In Thousands) |
| Balance Sheet Data | | |
| | |
| | |
| | |
| | |
|
| Working capital | | $ | 19,666 |
| | $ | 57,394 |
| | $ | 38,141 |
| | $ | 52,090 |
| | $ | 59,300 |
|
| Total assets | | 822,246 |
| | 826,744 |
| | 742,932 |
| | 786,140 |
| | 966,627 |
|
| Long-term debt | | 638,238 |
| | 633,013 |
| | 512,176 |
| | 504,090 |
| | 566,658 |
|
| Partners' capital | | 48,991 |
| | 67,403 |
| | 95,027 |
| | 143,249 |
| | 332,158 |
|
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion is intended to analyze major elements of our consolidated financial statements and provide insight into important areas of management’s focus. This section should be read in conjunction with ourthe Consolidated Financial Statements and accompanying Notes included elsewhere in this Annual Report. This discussion includes forward-looking statements that involve certain risks and uncertainties.
This section of this Form 10-K generally discusses 2019 and 2018 items and year-to-year comparisons between 2019 and 2018. Discussions of 2017 items and year-to-year comparisons between 2018 and 2017 that are not included in this Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2018.
Statements in the following discussion may include forward-looking statements. These forward- lookingforward-looking statements involve risks and uncertainties. See “Item 1A. Risk Factors,” for additional discussion of these factors and risks.
Previously, our operations included our new unit sales business that consisted of the fabrication and sale of new standard and custom-designed, engineered compressor packages fabricated primarily at our facility in Midland, Texas. In the fourth quarter of 2020, we fully exited the new unit sales business. These operations were previously included in equipment sales revenues and are now reflected as discontinued operations for all periods presented.
On January 29, 2021, Spartan acquired from TETRA the Partnership’s general partner, IDRs and 10.95 million common units in the Partnership in the GP Sale. In connection with the GP Sale, on January 29, 2021, TETRA entered into the Transition Services Agreement with the Partnership, pursuant to which TETRA provided certain accounting, information technology and back office support services to the Partnership for a period of up to one year following closing. The Transition Services Agreement with TETRA expired on January 31, 2022.
On November 10, 2021, the Partnership entered into the Contribution Agreement with CSI Compressco GP, Spartan and Compressco Sub. Pursuant to the terms of the Contribution Agreement, Spartan contributed Spartan Treating to the Partnership. As the Partnership and Spartan Treating were under common control at the time of the Spartan Acquisition, the results of operations have been combined for the Partnership and Spartan Treating from the date common control began, January 29, 2021. See Note 4 - “Common Control Acquisition” in the Notes to Consolidated Financial Statements in this Annual Report for further information.
Business Overview
We provide services including natural gas compression services and treating services. Natural gas compression equipment is used for natural gas and oil production, gathering, artificial lift, production enhancement, transmission, processing, and storage. We also provide a variety of natural gas treating services. Our compression and related services business includes a fleet of more than 5,200approximately 4,800 compressor packages providing approximately 1.2 million capacity in aggregate horsepower, utilizing a full spectrum of low-, medium-, and high-horsepower engines. Our equipment sales businesstreating fleet includes the fabrication, assembly,amine units, gas coolers, and sale of both standard and custom-designed, engineered compressor packages.related equipment. Our design aftermarket business provides compressor package overhaul, repair, engineering and design, reconfiguration and maintenance services, as well as the sale of compressor package parts and components manufactured by third-party suppliers. Our customers operate throughout many of the onshore producing regions of the United States, as well as in a number of international locations, including the countries of Mexico, Canada, Argentina, Egypt and Argentina.Chile.
Our operations are significantly dependent upon Demand for our services is directly driven by the demand for, and production of crude oil and the associated natural gas from unconventional shale plays, production of natural gas from conventional plays and the transmission of natural gas to and within sales pipelines. Our fleet of compressors, ranging from 20 to 2,500 horsepower per unit, allows us to service our customers compression needs at the wellhead through high-horsepower compression needs at centralized gathering and gas lift facilities.
During 2020, macroeconomic uncertainty in the oil and natural gas productionindustry drove steep declines in the domestic and international markets in which we operate. Beginning in 2017 and continuing throughout all of 2019, shale production forspending by oil and the associated natural gas produced from these wells provided improved compression demand opportunities for our products and services. This growth in demand continuesoperators which led to drive increasesa decline in our compression servicesfleet utilization and impacted revenues through increased activity and customer contract pricing. Oil prices began to stabilize during the third and fourth quarters of 2020 and gained strength throughout 2021, reaching an average of $77 per barrel in the fourth quarter of 2021. This has resultedimprovement in increased utilization of our compression equipment fleet, with over 1.06 million horsepower of our compression equipment in service as of December 31, 2019. During 2019, we reached the highest overall utilization since the acquisition of Compressor Systems, Inc. ("CSI") in 2014 at 90.1% and at December 31, 2019 we are close to maximum utilization for our high-horsepower class at 97.9%. Further, over this same period, the shift to gas lift as a preferred lifting method improved demand for our complete range of product offerings. While we have experienced increased demand and utilization for certain of our compressor packages, the recent significant decline in oilcommodity prices, as well as the volatility and declinesbeginning of a recovery in the stockgeneral economy and the energy sector, has resulted in an increase in activity levels from our contract services and aftermarket services customers. Revenue from contract services increased each quarter in 2021. In addition, we secured orders from key customers for high-horsepower and electric compressors that started generating revenues in the fourth quarter of 2021 and will continue to be deployed in the first half of 2022. Our customers continue to be focused on capital discipline; however, we continue to see improvement in the levels of quote activity and awards. As the market environment continues to evolve, competition for field employees has increased and inflationary pressures have driven certain costs higher. In addition, supply chain disruptions have impacted the availability of parts and supplies. In addition, war and other armed conflicts, including conflict related to Russia’s invasion of Ukraine, and any resulting economic downturn could adversely affect our results of operations, impair our ability to raise capital or otherwise adversely impact our ability to realize certain business strategies. We will continue to monitor these risks and take the necessary actions to mitigate them.
We have and will continue to evaluate the sale of non-core assets, including our low-horsepower compression fleet. We can provide no assurance that we will consummate a future sale of our low-horsepower compression fleet.
In 2020, we took an aggressive approach towards cost management to improve our financial performance and liquidity. We implemented temporary and permanent cost reductions, including reductions in capital expenditures, workforce, and salaries. We also implemented furloughs, a reduction in the cash retainers for the directors of our general partner, the suspension of 401(k) matching contributions for our employees, targeted reduction in selling, general and administrative expenses, rationalization of our real estate facilities, and negotiated reductions in expenditures with many of our suppliers. In 2021, with the improvement in market conditions, we have reversed most of the cost-reduction actions taken in 2020 and have increased capital allocated to growth. With the rapidly changing market environment, we will continue to proactively manage our capital allocation strategies and monitor our expenses and financial performance.
While we are not able to predict how long the COVID-19 pandemic will continue to impact overall market conditions, the demand for oil and gas and the effect it will ultimately have on our business, we continued to see activity levels increase in the fourth quarter of 2021. We are encouraged by the strong oil and gas commodity prices and projections for demand recovery; however, the risk of additional strains of COVID-19, risk that developed vaccines may not be successful in preventing COVID-19 or its spread or the potential outbreak of a new or mutated virus, and the possibility of future lockdowns makes any forecast for improvement uncertain. In addition, continued capital discipline throughout the energy sector may limit production growth even when the economy recovers from the pandemic. Despite challenging and changing market conditions, we will continue to maintain our commitment to safety and service quality for our customers.
Results of Operations
The following data should be read in conjunction with the Consolidated Financial Statements and the associated Notes contained elsewhere in this document. On November 10, 2021, Spartan contributed Spartan Treating to the Partnership. As the Partnership and Spartan Treating were under common control at the time of the Spartan Acquisition, the results of operations have been combined for the Partnership and Spartan Treating from the date common control began which was January 29, 2021. See Note 4 - “Common Control Acquisition” in the Notes to Consolidated Financial Statements in this Annual Report for further information. Previously, our equipment sales business included our new unit sales business that consisted of the fabrication and sale of new standard and custom-designed, engineered compressor packages fabricated primarily at our facility in Midland, Texas. We sold the Midland facility in July 2020. In the fourth quarter of 2020, we fully exited the new unit sales business and we have reflected these operations as discontinued operations for all periods presented. See Note 10 - “Discontinued Operations” in the Notes to Consolidated Financial Statements in this Annual Report for further information. Used equipment sales revenue continues to be included in equipment sales revenue.
2021 Compared to 2020
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | | | | Period-to-Period Change | | | Percentage of Total Revenues | | Period-to-Period Change |
| Consolidated Results of Operations | | 2021 | | 2020 | | | | 2021 vs. 2020 | | | 2021 | | 2020 | | 2021 vs. 2020 |
| | | (In Thousands) | | | | | |
| Revenues: | | | | | | | | | | | | | | | |
| Contract services | | $ | 234,998 | | | $ | 228,088 | | | | | $ | 6,910 | | | | 77.3 | % | | 75.6 | % | | 3.0 | % |
| Aftermarket services | | 53,534 | | | 60,290 | | | | | (6,756) | | | | 17.6 | % | | 20.0 | % | | (11.2) | % |
| Equipment rentals | | 12,903 | | | — | | | | | 12,903 | | | | 4.2 | % | | — | % | | 100.0 | % |
| Equipment sales | | 2,736 | | | 13,209 | | | | | (10,473) | | | | 0.9 | % | | 4.4 | % | | (79.3) | % |
| Total revenues | | 304,171 | | | 301,587 | | | | | 2,584 | | | | 100.0 | % | | 100.0 | % | | 0.9 | % |
| Cost of revenues: | | | | | | | | | | | | | | | |
| Cost of contract services | | 118,702 | | | 108,843 | | | | | 9,859 | | | | 39.0 | % | | 36.1 | % | | 9.1 | % |
| Cost of aftermarket services | | 45,578 | | | 52,444 | | | | | (6,866) | | | | 15.0 | % | | 17.4 | % | | (13.1) | % |
| Cost of equipment rentals | | 1,065 | | | — | | | | | 1,065 | | | | 0.4 | % | | — | % | | 100.0 | % |
| Cost of equipment sales | | 3,342 | | | 12,946 | | | | | (9,604) | | | | 1.1 | % | | 4.3 | % | | (74.2) | % |
| Total cost of revenues | | 168,687 | | | 174,233 | | | | | (5,546) | | | | 55.5 | % | | 57.8 | % | | (3.2) | % |
| Depreciation and amortization | | 78,234 | | | 80,007 | | | | | (1,773) | | | | 25.7 | % | | 26.5 | % | | (2.2) | % |
| Impairments and other charges | | — | | | 15,367 | | | | | (15,367) | | | | — | % | | 5.1 | % | | (100.0) | % |
| Insurance recoveries | | — | | | (517) | | | | | 517 | | | | — | % | | (0.2) | % | | (100.0) | % |
| Selling, general, and administrative expense | | 43,299 | | | 34,295 | | | | | 9,004 | | | | 14.2 | % | | 11.4 | % | | 26.3 | % |
| | | | | | | | | | | | | | | |
| Interest expense, net | | 54,791 | | | 54,468 | | | | | 323 | | | | 18.0 | % | | 18.1 | % | | 0.6 | % |
| | | | | | | | | | | | | | | |
| Other (income) expense, net | | 3,868 | | | 3,544 | | | | | 324 | | | | 1.3 | % | | 1.2 | % | | 9.1 | % |
| Loss before taxes and discontinued operations | | (44,708) | | | (59,810) | | | | | 15,102 | | | | (14.7) | % | | (19.8) | % | | (25.2) | % |
| Provision for income taxes | | 4,952 | | | 3,144 | | | | | 1,808 | | | | 1.6 | % | | 1.0 | % | | 57.5 | % |
| Loss from continuing operations | | (49,660) | | | (62,954) | | | | | $ | 13,294 | | | | (16.3) | % | | (20.9) | % | | (21.1) | % |
| Loss from discontinued operations, net of taxes | | (612) | | | (10,886) | | | | | $ | 10,274 | | | | (0.2) | % | | (3.6) | % | | (94.4) | % |
| Net loss | | $ | (50,272) | | | $ | (73,840) | | | | | $ | 23,568 | | | | (16.5) | % | | (24.5) | % | | (31.9) | % |
Revenues
Contract services revenues increased by $6.9 million, or 3.0%, during 2021 compared to the prior year primarily due to the Spartan Acquisition which generated $11.1 million of contract services revenue in 2021 from the date of common control. This increase in revenues was partially offset by a decrease in revenues resulting from the impact of the COVID-19 pandemic on revenue in 2020 and 2021. The overall compression fleet horsepower utilization rate as of December 31, 2021 increased to 80.8% compared to 76.4% as of December 31, 2020. In addition, in 2021 we discontinued some of the pricing concessions given in 2020.
Aftermarket services revenues decreased $6.8 million, or 11.2%, during 2021 compared to the prior year partially due to decreased demand for parts and services as customers delayed re-starting maintenance programs on their owned equipment. Additionally, due to the increase in demand for our compression services, our facilities and equipment.workforce were consumed with make-ready and redeployment work limiting the availability for aftermarket services jobs. The contribution of Spartan Treating generated $0.7 million in aftermarket services revenue in 2021 from the date of common control.
We are focusedEquipment rentals revenues increased $12.9 million, or 100.0%, during 2021 due to the Spartan Acquisition.
Equipment sales revenues decreased $10.5 million, or 79.3%, during 2021 compared to the prior year due to a decrease in used unit sales. In 2020, the Partnership increased efforts to sell non-core used compressors to strengthen liquidity during the market downturn.
Cost of revenues
Cost of contract services increased compared to the prior year consistent with increased revenues and includes the addition of Spartan Treating which had $6.3 million of cost in 2021 from the date of common control. Cost of contract services as a percentage of contract services revenues increased from 47.7% in 2020 to 50.5% in 2021. This increase was partially due to higher make-ready expenses and start-up costs in 2021 which contributed to higher revenues in the fourth quarter of 2021 and will continue to do so in 2022. In addition, inflationary pressures have resulted in increased costs in certain operating cost categories in 2021 including field labor costs and fuel costs.
Cost of aftermarket services decreased in 2021 compared to 2020 consistent with the decrease
in revenues. The addition of Spartan Treating added $0.4 million of costs in 2021 from the date of common control. The cost of aftermarket services was also impacted by inflation in 2021.
Cost of equipment rentals increased $1.1 million, or 100%, during 2021 due to the Spartan Acquisition.
Cost of equipment sales decreased in 2021 compared to 2020 consistent with the decrease in associated revenues.
Depreciation and amortization
Depreciation and amortization expense primarily consists of the depreciation of compressor packages in our service fleet. In addition,itincludes the depreciation of other operating equipment and facilities and the amortization of intangibles. The contribution of Spartan Treating resulted in $4.3 million of depreciation and amortization in 2021. Depreciation and amortization expense decreased compared to the prior year primarily due to impairments recorded in 2020, reducing the cost basis of our compression fleet.
Impairments and other charges
During the year ended December 31, 2020, we recorded impairments and other charges of $15.4 million primarily on aligningnon-core used compressor equipment—the low-horsepower class of our compression fleet and field inventory for compression and related services. There were no impairments recorded in the current year.
Insurance recoveries
Insurance recoveries relate to meetinsurance claim proceeds received in 2020 associated with fleet compressor packages that were damaged during the growing demandprior year.
Selling, general, and administrative expense
Selling, general, and administrative expenses increased during 2021 compared to 2020 largely due to increased employment expenses, including wages, incentives, benefits, and other employee-related expenses of $6.2 million, the addition of Spartan Treating, which added $3.7 million in expenses in 2021 from the date of common control, increased professional services fees of $0.2 million and increased general expenses such as
office, tax, and insurance expenses of $0.3 million. These increases were offset by decreased bad debt expenses of $1.2 million.
Interest expense, net
Interest expense, net increased to $54.8 million during 2021 compared to $54.5 million in 2020 due to higher interest rates associated with our Second Lien Notes following the June 2020 debt exchange.
Other (income) expense, net
Other (income) expense, net, was $3.9 million of expense during 2021 compared to $3.5 million of expense in 2020. This increase in expense is primarily due to $5.2 million of increased losses on disposal of assets and increased foreign currency losses of $1.2 million, partially offset by $4.8 million of decreased fees associated primarily with the unsecured debt exchange transaction in 2020.
Provision for high-horsepower. Our high-horsepower engines are well suited for centralized gas lift, which isincome taxes
As a preferred means of artificial lift as customers see increasing gas-to-oil ratios in key basins where their focus is on multi-well pads and completion of longer lateral wells. We continue to focus growth capital toward meeting the demands for high-horsepower in centralized gas lift applications and are strategically selling low-horsepower and non-core fleet units to aid in this shift. In addition,partnership, we are refocusinggenerally not subject to income taxes at the entity level, and our low-horsepower engines to target liquids (oilpartners are separately taxed on their share of our taxable income. However, a portion of our business is conducted through taxable U.S. corporate subsidiaries. Accordingly, a U.S. federal and natural gas condensates) through production enhancement and artificial lift methods including gas assisted plunger lift ("GAPL") and backside auto injection services ("BAIS"), which allows customers to uplift liquids production and enhance economic returns on older wells.
Givenstate income tax provision has been reflected in the high demand for compression services we have experienced through February 2020accompanying statements of operations. Certain of our operations are located outside of the United States and the high utilization ofPartnership, through its foreign subsidiaries, is responsible for income taxes in these countries.
Our effective tax rate for the year ended December 31, 2021, was negative 11.1% primarily due to taxes in certain foreign jurisdictions and Texas gross margin taxes combined with losses generated in entities for which no related tax benefit has been recorded. Included in our compression equipment fleet, we continue to focus on our ability to appropriately expanddeferred tax assets are net operating loss carryforwards and maintain our compression equipment fleet in order to serve our customers. While the current industry market for traditional debt and equity financing is difficult, we continue to review all optionstax credits that are available to usoffset future income tax liabilities in the U.S. as well as in certain foreign jurisdictions.
Income (loss) from discontinued operations, net of tax
Income (loss) from discontinued operations, net of tax decreased from a $10.9 million loss for the year ended December 31, 2020 to expand our fleet.a $0.6 million loss for the year ended December 31, 2021. The Partnership exited the new unit sales business during 2020, with final deliveries made in October. The prior year loss includes $36.8 million of new unit sales revenues and $0.8 million of other income, offset by $38.5 million of cost of sales, $5.5 million of impairments, and $3.9 million of selling, general, and administrative expenses.
How We Evaluate Our Operations
Operating Expenses. We use operating expenses as a performance measure for our business. We track our operating expenses using month-to-month, quarter-to-quarter, year-to-date, and year-to-year comparisons and as compared to budget. This analysis is useful in identifying adverse cost trends and allows us to investigate the cause of these trends and implement remedial measures if possible. The most significant portions of our operating expenses are for our field labor, repair and maintenance of our equipment, and for the fuel and other supplies consumed while providing our services. The costs of other materials consumed while performing our services, ad valorem taxes, other labor costs, truck maintenance, rent on storage facilities, vehicle leases and insurance expenses comprise the significant remainder of our operating expenses. Our operating expenses generally fluctuate with our level of activity.
Our labor costs consist primarily of wages and benefits for our field and fabrication personnel, as well as expenses related to their training and safety. Additional information regarding our operating expenses for the year ended December 31, 2019,2021 is provided within the Results of Operations sections below.above.
Adjusted EBITDA. We view Adjusted EBITDA as one of our primary management tools, and we track it on a monthly basis, both in dollars and as a percentage of revenues (typically compared to the prior month, prior year period, and to budget). We define Adjusted EBITDA as earnings before interest, taxes, depreciation and amortization, and before certain charges, including impairments, bad debt expense attributable to bankruptcy of customers, equity compensation, non-cash chargescosts of compressors sold, gain on extinguishment of debt, write-off of
unamortized financing costs, severance and other non-recurring or unusual expenses or charges, including impairments, equity compensation, bad debt expense attributable to bankruptcy of customer, non-income tax contingency, non-cash costs of compressors sold, fair value adjustments of our Preferred Units, administrative expenses under the Omnibus Agreement paid in equity using common units, write-off of unamortized financing costs, and excluding Series A Convertible Preferred Unit redemption premiums and severance.charges. Adjusted EBITDA is used as a supplemental financial measure by our management to:
| |
• | •assess our ability to generate available cash sufficient to make distributions to our common unitholders andgeneralpartner; •generalpartner; |
evaluate the financial performance of our assets without regard to financing methods, capital structure, or historical cost basis;
•measure operating performance and return on capital as compared to those of our competitors; and
•determine our ability to incur and service debt and fund capital expenditures.
The following table reconciles net income (loss) to Adjusted EBITDA for the periods indicated:
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| Net income (loss) | | $ | (20,973 | ) |
| $ | (36,978 | ) | | $ | (40,459 | ) |
| Provision for income taxes | | 3,353 |
|
| 2,615 |
| | 2,784 |
|
| Depreciation and amortization | | 76,663 |
|
| 70,500 |
| | 69,140 |
|
| Impairments and other charges | | 3,313 |
| | 681 |
| | — |
|
| Bad debt expense attributable to bankruptcy of customer | | 1,768 |
| | — |
| | — |
|
| Interest expense, net | | 53,375 |
|
| 52,585 |
| | 43,135 |
|
| Equity compensation | | 1,064 |
| | 639 |
| | 1,219 |
|
| Expense for unamortized finance costs | | — |
| | 3,539 |
| | — |
|
| Non-income tax contingency | | — |
| | 2,110 |
| | — |
|
| Series A Preferred redemption premium | | 1,468 |
| | — |
| | — |
|
| Series A Preferred fair value adjustments | | 1,470 |
| | (838 | ) | | (3,402 | ) |
| Omnibus expense paid in equity | | — |
| | — |
| | 1,746 |
|
| Severance | | 118 |
| | 12 |
| | 63 |
|
| Non-cash cost of compressors sold | | 6,023 |
| | 4,126 |
| | 8,505 |
|
| Other | | 630 |
| | 176 |
| | 1,011 |
|
| Adjusted EBITDA | | $ | 128,272 |
| | $ | 99,167 |
| | $ | 83,742 |
|
The following table reconciles cash flow from operating activities to Adjusted EBITDA:
|
| | | | | | | | | | | | |
| | | Year Ended December 31, |
| | | 2019 | | 2018 | | 2017 |
| | | (In Thousands) |
| Cash flow from operating activities | | 67,696 |
| | 30,121 |
| | 39,068 |
|
| Changes in current assets and current liabilities | | 311 |
| | 16,614 |
| | (1,357 | ) |
| Deferred income taxes | | (129 | ) | | 178 |
| | (757 | ) |
| Other non-cash charges | | (4,305 | ) | | (3,951 | ) | | (4,391 | ) |
| Bad debt expense attributable to bankruptcy of customer | | 1,768 |
| | — |
| | — |
|
| Non-income tax contingency | | — |
| | 2,110 |
| | — |
|
| Interest expense, net | | 53,375 |
| | 52,585 |
| | 43,135 |
|
| Series A Preferred paid in kind distributions | | (1,123 | ) | | (5,419 | ) | | (8,380 | ) |
| Insurance recoveries | | 555 |
| | — |
| | 2,352 |
|
| Provision for income taxes | | 3,353 |
| | 2,615 |
| | 2,784 |
|
| Acquisition costs | | — |
| | — |
| | — |
|
| Omnibus expense paid in equity | | — |
| | — |
| | 1,746 |
|
| Severance | | 118 |
| | 12 |
| | 63 |
|
| Non-cash cost of compressors sold | | 6,023 |
| | 4,126 |
| | 8,505 |
|
| Software implementation | | 630 |
| | 176 |
| | 1,011 |
|
| Adjusted EBITDA | | $ | 128,272 |
| | $ | 99,167 |
| | $ | 83,779 |
|
| | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | |
| | | 2021 | | 2020 | | |
| | | (In Thousands) |
| Net income (loss) | | $ | (50,272) | | | $ | (73,840) | | | |
| Provision for income taxes | | 4,952 | | | 3,211 | | | |
| Depreciation and amortization | | 78,234 | | | 80,533 | | | |
| Impairments and other charges | | — | | | 20,841 | | | |
| | | | | | |
| Interest expense, net | | 54,791 | | | 54,468 | | | |
| Equity compensation | | 1,954 | | | 1,389 | | | |
| Transaction costs | | 2,146 | | | — | | | |
| ERP Write Off | | 4,635 | | | — | | | |
| Reorganization costs | | 754 | | | — | | | |
| | | | | | |
| | | | | | |
| | | | | | |
| Debt exchange expenses | | — | | | 4,892 | | | |
| Severance | | 114 | | | 2,034 | | | |
| Non-cash cost of compressors sold | | 3,368 | | | 12,812 | | | |
| Prior year sales tax accrual adjustment | | 367 | | | — | | | |
| Manufacturing engine order cancellation charge | | 300 | | | — | | | |
Provision for income taxes, depreciation, amortization and
impairments attributed to discontinued operations | | 256 | | | — | | | |
| Other | | (137) | | | 2,438 | | | |
| Adjusted EBITDA | | $ | 101,462 | | | $ | 108,778 | | | |
Free Cash Flow. We define Free Cash Flow as cash from operations less capital expenditures, net of sales proceeds. Management primarily uses this metric to assess our ability to retire debt, evaluate our capacity to further invest and grow, and measure our performance as compared to our peers. The following table reconciles cash provided by operations, net, to Free Cash Flow for the periods indicated:
| | | | | | | | | | | | | |
| Year Ended December 31, | | |
| 2021 | | 2020 | | |
| (In Thousands) |
| Net cash provided by operating activities | $ | 27,156 | | | $ | 20,762 | | | |
| Capital expenditures, net of sales proceeds | (42,098) | | | (12,334) | | | |
| Midland facility sale proceeds | — | | | 17,000 | | | |
| Free cash flow | $ | (14,942) | | | $ | 25,428 | | | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (In Thousands) |
| Cash from operations, net | $ | 67,696 |
| | $ | 30,121 |
| | $ | 39,068 |
|
| Capital expenditures, net of sales proceeds | (64,773 | ) | | (103,489 | ) | | (25,126 | ) |
| Free cash flow | $ | 2,923 |
| | $ | (73,368 | ) | | $ | 13,942 |
|
Net cash provided by operating activities for the year ended December 31, 2021 includes $40.0 million of revenues in excess of cash expenses partially offset by $12.9 million in working capital changes.
Adjusted EBITDA and Free Cash Flow are financial measures that are not in accordance with U.S. GAAP and should not be considered an alternative to net income, operating income, cash flows from operating activities, or any
other measure of financial performance presented in accordance with U.S. GAAP. These measures may not be comparable to similarly titled financial metrics of other entities, as other entities may not calculate Adjusted EBITDA or Free Cash Flow in the same manner as we do. Management compensates for the limitations of Adjusted EBITDA and Free Cash Flow as analytical tools by reviewing the comparable U.S. GAAP measures, understanding the differences between the measures, and incorporating this knowledge into management’s decision-making processes. Adjusted EBITDA and Free Cash Flow should not be viewed as indicative of the actual amount of cash we have available for distributions or that we plan to distribute for a given period, nor should it be equated with “available cash” as defined in our partnership agreement.
Horsepower Utilization Rate of our Compressor Packages. We measure the horsepower utilization rate of our fleet of compressor packages as the amount of horsepower of compressor packages used to provide services as of a particular date, divided by the amount of horsepower of compressor packages in our services fleet as of such date. Management primarily uses this metric to determine our future need for additional compressor packages for our service fleet and to measure marketing effectiveness.
The following table sets forth the total horsepower in our compression fleet, our total horsepower in service and our total horsepower utilization rate by each horsepower class of our compression fleet as of the dates shown.
| | | | | | | | | | | | | | | | |
| | | December 31, | | |
| | | 2021 | | 2020 | | |
| Horsepower | | | | | | |
| Total horsepower in fleet | | 1,196,842 | | | 1,175,075 | | | |
| Total horsepower in service | | 967,085 | | | 897,446 | | | |
| Total horsepower utilization rate | | 80.8 | % | | 76.4 | % | | |
|
| | | | | | | | | |
| | | December 31, |
| | | 2019 | | 2018 | | 2017 |
| Horsepower | | | | | | |
| Total horsepower in fleet | | 1,177,745 |
| | 1,135,477 |
| | 1,081,919 |
|
| Total horsepower in service | | 1,059,590 |
| | 983,848 |
| | 900,638 |
|
| Total horsepower utilization rate | | 90.0 | % | | 86.6 | % | | 83.2 | % |
The following table sets forth our horsepower utilization rates by each horsepower class of our compression fleet as of the dates shown.
| | | | | | | | | | | | | |
| December 31, | | |
| | 2021 | | 2020 | | |
| Horsepower utilization rate by class | | | | | |
| Low-horsepower (0-100) | 57.3 | % | | 59.4 | % | | |
| Medium-horsepower (101-1,000) | 80.4 | % | | 74.5 | % | | |
| High-horsepower (1,001 and over) | 86.1 | % | | 81.5 | % | | |
| Total Horsepower utilization rate | 80.8 | % | | 76.4 | % | | |
|
| | | | | | | | |
| | December 31, |
| | 2019 | | 2018 | | 2017 |
| Horsepower utilization rate by class | | | | | |
| Low horsepower (0-100) | 70.8 | % | | 66.4 | % | | 65.4 | % |
| Medium-horsepower (101-1,000) | 86.0 | % | | 84.9 | % | | 80.8 | % |
| High-horsepower (1,001 and over) | 97.9 | % | | 95.0 | % | | 92.8 | % |
The total horsepower utilization figuresrate and the utilization rate for the medium and high-horsepower class each increased in 2021 compared to 2020 due to an increase in customer activity levels. The market environment improved in 2021 resulting in an increase in total utilization of 4% compared to the utilization rate as of December 31, 2019 above reflect2020, with meaningful gains in utilization in the impairment of certain low-horsepower class compressor packagesmedium and removal of 20,286 horsepower from the compression fleet during the second quarter of 2019. Through new equipment fabrication, we added 97,118 of horsepower to our fleet during the year ended December 31, 2019.high-horsepower categories.
Net Increases/Decreases in Compression Fleet Horsepower. We measure the net increase (or decrease) in our compression fleet horsepower during a given period by taking the difference between the aggregate horsepower of compressor packages added to the fleet during the period, less the aggregate horsepower of compressor packages removed from the fleet during the period. We measure the net increase (or decrease) in our compression fleet horsepower in service during a given period by taking the difference between the aggregate horsepower of compressor packages placed into service during the period, less the aggregate horsepower of compressor packages removed from service during the period.
Liquidity and Capital Resources
New Equipment Sales BacklogOur primary cash requirements are for distributions, working capital requirements, debt service, normal operating expenses, and capital expenditures. Our potential sources. Our new equipmentof funds areour existing cash balances, cash generated from our operations, asset sales, business includes the design, fabrication, assembly, and sale of both standardlong-term and custom-designed, engineered compressor packages fabricated primarily at our facility in Midland, Texas. The equipment is fabricated to custom or standard specifications, as applicable. Our custom fabrication projects are typically greater in size and scope than standard fabrication projects, requiring more labor, materials, and overhead resources. Our fabrication business requires diligent planning of those resources and project and backlog management in ordershort-term borrowings, which we believe will be sufficient to meet our working capital and growth capital requirements during 2022.We have secured orders from
key customers for high-horsepower and electric compressors which will drive our investment in growth capital and consume liquidity in 2022.
Oil and natural gas commodity prices recovered in the customer delivery datessecond half of 2020 and performance criteria. New equipment sales backlog was $35.5 millionthroughout 2021 from their lows in the first half of 2020. During the beginning of 2022, commodity prices have continued to increase with the West Texas Intermediate price of oil rising to $119.26 per barrel as of December 31, 2019 comparedMarch 7, 2022 and the Henry Hub price for natural gas rising to $105.2$4.61 per MMBtu as of March 8, 2022. Although uncertainty remains, the outlook for the energy sector has improved significantly. If oil and natural gas prices decrease from current levels, our businesses could be negatively impacted. Despite these uncertainties, we remain committed to a long-term growth strategy. Our near-term focus is to balance our investment in growth against our investment in maintaining our revenue-generating assets, while continuing to preserve and enhance liquidity through strategic operating and financial measures. We periodically evaluate engaging in strategic transactions and may consider divesting assets where our evaluation suggests such transactions are in the best interests of our business. We are subject to business and operational risks that could materially and adversely affect our cash flows and, when coupled with risks associated with current debt and equity market conditions, our ability or desire to issue securities. Please read “Item 1A. Risk Factors.”
In November of 2021, in connection with the Spartan Acquisition, we closed a private placement of common units to certain investors for gross proceeds of $52.7 million (the “Private Placement”) and issued $10 million in aggregate principal amount of our 10.000%/10.750% Senior Secured Second Lien Notes due 2026 (the “New Second Lient Notes”) pursuant to a securities purchase agreement (the “Second Lien Notes Sale”). The proceeds of the Private Placement and Second Lien Notes Sale were used for general Partnership purposes, including the redemption of all $80.7 million of our senior unsecured notes in December 2021. These and other transactions completed in the fourth quarter of 2021 improved our overall financial condition and liquidity position.
Following the redeployment of our idle assets, meeting increased demand for our contract services will requireongoingcapital expenditureinvestment, which could be significant. We expect to fund any future capital expenditures, along with potential acquisitions, if any, with existing cash balances and cash flow generated from our operations. We may also seek to expand our compression fleet through finance leases with third parties.
The level of future growth capital expenditures depends on demand for our contract services, the level of cash available to fund these expenditures and our decisions whether to utilize available cash to fund increases in our quarterly common unit distribution, retire debt, or make capital expenditures. We expect capital expenditures in 2022 will range from $50.0 million to $60.0 million. These capital expenditures include approximately $18.0 million to $22.0 million of maintenance capital expenditures, approximately $24.0 million to $28.0 million of capital expenditures primarily associated with the expansion of our contract services fleet and $8.0 million to $10.0 million of capital expenditures related to investments in technology and other initiatives, which include the development and implementation of our new ERP system. The foregoing estimates were based on assumptions regarding current market conditions and the ongoing impact of the COVID-19 pandemic. We expect cash on hand and cash generated from operations will be sufficient to meet cash needs throughout 2022 without the need to incur additional debt or issue additional equity.
On January 20, 2022, our general partner declared a cash distribution attributable to the quarter ended December 31, 2021 of $0.01 per common unit. This distribution equates to a distribution of $0.04 per outstanding common unit on an annualized basis. This quarterly distribution was paid on February 14, 2022 to each of the holders of common units of record as of Decemberthe close of business on January 31, 2018. Changes in2022.
Cash Flows
A summary of our new equipment sales backlog are a functionsources and uses of additional customer orders less completed orders that result in equipment sales revenues for the period. Duringcash during the year ended December 31, 2019, we received cumulative orders2021 and 2020 is as follows:
| | | | | | | | | | | | | |
| Year Ended December 31, | | |
| 2021 | | 2020 | | |
| Operating activities | $ | 27,156 | | | $ | 20,762 | | | |
| Investing activities | (40,509) | | | 5,183 | | | |
| Financing activities | 3,377 | | | (11,685) | | | |
Operating Activities
Net cash provided by operating activities increased by $6.4 million during the year ended December 31, 2021 to $27.2 million compared to $20.8 million provided by operating activities in2020. Our cash provided from operating activities was primarily generated from the provision of $64.4 millioncontract compression and treating services and, for the prior year, the sale of new compressor packages. AllThe increase in cash provided by operating activities was primarily due to the contribution of Spartan Treating.
Cash provided from our foreign operations is subject to various uncertainties, including the volatility associated with interruptions caused by customerbudgetary decisions, uncertainties regarding the renewal of our existing customer contracts, and other changes in contract arrangements,the timing of collection of our receivables, and the repatriation of cash generated by our international operations.
Investing Activities
Capital expenditures duringthe year ended December 31, 2019 new equipment sales backlog is expected2021 increased by $28.7 million compared to be recognized during 2020. Our new equipment sales backlog consists of firm customer orders2020 due to increased activity levels and increasing demand for which a purchase or work order has been received, satisfactory credit or financing arrangements exist, and target delivery dates have been established based on customer requirements. Our new equipment sales backlog is a measure of marketing effectiveness that allows us to plan future labor and raw material needs and measure our success in winning bidscompression services from our customers. In 2020, capital expenditures were largely offset by proceeds of $17.0 million from the sale of our Midland manufacturing facility. Total capital expenditures during 2021 were $47.0 million, offset by $3.4 million from compression units sold. Total capital expenditures for 2021 include $12.8 million of maintenance capital expenditures.
The level of growth capital expenditures depends on our ability to redeploy existing fleet equipment and demand for compression services. If the demand for compression services increases or decreases, the amount of planned expenditures on growth and expansion will be adjusted. We continue to review all capital expenditure plans carefully in an effort to conserve cash and fund our liquidity needs.
Financing Activities
Distributions
Beginning with the distribution to common unitholders during February 2019, we reduced our common unit distributions from $0.75 per unit per year (or $0.1875 per quarter) to $0.04 per unit per year (or $0.01 per quarter). Accordingly, during the year ended December 31, 2021, we distributed $1.9 million of cash distributions to our common unitholders and general partner.
Credit Agreement
As of December 31, 2021, and subject to compliance with the covenants, borrowing base, and other provisions of the agreements that may limit borrowings under the Credit Agreement, we had availability of $15.2 million. On January 29, 2021, the Partnership amended the Loan and Security Agreement dated June 29, 2018 (as amended, restated, amended and restated, supplemented or otherwise modified from time to time, the “Credit Agreement”). The Credit Agreement provides for maximum revolving credit commitments of $35.0 million and includes a $5.0 million reserve, which results in reduced borrowing availability. The Credit Agreement was amended on January 29, 2021 to temporarily increase the size of the reserve to $10.0 million and also required that Spartan backstop all of our outstanding letters of credit. These temporary restrictions expired on April 30, 2021. The Credit Agreement includes a $25.0 million sublimit for letters of credit.
The maturity date of the Credit Agreement is June 29, 2023. As of December 31, 2021, we had an outstanding balance of $0.8 million and had $2.1 million in letters of credit against our Credit Agreement. As of March 10, 2022, we had no balance outstanding under our Credit Agreement and $2.1 million in letters of credit, leaving availability under the Credit Agreement of $14.9 million. The amounts the Partnership may borrow under the Credit Agreement are based on the amounts of the Partnership’s accounts receivable and the value of certain inventory. Decreases in the amount of the Partnership’s accounts receivable and the value of its inventory would result in reduced borrowing availability under the Credit Agreement.
On November 10, 2021, certain unrestricted subsidiaries of the Partnership, Spartan Energy Services LLC, as borrower, and Treating Holdco, as new guarantor, entered into the First Amendment to Loan, Security and Guaranty Agreement (the “Spartan Amendment”) amending the Loan, Security and Guaranty Agreement dated January 29, 2021 (as amended, restated, amended and restated, supplemented or otherwise modified from time to time, the “Spartan Credit Agreement”) with Bank of America, N.A., in its capacity as agent, and the other lenders and loan parties party thereto. As of December 31, 2021, and subject to compliance with the covenants, borrowing base, and other provisions of the agreements that may limit borrowings under the Spartan Credit Agreement, we had availability of $10.9 million.
The maturity date of the Spartan Credit Agreement is January 29, 2024. As of December 31, 2021, we had a $59.0 million outstanding balance. As of March 10, 2022, we have $60.0 million balance outstanding under our Credit Agreement and no letters of credit, leaving availability under the Spartan Credit Agreement of $4.0 million. The amounts that may be borrowed under the agreement are based on the amounts of accounts receivable, the value of certain inventory, and fixed asset net book value. Decreases in the amount of accounts receivable and the value of its inventory and fixed assets would result in reduced borrowing availability under the Spartan Credit Agreement.
Notes
We may from time to time seek to retire or purchase certain amounts of our outstanding senior notes through cash purchases, in open market purchases, privately negotiated transactions or otherwise. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.
7.25% Senior Notes due 2022
On November 10, 2021, the Partnership delivered a notice of redemption with respect to the 7.25% Senior Notes due 2022 (the “2022 Notes”) calling for redemption on December 13, 2021 of all of the outstanding 2022 Notes at a redemption price equal to 100.0% of the principal amount of the 2022 Notes to be redeemed, plus accrued and unpaid interest, if any, on the 2022 Notes (the “Redemption”). The Redemption was financed with the net proceeds from the Private Placement and the issuance of the New Second Lien Notes, among other sources of cash.
7.50% First Lien Notes due 2025
As of December 31, 2021, our 7.50% First Lien Notes due 2025 (the “First Lien Notes”) had $399.8 million outstanding net of unamortized discounts, unamortized deferred financing costs and deferred restructuring gains. Interest on these notes is payable on April 1 and October 1 of each year. The First Lien Notes are secured by a first-priority security interest in substantially all of the Partnership’s and its subsidiaries assets, subject to certain permitted encumbrances and exceptions, and are guaranteedon a senior secured basis by each of the Partnership’s U.S. restricted subsidiaries (other than Finance Corp, certain immaterial subsidiaries and certain other excluded U.S. subsidiaries).
10.000%/10.750% Second Lien Notes due 2026
As of December 31, 2021, our 10.000%/10.750% Second Lien Notes due 2026 (the “Second Lien Notes”) had $173.0 million outstanding, net of unamortized discounts, unamortized deferred financing costs and deferred restructuring gains. Interest on the Second Lien Notes is payable on April 1 and October 1 of each year. The Second Lien Notes are secured by a second-priority security interest in substantially all of the Partnership’s and its subsidiaries assets, subject to certain permitted encumbrances and exceptions, and are guaranteed on a senior secured basis by each of the Partnership’s U.S. restricted subsidiaries (other than Finance Corp, certain immaterial subsidiaries and certain other excluded U.S. subsidiaries). In connection with the payment of PIK Interest (as defined below), if any, in respect of the Second Lien Notes, the issuers will be entitled, to increase the outstanding aggregate principal amount of the Second Lien Notes or issue additional notes (“PIK notes”) under the Second Lien Notes indenture on the same terms and conditions as the already outstanding Second Lien Notes. Interest will accrue at (1) the annual rate of 7.250% payable in cash, plus (2) at the election of the Issuers (made by delivering a notice to the Second Lien Trustee not less than five business days prior to the record date), the annual rate of (i) 2.750% payable in cash (together with the annual rate set forth in clause (1), the “Cash Interest Rate”) or (ii) 3.500% payable by increasing the principal amount of the outstanding Second Lien Notes or by issuing additional PIK notes,
in each case rounding up to the nearest $1.00 (such increased principal amount or additional PIK notes, the “PIK Interest”).
In addition, the indentures governing our First Lien Notes and Second Lien Notes contain customary covenants restricting our ability and the ability of our restricted subsidiaries to: (i) pay distributions on, purchase, or redeem our common units, make certain investments and other restricted payments, or purchase or redeem any subordinated debt; (ii) incur or guarantee additional indebtedness or issue certain kinds of preferred equity securities; (iii) create or incur certain liens securing indebtedness; (iv) sell assets, including dispositions of the collateral securing our First Lien Notes and Second Lien Notes; (v) consolidate, merge, or transfer all or substantially all of our assets; (vi) enter into transactions with affiliates; and (vii) enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us. Our Second Lien Notes indenture further restricts our ability to make distributions in respect of our common units in any amount exceeding $0.04 per common unit per year, unless such increased distribution is funded by proceeds from an equity offering. These covenants are subject to a number of important limitations and exceptions, including certain provisions permitting us, subject to the satisfaction of certain conditions, to transfer assets to certain of our unrestricted subsidiaries. The indentures also contain customary events of default and acceleration provisions relating to events of default, which provide that upon an event of default under the indentures, the Trustee or the holders of at least 25% in aggregate principal amount of the then outstanding First Lien Notes and Second Lien Notes may declare all of the First Lien Notes and Second Lien Notes to be due and payable immediately. We are in compliance with all covenants of the First Lien Notes and Second Lien Notes indentures as of December 31, 2021.
Leases
We have operating leases for some of our office space, warehouse space, operating locations, and machinery and equipment. Our leases have remaining lease terms ranging from 1 to 10 years. Some of our leases have options to extend for various periods, while some have termination options with prior notice of generally 30 days or six months. See Note 6 - “Leases” in the Notes to Consolidated Financial Statements in this Annual Report for further information.
Other Financing
In December 2020, TETRA sold 15 high horsepower compressors to Spartan Energy Services LLC, a subsidiary of Spartan, which were subject to an existing lease with the Partnership. In connection with the GP sale, TETRA also assigned the leases for that compression services equipment with the Partnership to Spartan. As of December 31, 2020, all compression units pursuant to this arrangement were completed. See Note 8 - “Related Party Transactions” in the Notes to Consolidated Financial Statements in this Annual Report for further information.
Off Balance Sheet Arrangements
As ofDecember 31, 2021, we had no “off balance sheet arrangements” that may have a current or future material effect on our consolidated financial condition or results of operations.
Supplemental Guarantor Financial Information
The $400.0 million and $172.7 million in aggregate principal amounts outstanding of the First Lien Notes and the Second Lien Notes, respectively, as of December 31, 2021 are fully and unconditionally guaranteed, subject to certain customary release provisions, on a joint and several senior secured basis, by the following U.S. restricted subsidiaries which are each a 100% owned subsidiary (each a “Guarantor Subsidiary” and collectively the “Guarantor Subsidiaries”):
CSI Compressco Field Services International LLC
CSI Compressco Holdings LLC
CSI Compressco International LLC
CSI Compressco Leasing LLC
CSI Compressco Operating LLC
CSI Compressco Sub, Inc.
CSI Compression Holdings, LLC
Rotary Compressor Systems, Inc.
As a result of these guarantees, we are presenting the following summarized financial information of the obligor group pursuant to Rule 1-02(bb) of Regulation S-X. These schedules are presented using the equity method of accounting for all periods presented. Under this method, investments in subsidiaries are recorded at cost and
adjusted for our share in the subsidiaries’ cumulative results of operations, capital contributions and distributions and other changes in equity. Elimination entries relate primarily to the elimination of investments in subsidiaries and associated intercompany balances and transactions. The Other Subsidiaries column includes financial information for those subsidiaries that do not guarantee the First Lien Notes or the Second Lien Notes. In addition to the financial information of the Partnership, financial information of the Issuers includes CSI Compressco Finance Inc., which had no assets or operations for any of the periods presented.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2021 |
| (In Thousands) |
| | Issuers | | Guarantor
Subsidiaries | | Other
Subsidiaries | | Eliminations | | Consolidated |
| Revenues | | $ | — | | | $ | 424,599 | | | $ | 64,157 | | | $ | (184,585) | | | $ | 304,171 | |
| Cost of revenues (excluding depreciation and amortization expense) | | — | | | 321,454 | | | 31,818 | | | (184,585) | | | 168,687 | |
| Depreciation and amortization | | — | | | 69,954 | | | 8,280 | | | — | | | 78,234 | |
| | | | | | | | | | |
| | | | | | | | | | |
| Selling, general, and administrative expense | | 2,286 | | | 35,807 | | | 5,304 | | | (98) | | | 43,299 | |
| | | | | | | | | | |
| Interest expense, net | | 58,229 | | | (2,472) | | | (966) | | | — | | | 54,791 | |
| | | | | | | | | | |
| Other expense, net | | 38 | | | 5,442 | | | (1,508) | | | (104) | | | 3,868 | |
| Equity in net (income) loss of subsidiaries | | (10,281) | | | (17,433) | | | — | | | 27,714 | | | — | |
| Income (loss) before taxes and discontinued operations | | (50,272) | | | 11,847 | | | 21,229 | | | (27,512) | | | (44,708) | |
| Provision for income taxes | | — | | | 954 | | | 3,796 | | | 202 | | | 4,952 | |
| Income (loss) from continuing operations | | (50,272) | | | 10,893 | | | 17,433 | | | (27,714) | | | (49,660) | |
| Loss from discontinued operations, net of taxes | | — | | | (612) | | | — | | | — | | | (612) | |
| Net income (loss) | | (50,272) | | | 10,281 | | | 17,433 | | | (27,714) | | | (50,272) | |
| Other comprehensive income | | (11) | | | (11) | | | (11) | | | 22 | | | (11) | |
| Comprehensive income (loss) | | $ | (50,283) | | | $ | 10,270 | | | $ | 17,422 | | | $ | (27,692) | | | $ | (50,283) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, 2021 |
| (In Thousands) |
| | Issuers | | Guarantor Subsidiaries | | Other Subsidiaries | | Eliminations | | Consolidated |
| ASSETS | | | | | | | | | | |
| Current assets | | $ | — | | | $ | 56,781 | | | $ | 43,998 | | | $ | — | | | $ | 100,779 | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| Total non-current assets | 170,960,000 | | 586,150 | | | 551,621 | | | 119,130 | | | (635,319) | | | 621,582 | |
| Total assets | | $ | 586,150 | | | $ | 608,402 | | | $ | 163,128 | | | $ | (635,319) | | | $ | 722,361 | |
| | | | | | | | | | |
| LIABILITIES AND PARTNERS’ CAPITAL | | | | | | | | | | |
| Other current liabilities | | $ | 12,351 | | | $ | 41,802 | | | $ | 16,880 | | | $ | — | | | $ | 71,033 | |
| | | | | | | | | | |
| Current liabilities associated with discontinued operations | | — | | | 262 | | | — | | | — | | | 262 | |
| Long-term debt | | 572,640 | | | 456 | | | 58,045 | | | — | | | 631,141 | |
| | | | | | | | | | |
| Operating lease liabilities | | — | | | 17,586 | | | 62 | | | — | | | 17,648 | |
| | | | | | | | | | |
| Long-term affiliate payable and other liabilities | | — | | | 377,435 | | | 37,755 | | | (415,190) | | | — | |
| Other long-term liabilities | | — | | | (99) | | | 1,217 | | | — | | | 1,118 | |
| Total liabilities | | 584,991 | | | 437,442 | | | 113,959 | | | (415,190) | | | 721,202 | |
| Total partners’ capital | | 1,159 | | | 170,960 | | | 49,169 | | | (220,129) | | | 1,159 | |
| Total liabilities and partners’ capital | | $ | 586,150 | | | $ | 608,402 | | | $ | 163,128 | | | $ | (635,319) | | | $ | 722,361 | |
Critical Accounting Policies and Estimates
This discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements. We prepared these financial statements in conformity with U.S. GAAP. In preparing our consolidated financial statements, we make assumptions, estimates, and judgments 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 these estimates on historical experience, available information, and various other assumptions that we believe are reasonable under the circumstances. We periodically evaluate these estimates and judgments, which may change as new events occur, as new information is acquired, and with changes in our operating environment. Actual results are likely to differ from current estimates, and those differences may be material. The following critical accounting policy reflects the most significant judgmentjudgments and estimateestimates used in the preparation of our financial statements.
Business Combinations
When we acquire a business from an entity under common control, whereby the companies are ultimately controlled by the same party both before and after the transaction, it is treated similar to the pooling of interests method of accounting, where the assets and liabilities are recorded at the transferring entity’s historical cost instead of reflecting the fair market value of assets and liabilities.
Impairment of Long-Lived Assets
We conduct a determination of impairment of long-lived assets whenever indicators of impairment are present. If such indicators are present, the determination of the amount of impairment is based on our judgments as to the future operating cash flows to be generated from these assets throughout their estimated useful lives. If an impairment of a long-lived asset is warranted, we estimate the fair value of the asset based on a present value of these cash flows or the value that could be realized from disposing of the asset in a transaction between market participants. The estimation of future operating cash flows is inherently imprecise, and, if our estimates are materially incorrect, it could result in an overstatement or understatement of our financial position and results of operations. In particular, the oil and gas industry is cyclical, and estimates of the period over which future cash flows will be generated, as well as the predictability of these cash flows, can have an additional significant impact on the
carrying value of these assets and, particularly in periods of prolonged down cycles, may result in impairment charges. Historically, our business has not experienced significant impairments of its long-lived compression assets, as utilized compressor packages generate cash flows sufficient to support their carrying values. Unutilized assets are maintained and evaluated on a regular basis. Serviceable compressor packages that are currently unutilized are anticipated to be placed in service in future years as demand increases or as fully depreciated packages in service are replaced. Sales of compressor packages have historically been at selling prices in excess of asset cost. Intangible assets recognized as part of the CSI acquisition include trademark/tradename, customer relationships, and other intangible assets that are supported primarily by the estimated future cash flows of our operations. There were no impairments recorded in 2021. During the year ended December 31, 2019,2020, we recorded impairments of $2.3$15.4 million on certain unitslong-lived assets where the carrying values exceeded their respective fair values, including non-core used compressor equipment, the low-horsepower class of our GasJack(R)compression fleet, reflectingcertain classes of our decisioncompression fleet that are under-utilized due to dispose of these units upon management's determination that refurbishing this equipment was not economic given limited currentmarket preferences, and forecasted demandfield inventory for such equipment. A recoverability analysis was performed on the remaining low-horsepower fleetcompression and we concluded that the remaining fleet was recoverable from estimated future cash flows. During the years ended December 31, 2018 and 2017, we recorded no impairments of long-lived assets.related services. Impairments of our long-lived assets could occur in the future, particularly in the event of a significant and sustained deterioration of natural gas production or pricing.
Results of Operations
The following data should be read in conjunction with the Consolidated Financial Statements and the associated Notes contained elsewhere in this document.
|
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, 2019 |
| |
|
| Period-to-Period Change | | Percentage of Total Revenues | | Period-to-Period Change |
| Consolidated Results of Operations |
| 2019 |
| 2018 |
| 2019 vs. 2018 |
| 2019 | | 2018 | | 2019 vs. 2018 |
| |
| (In Thousands) | | | | | |
| Revenues: |
| |
|
| |
|
| |
|
| | | | | |
| Compression and related services |
| $ | 257,723 |
| | $ | 229,895 |
| | $ | 27,828 |
| | 54.1 | % | | 52.4 | % | | 12.1 | % |
| Aftermarket services | | 76,290 |
| | 70,907 |
| | 5,383 |
| | 16.0 | % | | 16.2 | % | | 7.6 | % |
| Equipment sales |
| 142,568 |
| | 137,861 |
| | 4,707 |
| | 29.9 | % | | 31.4 | % | | 3.4 | % |
| Total revenues |
| 476,581 |
| | 438,663 |
| | 37,918 |
| | 100.0 | % | | 100.0 | % | | 8.6 | % |
| Cost of revenues: |
| |
| | | | | | | | | | |
| Cost of compression and related services |
| 125,104 |
| | 127,128 |
| | (2,024 | ) | | 26.3 | % | | 29.0 | % | | (1.6 | )% |
| Cost of aftermarket services | | 63,757 |
| | 57,870 |
| | 5,887 |
| | 13.4 | % | | 13.2 | % | | 10.2 | % |
| Cost of equipment sales |
| 128,638 |
| | 123,399 |
| | 5,239 |
| | 27.0 | % | | 28.1 | % | | 4.2 | % |
| Total cost of revenues |
| 317,499 |
| | 308,397 |
| | 9,102 |
| | 66.6 | % | | 70.3 | % | | 3.0 | % |
| Depreciation and amortization |
| 76,663 |
| | 70,500 |
| | 6,163 |
| | 16.1 | % | | 16.1 | % | | 8.7 | % |
| Impairments and other charges | | 3,160 |
| | 681 |
| | 2,479 |
| | 0.7 | % | | 0.2 | % | | 364.0 | % |
| Insurance recoveries | | (555 | ) | | — |
| | (555 | ) | | (0.1 | )% | | — | % | | 100.0 | % |
| Selling, general, and administrative expense |
| 43,100 |
| | 39,600 |
| | 3,500 |
| | 9.0 | % | | 9.0 | % | | 8.8 | % |
| Interest expense, net |
| 53,375 |
| | 52,585 |
| | 790 |
| | 11.2 | % | | 12.0 | % | | 1.5 | % |
| Series A Preferred fair value adjustment | | 1,470 |
| | (838 | ) | | 2,308 |
| | 0.3 | % | | (0.2 | )% | | (275.4 | )% |
| Other (income) expense, net |
| (511 | ) | | 2,101 |
| | (2,612 | ) | | (0.1 | )% | | 0.5 | % | | (124.3 | )% |
| Loss before income taxes |
| (17,620 | ) | | (34,363 | ) | | 16,743 |
| | (3.7 | )% | | (7.8 | )% | | (48.7 | )% |
| Provision for income taxes |
| 3,353 |
| | 2,615 |
| | 738 |
| | 0.7 | % | | 0.6 | % | | 28.2 | % |
| Net Loss |
| $ | (20,973 | ) | | $ | (36,978 | ) | | $ | 16,005 |
| | (4.4 | )% | | (8.4 | )% | | (43.3 | )% |
2019 Compared to 2018
Revenues
Compression and related services revenues increased by $27.8 million, or 12.1%, during 2019 compared to the prior year. Growth in demand for compression services positively impacted our compression fleet utilization rates. The overall compression fleet horsepower utilization rate as of December 31, 2019 increased to 90.0% compared to 86.6% as of December 31, 2018. In addition, increased demand has led to improved customer contract pricing for compression services. In response to the overall improving demand for compression services, we continue to invest in growth capital projects to increase certain horsepower categories of our compression fleet.
Aftermarket services revenues increased $5.4 million, or 7.6%, during 2019 compared to the prior year resulting primarily from increased parts sales to existing customers.
Equipment sales revenues increased $4.7 million, a 3.4% increase, during 2019 compared to the prior year, primarily due to higher new equipment sales partially offset by lower used unit sales. Higher new unit sales were due to delivery in 2019 of significant orders received in 2018 primarily related to our customer's build out of new infrastructure projects requiring compression. New infrastructure was needed due to overall growth in associated gas production volumes in the U.S. The level of revenues from equipment sales is typically volatile and difficult to forecast, as these revenues are tied to specific customer projects that vary in scope, design, complexity, and customer needs.
Cost of revenues
Cost of compression and related services decreased compared to the prior year, even with the increase in corresponding revenues resulting from added horsepower and overall increased utilization of our compression fleet. Cost of compression and related services as a percentage of compression and related services revenues decreased from 55.3% during the prior year to 48.5% during the current year due to improved customer contract pricing, higher margins on new compressor equipment, labor efficiencies, and reduced maintenance costs.
Cost of aftermarket services increased compared to the prior year period consistent with the increased
activity and part sales.
Cost of equipment sales increased in accordance with the increase in associated revenues. Cost of equipment sales as a percentage of equipment sales revenues increased primarily due to pricing on equipment sales orders placed in 2018.
Depreciation and amortization
Depreciation and amortization expense primarily consists of the depreciation of compressor packages in our service fleet. In addition,itincludes the depreciation of other operating equipment and facilities and the amortization of intangibles. Depreciation and amortization expense increased compared to the prior year due to increases in the compression fleet.
Impairments and other charges
During the year ended December 31, 2019, we recorded impairments of $2.3 million on certain units of our GasJack(R) fleet, reflecting our decision to dispose of these units upon management's determination that refurbishing this equipment was not economic given limited current and forecasted demand for such equipment. A recoverability analysis was performed on the remaining low-horsepower fleet and we concluded that the remaining fleet was recoverable from estimated future cash flows. In addition, a certain compressor package was written off due to being destroyed by fire, resulting in an additional charge of $0.8 million.
Insurance recoveries
Insurance recoveries relate to insurance claim proceeds received related to fleet compressor packages that were damaged during the prior year.
Selling, general, and administrative expense
Selling, general, and administrative expenses increased during 2019 compared to the prior year. This increase was primarily driven by increased bad debt expense of $1.5 million primarily associated with the bankruptcy of a single customer, increased employee expenses, including wages, incentives, benefits, and other employee related expenses of $1.0 million, and increased professional services fees of $1.0 million. Despite increased expenses, as a percentage of revenues, selling, general and administrative expense remained flat compared to the prior year.
Interest expense, net
Interest expense, net, increased during 2019 compared to the prior year due to higher outstanding debt balances and higher interest rates associated with the issuance of our 7.50% Senior Secured Notes in March 2018 and due to imputed interest on related party financing. This increase was despite the reduction in interest expense from the conversion and redemption of the Preferred Units resulting in lower paid in kind distributions compared to the prior year period. Interest expense, net, during the current and prior year periods includes $3.2 million and $3.1 million, respectively, of finance cost amortization and other non-cash charges.
Series A Preferred fair value adjustment
The Series A Preferred Units fair value adjustment was $1.5 million charged to earnings during 2019 compared to $0.8 million credited to earnings during the prior year. All the remaining outstanding Preferred Units were redeemed for cash on August 8, 2019.
Other (income) expense, net
Other (income) expense, net, was $0.5 million income during 2019 compared to $2.1 million expense during the prior year. This decrease in expense is primarily due to $3.5 million of unamortized deferred financing costs charged to other expense in the prior year as a result of the termination of the previous credit agreement and increased foreign currency gains of $0.5 million. These decreases in expense were offset by increased expenses of $1.5 million of redemption premiums incurred during the current year period in connection with the redemption of Preferred Units for cash.
Provision for income taxes
As a partnership, we are generally not subject to income taxes at the entity level because our income is included in the tax returns of our partners. Our operations are treated as a partnership for federal tax purposes with each partner being separately taxed on its share of taxable income. However, a portion of our business is conducted through taxable U.S. corporate subsidiaries. Accordingly, a U.S. federal and state income tax provision has been reflected in the accompanying statements of operations. Certain of our operations are located outside of the U.S. and the Partnership, through its foreign subsidiaries, is responsible for income taxes in these countries.
Our effective tax rate for the year ended December 31, 2019, was negative 19.0% primarily attributable to taxes in certain foreign jurisdictions and Texas gross margin taxes combined with losses generated in entities for which no related tax benefit has been recorded. Included in our deferred tax assets are net operating loss carryforwards and tax credits that are available to offset future income tax liabilities in the U.S. as well as in certain foreign jurisdictions.
Liquidity and Capital Resources
Our primary cash requirements are for distributions, working capital requirements, debt service, normal operating expenses, and capital expenditures. Our potential sourcesof funds areour existing cash balances, cash generated from our operations, long-term and short-term borrowings, sale-leaseback transactions, and issuances of debt and equity securities, which we believe will be sufficient to meet our working capital and planned growth requirements during 2020. Though demand for compression services and equipment is currently high, we are monitoring the spending plans of our customers due to oil and gas price volatility, the recent significant decline in the price of oil, and the impact on our customer's demand for our products and services. If oil and gas prices remain at current levels or decrease further, our businesses could be negatively impacted. In addition, current conditions in the market for debt and equity securities in the energy sector have increased the difficulty of obtaining equity and debt financing and we expect the stock market decline beginning in March 2020 will make it more difficult to obtain debt and equity financing in the near future. Despite these challenges, we remain committed to a long-term growth strategy. Our near-term focus is to maintain and selectively expand our compression fleet to serve the growing demand for compression services, while continuing to preserve and enhance liquidity through strategic operating and financial measures. We periodically evaluate engaging in strategic transactions and may consider divesting non-core assets where our evaluation suggests such transaction is in the best interests of our business.
Meeting increased demand for our compression services will requireongoingcapital expenditureinvestment, which could be significant. We expect to fund any future capital expenditures, along with potential acquisitions, if any, with existing cash balances, cash flow generated from our operations, and funds received from the issuance of additional debt and equity securities. We may also seek to expand our compression fleet through finance or operating leases with third parties. However, we are subject to business and operational risks that could materially adversely affect our cash flows and together with risks associated with current debt and equity market conditions, our ability or desire to issue such securities.Pleaseread Part I, Item 1A "Risk Factors."
The level of future growth capital expenditures depends on demand for compression services, the level of cash available to fund these expenditures, and our decisions whether to utilize available cash to fund increases in our quarterly common unit distribution, retire debt, or make capital expenditures. We anticipate capital expenditures
in 2020 to range from $47.0 million to $56.0 million. These capital expenditures include approximately $23.0 million to $25.0 million of maintenance capital expenditures, approximately $20.0 million to $25.0 million of capital expenditures primarily associated with the expansion of our compression services fleet, and $4.0 million to $6.0 million of capital expenditures related to investments in technology, primarily software and systems. The foregoing estimates were based on assumptions prior to the March 2020 decline in oil prices and the stock market and we will continue to monitor such estimates going forward. We expect that the combination of cash on hand and operating cash flows expected to be generated during the year will be sufficient to fund capital expenditures without having to incur additional long-term debt and without having to access the equity markets. After funding growth and technology capital investments, we expect to use the remaining distributable cash flow each period beginning in the second quarter of 2020 to reduce debt, primarily through open market purchases of our outstanding 7.25% unsecured senior notes.
On January 20, 2020, our General Partner declared a cash distribution attributable to the quarter ended December 31, 2019 of $0.01 per common unit. This distribution equates to a distribution of $0.04 per outstanding common unit on an annualized basis. This quarterly distribution was paid on February 14, 2020 to each of the holders of common units of record as of the close of business on February 1, 2020.
Cash Flows
A summary of our sources and uses of cash during the year ended December 31, 2019, is as follows:
|
| | | | | | | |
| | Year Ended December 31, |
| | 2019 | | 2018 |
| Operating activities | $ | 67,696 |
| | $ | 30,121 |
|
| Investing activities | (64,218 | ) | | (103,490 | ) |
| Financing activities | (16,970 | ) | | 81,707 |
|
Operating Activities
Net cash provided by operating activities increased by $37.6 million during the year ended December 31, 2019 to $67.7 million compared to $30.1 million provided by operating activities in2018. Our cash provided from operating activities is primarily generated from the provision of compression and related services and the sale of new compressor packages. The increase in cash provided by operating activities was due to increased cash earnings and due to working capital management, particularly related to collections of accounts receivable, management of inventory levels, and timing of payments of accounts payable.
Cash provided from our foreign operations is subject to various uncertainties, including the volatility associated with interruptions caused by customerbudgetary decisions, uncertainties regarding the renewal of our existing customer contracts, and other changes in contract arrangements,the timing of collection of our receivables, and the repatriation of cash generated by our international operations.
Investing Activities
Capital expenditures duringthe year ended December 31, 2019, decreased by $28.2 million compared to 2018 primarily due to the reduction in total capital expenditure plans to grow the capacity of our compression fleet compared to the prior year. As a result of overall improving demand for compression services, beginning in late 2017, we began growth capital expenditure projects to increase certain horsepower categories of our compression fleet resulting in consecutive increases in the total horsepower of our fleet during 2018 and 2019. Maintenance capital expenditures increased during the year ended 2019. Total capital expenditures, net of disposals, during 2019 of $75.8 million include $23.1 million of maintenance capital expenditures, and are net of $6.0 million of non-cash cost of fleet compression units sold. Proceeds of $11.0 million from the sale of property, plant and equipment are primarily the result of a sale-leaseback transaction during the fourth quarter of 2019, whereby we sold ten compression units and immediately leased them back at a monthly rate. These compression units are now included in operating lease right-of-use assets on our consolidated balance sheets.
During the year ended December 31, 2019, $14.8 million was funded by TETRA for the construction of new compressor equipment, and the corresponding financing obligations to TETRA are included in amounts payable to
affiliates and long-term affiliate payable in our consolidated balance sheet. As of December 31, 2019, all compression units were completed and deployed under this agreement.
The level of growth capital expenditures depends on forecasted demand for compression services. If the forecasted demand for compression services increases or decreases, the amount of planned expenditures on growth and expansion will be adjusted, subject to the availability of funds. We continue to review all capital expenditure plans carefully in an effort to conserve cash and fund our liquidity needs.
Financing Activities
Distributions
Beginning with the distribution to common unitholders during February 2019, we reduced our common unit distributions from $0.75 per unit per year (or $0.1875 per quarter) to $0.04 per unit per year (or $0.01 per quarter). We used the cash savings from the reduced distribution to redeem the remaining Preferred Units for cash. Accordingly, during the year ended December 31, 2019, we distributed $1.9 million of cash distributions to our common unitholders and General Partner.
Series A Convertible Preferred Units
In January 2019 we began redeeming Preferred Units for cash, resulting in 2,660,569 Preferred Units being redeemed during the year ended December 31, 2019 for $31.9 million, which includes $1.5 million of redemption premium that was paid. The last redemption of the remaining Preferred Units occurred on August 8, 2019.
Bank Credit Facility
On June 29, 2018, we and two of our wholly owned subsidiaries (collectively the "Borrowers"), and certain of our wholly owned subsidiaries named therein as guarantors (the "Credit Agreement Guarantors"), entered into a Loan and Security Agreement (the "Credit Agreement") with the lenders thereto (the "Lenders"), and Bank of America, N.A., in its capacity as administrative agent, collateral agent, letter of credit issuer, and swing line lender. All of the Borrowers' obligations under the Credit Agreement are guaranteed by certain of their existing and future domestic subsidiaries. The Credit Agreement, as amended, includes a maximum credit commitment of $50.0 million available for loans, letters of credit (with a sublimit of $25.0 million) and swingline loans (with a sublimit of $5.0 million), subject to a borrowing base to be determined by reference to the value of the Partnership’s and any other Borrowers’ accounts receivable and certain inventory. Such maximum credit commitment may be increased by $25.0 million in accordance with the terms and conditions of the Credit Agreement. On June 26, 2019, we entered into an amendment of the Credit Agreement that, among other things, revised and increased the borrowing base, including adding the value of certain inventory in the determination of the borrowing base. As of December 31, 2019, and subject to compliance with the covenants, borrowing base, and other provisions of the agreements that may limit borrowings under the Credit Agreement, we had availability of $17.2 million.
The Borrowers may borrow funds under the Credit Agreement to pay fees and expenses related to the Credit Agreement and for the Borrower's ongoing working capital needs and for general partnership purposes. The revolving loans under the Credit Agreement may be voluntarily prepaid, in whole or in part, without premium or penalty, subject to breakage or similar costs. The maturity date of the Credit Agreement is June 29, 2023. As of December 31, 2019, we had a $3.5 million outstanding balance and we had $3.5 million in letters of credit against our Credit Agreement. As of March 12, 2020, we have no balance outstanding under our Credit Agreement and $3.0 million in letters of credit leaving availability under the CCLP Credit Agreement of $19.1 million.
Borrowings under the Credit Agreement will bear interest at a rate per annum equal to, at the option of the Borrowers, either (i) London Interbank Offered Rate (“LIBOR”) plus a margin based on average daily excess availability or (ii) a base rate plus a margin based on average daily excess availability; such base rate shall be determined by reference to the highest of (a) the prime rate of interest announced from time to time by Bank of America, N.A., (b) the Federal Funds Rate (as defined in the Credit Agreement) rate plus 0.5% per annum and (c) LIBOR for a 30-day interest period on such day plus 1.0% per annum. LIBOR-based loans have an applicable margin ranging between 1.75% and 2.25% per annum. The applicable margin for base-rate loans ranges between 0.75% and 1.25% per annum according to average daily excess availability when financial statements are delivered. In addition to paying interest on outstanding principal under the Credit Agreement, the Borrowers are required to pay a commitment fee in respect of the unutilized commitments thereunder, at the applicable rate
ranging from 0.250% to 0.375% per annum, paid quarterly in arrears based on utilization of the commitments under the Credit Agreement. The Borrowers are also required to pay a customary letter of credit fee equal to the applicable margin on revolving credit LIBOR loans and fronting fees.
The Credit Agreement contains certain affirmative and negative covenants, including covenants that restrict the ability of the Borrowers, the Credit Agreement Guarantors, and certain of their subsidiaries to take certain actions including, among other things and subject to certain significant exceptions, incurring debt, granting liens, making investments, entering into or amending transactions with affiliates, paying dividends, and selling assets. The Credit Agreement also contains a provision that requires compliance with a fixed charge coverage ratio (as defined in the Credit Agreement) of not less than 1.0 to 1.0 in the event that certain conditions associated with outstanding borrowings and cash availability occur. As of December 31, 2019, such conditions have not occurred.
All obligations under the Credit Agreement and the guarantees of those obligations are secured, subject to certain exceptions, by a first priority security interest for the benefit of the Lenders in the Borrowers' and the Credit Agreement Guarantors' present and future accounts receivable, inventory and related assets, and proceeds thereof.
7.25% Senior Notes
The obligations under the 7.25% Senior Notes due 2022 (the "7.25% Senior Notes") are jointly and severally, and fully and unconditionally, guaranteed on a senior unsecured basis by each of our domestic restricted subsidiaries (other than CSI Compressco Finance) that guarantee our other indebtedness (the "Guarantors" and together with us and CSI Compressco Finance Inc., the "Issuers", and the "7.25% Senior Notes Obligors"). The 7.25% Senior Notes and the subsidiary guarantees thereof (together, the "7.25% Senior Notes Securities") were issued pursuant to an indenture described below. As of March 12, 2020, $295.9 million in aggregate principal amount of our 7.25% Senior Notes were outstanding.
The 7.25% Senior Notes Obligors issued the 7.25% Senior Notes Securities pursuant to the Indenture dated as of August 4, 2014 (the "7.25% Senior Notes Indenture") by and among the 7.25% Senior Notes Obligors and U.S. Bank National Association, as trustee (the "Trustee"). The 7.25% Senior Notes accrue interest at a rate of 7.25% per annum and are scheduled to mature on August 15, 2022.
The 7.25% Senior Notes Indenture contains customary covenants restricting our ability and the ability of our restricted subsidiaries to: (i) pay dividends and make certain distributions, investments and other restricted payments; (ii) incur additional indebtedness or issue certain preferred shares; (iii) create certain liens; (iv) sell assets; (v) merge, consolidate, sell or otherwise dispose of all or substantially all of our or their assets; (vi) enter into transactions with affiliates; and (vii) designate our or their subsidiaries as unrestricted subsidiaries under the 7.25% Senior Notes Indenture. The 7.25% Senior Notes Indenture also contains customary events of default and acceleration provisions relating to such events of default, which provide that upon an event of default under the 7.25% Senior Notes Indenture, the Trustee or the holders of at least 25% in aggregate principal amount of the 7.25% Senior Notes then outstanding may declare all amounts owing under the 7.25% Senior Notes to be due and payable. We are in compliance with all covenants of the 7.25% Senior Notes Indenture as of December 31, 2019.
7.50% Senior Secured Notes
The obligations under the 7.50% Senior Secured Notes are jointly and severally, and fully and unconditionally guaranteed on a senior secured basis by each of our domestic restricted subsidiaries (other than CSI Compressco Finance) that guarantee our other indebtedness (the "7.50% Senior Secured Notes Guarantors" and together with the Partnership and CSI Compressco Finance Inc, the "7.50% Senior Secured Notes Obligors"). The 7.50% Senior Secured Notes and the subsidiary guarantees thereof (together, the "7.50% Senior Secured Notes Securities") were issued pursuant to an indenture by and among the 7.50% Senior Secured Notes Obligors and U.S. Bank National Association, as trustee (the "7.50% Senior Secured Notes Indenture"). As of December 31, 2019, $350.0 million in aggregate principal amount of our 7.50% Senior Secured Notes were outstanding. The 7.50% Senior Secured Notes Securities are secured by a first-priority security interest in substantially all of the 7.50% Senior Secured Notes Obligors' assets (other than certain excluded assets) (the "Collateral") as collateral security for their obligations under the 7.50% Senior Secured Notes Securities, subject to certain permitted encumbrances and exceptions.
The 7.50% Senior Secured Notes accrue interest at a rate of 7.50% per annum and are scheduled to mature on April 1, 2025.
The 7.50% Senior Secured Notes Indenture contains customary covenants restricting our ability and the ability of our restricted subsidiaries to: (i) pay distributions on, purchase, or redeem our common units or purchase or redeem any subordinated debt; (ii) incur or guarantee additional indebtedness or issue certain kinds of preferred equity securities; (iii) create or incur certain liens securing indebtedness; (iv) sell assets, including dispositions of the Collateral; (v) consolidate, merge, or transfer all or substantially all of our assets; (vi) enter into transactions with affiliates; and (vii) enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us. These covenants are subject to a number of important limitations and exceptions, including certain provisions permitting us, subject to the satisfaction of certain conditions, to transfer assets to certain of our unrestricted subsidiaries. Moreover, if the 7.50% Senior Secured Notes receive an investment grade rating from at least two rating agencies and no default has occurred and is continuing under the 7.50% Senior Secured Notes Indenture, many of the restrictive covenants in the 7.50% Senior Secured Notes Indenture will be terminated. The 7.50% Senior Secured Notes Indenture also contains customary events of default and acceleration provisions relating to events of default, which provide that upon an event of default under the 7.50% Senior Secured Notes Indenture, the Trustee or the holders of at least 25% in aggregate principal amount of the then outstanding 7.50% Senior Secured Notes may declare all of the 7.50% Senior Secured Notes to be due and payable immediately. We are in compliance with all covenants of the 7.50% Senior Secured Notes Indenture as of December 31, 2019.
We may from time to time seek to retire or purchase certain amounts of our outstanding 7.25% Senior Notes and 7.50% Senior Secured Notes through cash purchases, in open market purchases, privately negotiated transactions or otherwise. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.
Other Financing
In February 2019, we entered into an arrangement with TETRA under which a subsidiary of TETRA entered into an agreement with one of our subsidiaries for the purchase up to $15.0 million of compressor services equipment and to subsequently lease the equipment back to us in exchange for a monthly rental fee. As of December 31, 2019, pursuant to this arrangement, $14.8 million has been funded by TETRA for the construction of new compressor services equipment. As of December 31, 2019, all compression units were completed and deployed under this agreement.
Off Balance Sheet Arrangements
As ofDecember 31, 2019, we had no “off balance sheet arrangements” that may have a current or future material effect on our consolidated financial condition or results of operations.
Recently Adopted Accounting Guidance
We adopted the new lease accounting standard on January 1, 2019. The new lease standard had a material impact to our consolidated financial statements, resulting from the inclusion of operating lease right-of-use assets and operating lease liabilities in our consolidated balance sheet. Refer to Part I, Item 1. Financial Statements- Note 2 - "Summary of Significant Accounting Policies" and Note 5 - “Leases” for further discussion.
Commitments and Contingencies
From time to time, we are involved in litigation relating to claims arising out of our operations in the normal course of business. While the outcome of these lawsuits or other proceedings against us cannot be predicted with certainty, management does not consider it reasonably possible that a loss resulting from such lawsuits or proceedings in excess of any amounts accrued has been incurred that is expected to have a material adverse effect on our financial condition, results of operations or cash flows.
Contractual Obligations
Our contractual obligations and commitments principally include obligations associated with our outstanding indebtedness and obligations under operating leases.
The table below summarizes our contractual cash obligations as of December 31, 2019:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Payments Due |
| | Total | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 | | Thereafter |
| | (In Thousands) |
| Long-term debt | $ | 649,430 |
| | $ | — |
| | $ | — |
| | $ | 295,930 |
| | $ | 3,500 |
| | $ | — |
| | $ | 350,000 |
|
| Interest on debt | 197,628 |
| | 47,795 |
| | 47,795 |
| | 40,683 |
| | 26,355 |
| | 26,250 |
| | 8,750 |
|
| Operating leases | 24,787 |
| | 7,840 |
| | 5,791 |
| | 3,684 |
| | 1,934 |
| | 1,934 |
| | 3,604 |
|
| Affiliate financing obligation | 14,372 |
| | 3,015 |
| | 3,015 |
| | 3,015 |
| | 3,015 |
| | 2,312 |
| | — |
|
| Total contractual cash obligations | $ | 886,217 |
| | $ | 58,650 |
| | $ | 56,601 |
| | $ | 343,312 |
| | $ | 34,804 |
| | $ | 30,496 |
| | $ | 362,354 |
|
Recently Issued Accounting Pronouncements
For a discussion of new accounting pronouncements that may affect our consolidated financial statements, see "NoteNote 2 - Summary“Summary of Significant Accounting Policies, New Accounting Pronouncements,"” in the Notes to Consolidated Financial Statements in this Annual Report.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk.
Not Applicable.applicable.
Item 8. Financial Statements and Supplementary Data.
Our financial statements and supplementary data for us and our subsidiaries required to be included in this Item 8 are set forth in Item 15 of this Annual Report.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures
Under the supervision and with the participation of our management, including the Principal Executive Officer and Principal Financial Officer of our general partner, we conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act) as of the end of the period covered by this Annual Report. Based on this evaluation, the Principal Executive Officer and Principal Financial Officer of our general partner concluded that our disclosure controls and procedures were effective as of December 31, 2019.2021.
Management’s Report on Internal Control over Financial Reporting
Management of our general partner is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Our Internalinternal control over financial reporting is a process to provide reasonable assurance regarding the reliability of our financial reporting for external purposes in accordance with accounting principles generally accepted in the United States of America.
Our internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that our receipts and
expenditures are being made only in accordance with authorizations of our management and directors; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. In addition, 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.
Under the supervision and with the participation of management of our general partner, including the Principal Executive Officer and Principal Financial Officer of our general partner, an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2019,2021 was conducted based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) ("COSO"(“COSO”). Based on this assessment, management of our general partner has determined that our internal control over financial reporting was effective as of December 31, 2019.2021.
Ernst & Young LLP, our independent registered public accounting firm, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2019. Ernst & Young LLP's report on our internal control over financial reporting is included herein.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the fourth quarter of the fiscal year ended December 31, 2019,2021, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors of CSI Compressco GP Inc.
and the Unitholders of CSI Compressco LP
Opinion on Internal Control over Financial Reporting
We have audited CSI Compressco LP’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 Framework) (the COSO criteria). In our opinion, CSI Compressco LP (the Partnership) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the 2019 consolidated financial statements of the Partnership and our report dated March 16, 2020, expressed an unqualified opinion thereon.
Basis for Opinion
The Partnership's management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying “Management’s Report on Internal Control Over Financial Reporting.” Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ ERNST & YOUNG LLP
Houston, Texas
March 16, 2020
Item 9B. Other Information.
None.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.
Not Applicable.
PART III
Item 10. Directors, Executive Officers, and Corporate Governance.
Corporate Governance and Director Independence
Our general partner CSI Compressco GP Inc., is an indirect, wholly owned subsidiary of TETRA Technologies, Inc. (“TETRA”)Spartan and has sole responsibility for conducting our business and managing our operations. The members of our general partner’s board of directors (our “Board”) oversee our operations. Unitholders are not entitled to elect the members of our Board or directly or indirectly participate in our management or operation. All of the members of our Board are appointed by Compressco Field Services, L.L.C., an indirect,Spartan Energy Holdco LLC, a direct, wholly owned subsidiary of TETRA.Spartan. We do not hold annual unitholder meetings. References in this Part III to the “Board,” “directors,” "executive“executive officers,"” or “officers” refer to the Board, directors, executive officers, and officers of our general partner, unless otherwise indicated.
Our Board has adopted Corporate Governance Guidelines that outline important policies and practices regarding our governance and provide a framework for the functioning of the Board and its committees. The Corporate Governance Guidelines and the charterscharter of the Audit Committee and Conflicts Committee are available in the Corporate Governance section of the Investor Relations area of our website at www.csicompressco.com. In addition, our Board and our general partner have adopted a Code of Business Conduct and a Financial Code of Ethics, copies of which are also available in the Corporate Governance section of the Investor Relations area of our website at www.csicompressco.com. We will post on our website all waivers to or amendments of our Code of Business Conduct and Financial Code of Ethics that are required to be disclosed by applicable law or the listing requirements of the NASDAQ. We will provide to our unitholders, without charge, printed copies of the foregoing materials upon written request to Investor Relations, CSI Compressco LP, 24955 Interstate 45 North,1735 Hughes Landing Boulevard, Suite 200, The Woodlands, Texas, 77380.
The NASDAQ does not require a listed limited partnership like us to have a majority of independent directors on the Board or to establish a compensation committee or a nominating committee. Our Board currently consists of sixseven directors, fourthree of whom, Paul D. Coombs, D. Frank Harrison,Denise G. Essenberg, Stephen R. Gill and James R. Larson, and William D. Sullivan, are independent as defined under the listing standards of the NASDAQ.
| | | | | | | | | | | | | | |
| Name | | Age | | Position with CSI Compressco GP |
| Derek J. Anchondo | | 48 | | Assistant General Counsel |
| Jonathan W. Byers | | 43 | | Chief Financial Officer, Director |
| Denise G. Essenberg | | 63 | | Independent Director |
| Ted A. Gardner | | 64 | | Director, Chairman of the Board of Directors |
| Stephen R. Gill | | 64 | | Independent Director |
| John E. Jackson | | 63 | | Chief Executive Officer, Director |
| | | | |
| James R. Larson | | 72 | | Independent Director |
| Michael E. Moscoso | | 56 | | Vice President of Finance |
| Matthew B. Pitcock | | 39 | | Vice President North America Sales, Compression Services |
| Robert W. Price | | 54 | | Chief Operating Officer, Director |
| Rodney P. Pruski | | 49 | | Vice President of Operations |
Directors and Executive Officers
Our directors hold office until the earlier of their death, resignation, removal, or until their successors have been appointed. Our executive officers are appointed by and serve at the discretion of our Board. There are no family relationships among any of our directors or executive officers. The following table shows information regarding our current directors and executive officers. Directors are appointed for one-year terms.
|
| | | | |
Name | | Age | | Position with CSI Compressco GP |
Paul D. Coombs | | 64 | | Independent Director |
D. Frank Harrison | | 72 | | Independent Director |
James R. Larson | | 70 | | Independent Director |
Brady M. Murphy | | 60 | | President, Chairman of the Board of Directors |
William D. Sullivan | | 63 | | Independent Director |
Elijio V. Serrano | | 62 | | Chief Financial Officer, Director |
Ronald J. Foster | | 63 | | Senior Vice President and Chief Marketing Officer |
Miguel Luna | | 49 | | Vice President of Engineered Products Sales & International Operations |
Roy McNiven | | 40 | | Senior Vice President of Operations and Manufacturing |
Michael E. Moscoso | | 54 | | Vice President - Finance |
Matthew B. Pitcock | | 38 | | Vice President North America Sales, Compression Services |
|
| | | | |
Name | | Age | | Position with CSI Compressco GP |
Bass C. Wallace, Jr. | | 61 | | General Counsel |
Jacek M. Mucha | | 41 | | Treasurer |
Elisabeth K. Evans | | 57 | | Vice President-Human Resources of TETRA Technologies, Inc. |
Timothy C. Moeller | | 56 | | Vice President and Chief Procurement Officer of TETRA Technologies, Inc. |
Biographical summaries of the directors and executive officers, including the experiences, qualifications, attributes, and skills of each director that have been considered by the Board in determining that these individuals should serve as directors, are set forth below. See “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters - Beneficial Ownership of Certain Unitholders and Management” included under Item 12 of this Annual Report for information regarding the number of common units owned by each individual.
Paul D. CoombsDerek J. Anchondo has served as Assistant General Counsel of our general partner since August 2021. Prior to his current role, he was a Partner with large domestic and international law firms from 2011 to 2021. Prior to that, Mr. Anchondo held the role of Chief Counsel and Division Counsel with Pride International from 2006 to 2011 and held the role of Counsel – U.S. Operations with Hanover Compressor Company from 2003 to 2006. He began his career as an attorney in 1999 with large domestic and international law firms. Mr. Anchondo received his B.A from Trinity University and his J.D. from the University of Houston Law Center. He is admitted to practice in the State of Texas and the State of New York.
Jonathan W. Byers has served as the Chief Financial Officer of our general partner and as a member of its Board since January 2021 and as Head of Corporate Development and Secretary of Spartan since 2010. Prior to joining Spartan, Mr. Byers served as Vice President, Corporate Development for Price Gregory Services (“Price Gregory”), a leading energy infrastructure services provider specializing in pipeline construction. Prior to joining Price Gregory, Mr. Byers held positions at SCF Partners (an energy focused investment firm) and General Atlantic (a global, growth focused private equity firm). Prior to General Atlantic, Mr. Byers was employed with Goldman Sachs Group in the Investment Banking Division. Mr. Byers holds a B.S. in Business Administration from Georgetown University and an MBA from Harvard Business School.
Denise G. Essenberg has served as an independent director of our general partner'spartner’s Board since May 6, 2014. Mr. CoombsFebruary 2021. Ms. Essenberg is a retired Partner with PwC, retiring in June 2019 after 40 years serving numerous insurance clients across the property/casualty, life and health payor sectors of the insurance industry and advising on acquisitions, pre- and post-transaction integration issues, business divestitures and the adoption of new technologies. Ms. Essenberg served as the managing partner of the PwC Grand Rapids and Hartford offices from 2003 to 2008 and 2008 to 2011, respectively, with oversight and responsibility for client service, office operations and resource management and was the audit transformation leader of PwC’s insurance practice from 2014 to 2019. Ms. Essenberg has served as a member of TETRA’son the board of directors since June 1994, and as a member of its nominating and corporate governance committee since July 2012, and as a member of its audit and compliance committee and finance committee of Health Alliance Plan of Michigan since May 2015. From April 2005 until his retirement in June 2007, Mr. Coombs servedJanuary 2021 and as TETRA’s executive vice president of strategic initiatives, and from May 2001 to April 2005, as TETRA’s executive vice president and chief operating officer. From January 1994 to May 2001, Mr. Coombs served as TETRA’s executive vice president - oil & gas, from 1987 to 1994 he served as senior vice president - oil & gas, and from 1985 to 1987, as general manager - oil & gas. Mr. Coombs has served in numerous other positions with TETRA since 1982. Mr. Coombs is presently a director and serves on the audit and corporate governance committeesmember of the board of directors and audit committee chairperson of Balchem Corporation, a public company that is subjectAtain Insurance Company and Atain Specialty Insurance Company since June 2020. In December 2021, Ms. Essenberg was elected to the reporting requirementsboard of directors and was appointed audit committee chairperson of Frankenmuth Mutual Insurance Company. Ms. Essenberg received her BA from Michigan State University and attended the Exchange Act.Kellogg School of Management Women’s Director Development Program at Northwestern University in 2015.
Mr. Coombs Ted A. Gardner has more than 30 yearsserved as a director and as Non-Executive Chairman of experience with TETRA, which, together with his entrepreneurial approach to management, provides our general partner’s Board with insight into our capabilitiessince January 2021. Mr. Gardner is a co-founder and personnel.Managing Partner of Silverhawk Capital Partners. Mr. Coombs has substantial experience withGardner is currently a director of Incline Energy Partners, L.P., Kinder Morgan, Inc. (NYSE: KMI), Meridian Chemicals and Spartan. He was previously a director of Kinder Morgan Energy Partners, Athlon Energy, Summit Materials Inc. and Encore Acquisition Company. Ted earned a B.A. degree in Economics from Duke University and both a J.D. and an MBA from the services we provide and with oil and gas exploration and production operations in general.
D. Frank Harrison
Stephen R. Gill has served as an independent director of our general partner'spartner’s Board and as Chairman of its Conflicts Committee and a member of its Audit Committee since April 2012. Since June 2011,January 2021. Mr. Harrison is an owner and the managing partner of Eufaula Energy, LLC, a privately held company that invests in oil and gas interests. Mr. HarrisonGill has served as chairmanthe Chief Executive Officer of Lindsayca Solutions, an EPC firm specializing in production and processing facilities, since December 2018. From March 2017 to December 2018, Mr. Gill was retired. From January 2014 to January 2017, Mr. Gill was the boardChief Executive Officer of directors (since 2007)Valerus, a global provider of compression, production, and processing equipment and turnkey facilities. Prior to Valerus, Mr.
Gill served in various senior positions at Exterran and Hanover, including Vice President – International and at Ingersoll Rand & Dresser Rand. Mr. Gill holds a BS degree in Mechanical Engineering from Texas A&M University.
John E. Jackson has served as the Chief Executive Officer of our general partner and as chief executive officera member of its Board since January 2021 and a director (since 2005)as President and Chief Executive Officer of Bronco Drilling Company, Inc. ("Bronco") untilSpartan since 2010. Prior to joining Spartan, Mr. Jackson was the acquisitionChairman and CEO of Bronco by Chesapeake Energy CorporationPrice Gregory. Prior to serving in June 2011. Bronco was a publicly traded company that provided contract drilling and well services. From 2002 to 2005,his roles at Price Gregory, Mr. HarrisonJackson served as an agent for the purchasePresident and Chief Executive Officer of oilHanover Compressor. Prior to that, he held several positions at Duke Energy Field Services, including Chief Financial Officer, and gas properties for entities controlled by Wexford Capital LLC. From 1999 to 2002,Union Pacific Resources. Mr. HarrisonJackson has served as president of Harding and Shelton, Inc., a privately held oil and natural gas exploration, drilling and development firm. Mr. Harrison currently serves on the board of directors of the Oklahoma Independent Petroleum Association.Basic Energy Services, Inc. (NYSE: BAS) since December 2016 and Main Street Capital Corporation (NYSE: MAIN) since May 2014. He received his B.S. degreewas previously a director of CNX Midstream Partners. Mr. Jackson holds a B.B.A. in SociologyAccounting from Oklahoma StateBaylor University.
Mr. Harrison has significant management experience in the exploration and production of oil and gas in the U.S. Mr. Harrison also has substantial experience in serving on the board of a publicly held corporation operating in the oil and gas industry, which provides cross board experience and perspective.
James R. Larson has served as an independent director of our general partner'spartner’s Board and as Chairman of its Audit Committee since July 2011 and as a member of its Conflicts Committee since April 2012. Since January 1, 2006, Mr. Larson has been retired. From September 2005 until January 1, 2006, Mr. Larson served as senior vice president of Anadarko Petroleum Corporation ("Anadarko"(“Anadarko”). From December 2003 to September 2005, Mr. Larson served as senior vice president, finance and chief financial officer of Anadarko. From 2002 to 2003, Mr. Larson served as senior vice president, finance of Anadarko where he oversaw treasury, investor relations, internal audits and acquisitions and divestitures. From 1995 to 2002, Mr. Larson served as vice president and controller of Anadarko where he was responsible for accounting, financial reporting, budgeting, forecasting, and tax. Prior to that, he held various tax and financial positions within Anadarko after joining the company in 1981. Mr. Larson currently serves as a director, chairman of the audit committee and a member of the governance committee of Magnolia Oil & Gas Corporation, a publicly traded company that is subject to the reporting requirements of the
Exchange Act. From September 2006 until June 2018, Mr. Larson served as a director of EV Management, LLC, the general partner of EV Energy GP, which was the general partner of EV Energy Partners, L.P. a publicly-traded limited partnership. Mr. Larson is a current member of the American Institute of Certified Public Accountants, Financial Executives International, the Tax Executives Institute and the National Association of Corporate Directors. He received his BBA degree in business from the University of Iowa.
Mr. Larson has significant management experience in the exploration and production of oil and gas on an international as well as domestic level. Mr. Larson also has substantial experience in corporate finance and financial reporting matters and in serving on the board of a publicly traded limited partnership operating in the oil and gas industry.
Brady
M. Murphy has served as President and chairman of the Board of our general partner since May 2019 and as a member of its Board since February 22, 2018. Mr. Murphy has also served as the President and Chief Executive Officer of TETRA since May 2019, as a member of its board of directors since December 2018, and as TETRA's President and Chief Operating Officer from February 2018 until his promotion to Chief Executive Officer. Prior to his employment with TETRA, Mr. Murphy served as chief executive officer of Paradigm Group B.V., a private company focused on strategic technologies for the upstream energy industry, from January 2016 until February 2018. Mr. Murphy previously served at Halliburton Company and its affiliated companies for 26 years, holding numerous international and North America positions, most recently as senior vice president - global business development and marketing from 2012 to December 2015, as senior vice president - business development Eastern Hemisphere from 2011 to 2012, as senior vice president - Europe/Sub -Saharan Africa region from 2009 to 2011, and as vice president of Sperry Drilling Services from 2004 to 2008. Mr. Murphy received his B.S. degree in Chemical Engineering from Pennsylvania State University and is a graduate of the Harvard Business School’s Advanced Management Program.
Mr. Murphy has more than 35 years of global operations, engineering, manufacturing and business development experience in a variety of areas within the energy industry, including deepwater, mature fields and unconventional assets.
William D. Sullivan is an independent director of our general partner's Board and has served as a member of its Audit Committee since July 2011. Mr. Sullivan has served as a member of TETRA’s board of directors since August 2007 and as non-executive chairman of its board since May 2015. Mr. Sullivan is the non-executive chairman of the board of directors of SM Energy Company, a publicly traded company subject to the reporting requirements of the Exchange Act. From 1981 through August 2003, Mr. Sullivan was employed in various capacities by Anadarko, most recently as executive vice president, exploration and production. Mr. Sullivan has been retired since August 2003. Mr. Sullivan received his B.S. degree in Mechanical Engineering from Texas A&M University. From 2007 to May 2015, Mr. Sullivan served as a director and as a member of the conflicts and audit committees of Targa Resources Partners GP, LLC, the general partner of Targa Resources Partners LP, and from March 2006 to September 2018, Mr. Sullivan served as a director and as a member of the audit, nominating and corporate governance and conflicts, and compensation committees of Legacy Reserves GP, LLC, the general partner of Legacy Reserves, LP, both of which are publicly traded limited partnerships. Mr. Sullivan received his B.S. degree in Mechanical Engineering from Texas A&M University.
Mr. Sullivan has significant management experience in midstream oil and gas operations and in the exploration and production of oil and gas on an international and domestic level. Mr. Sullivan also has substantial experience in executive compensation matters and in serving on the boards of publicly held corporations and publicly traded limited partnerships operating in the oil and gas industry, which provides cross board experience and perspective.
Elijio V. Serrano has served as Chief Financial Officer of our general partner since March 2017 and as a member of its Board since May 2019. He has also served as TETRA’s senior vice president and chief financial officer since August 2012. Mr. Serrano served as chief financial officer of UniversalPegasus International from October 2009 through July 2012. Following his resignation from Paradigm BV in February 2009 and until his acceptance of the position with UniversalPegasus International in October 2009, Mr. Serrano was retired. From February 2006 through February 2009, Mr. Serrano served as chief financial officer and executive vice president of Paradigm BV (formerly, Paradigm Geophysical Ltd.). From October 1999 through February 2006, Mr. Serrano served as chief financial officer of EGL, Inc., a publicly-traded company subject to the reporting requirements of the Securities Exchange Act of 1934. From 1982 through October 1999, Mr. Serrano was employed in various capacities with increasing responsibilities by Schlumberger Ltd.. Mr. Serrano served as a director, chairman of the
audit committee, and as a member of the corporate governance and nominating committee of Tesco Corporation, a public company subject to the reporting requirements of the Exchange Act, until its acquisition by Nabors Industries Ltd. in December 2017. Mr. Serrano received his B.B.A. degree in Accounting and Finance from the University of Texas at El Paso. Mr. Serrano was a certified public accountant in the State of Texas from 1986 until March 2002, at which time his license became inactive.
Ronald J. Foster has served as Senior Vice President and Chief Marketing Officer of our general partner since the closing of the CSI acquisition in August 2014. From October 2008 through September 2015, Mr. Foster also served as a director of our general partner and Compressco, Inc. Prior to the CSI acquisition, Mr. Foster served as President of CSI Compressco GP Inc. from October 2008 until July 2014, and as President and a director of our Compressco, Inc. subsidiary from October 2008 until October 2012. From August 2002 to September 2008, Mr. Foster served as Senior Vice President of Sales and Marketing with Compressco, Inc. Mr. Foster has over 30 years of energy-related work experience that also includes positions with Wood Group, Halliburton and Dresser. He is an active member of several regional industry trade organizations, including the American Petroleum Institute (API), the Society of Petroleum Engineers (SPE) and the Oklahoma Independent Petroleum Association (OIPA). Mr. Foster received his B.S. degree in Economics from Oklahoma State University.
Miguel Luna has served as Vice President of Engineered Products Sales & International Operations of our general partner since May 2017. From August 2014 through May 2017, he served as Director of Engineered Products Sales & International Operations of our general partner. Mr. Luna served as general manager of engineered products sales & international operations of Compressor Systems, Inc. from October 2010 through August 2014. From December 2004 to February 2009, Mr. Luna served as senior manager of Latin America for Exterran. Mr. Luna began his career at Schlumberger in 1999, as a marketing manager and held various leadership roles with increasing responsibility. Mr. Luna holds a Bachelor of Science degree in Natural Gas Engineering from Texas A&M University.
Roy E. McNiven has served as Senior Vice President of Operations and Manufacturing of our general partner since December 2019 and as Vice President of Operations from October 2018 until December 2019. Mr. McNiven most recently served as Vice President of Rental Operations at Nabors Industries ("Nabors") from December 2017 until joining CSI Compressco. Prior to this role, he served for 13 years at Tesco Corporation in various management levels roles, including Vice President of Product Supply and Commercialization from March 2017 to December 2017, Vice President of Products and Services from May 2016 to March 2017, Vice President of Aftermarket Sales & Service, Rentals and Global Supply Chain from November 2014 to May 2016, and Global Director, Aftermarket Sales & Service and Rentals from June 2010 to November 2014, before Tesco was acquired by Nabors. Mr. McNiven earned a Bachelor of Business Administration degree, as well as an Executive MBA, from Athabasca University in Canada.
Michael E. Moscoso, has served as our Vice President -of Finance since January 2018. He served as Director of Internal Audit of TETRA from July 2014 until January 2018. From July 2005 until April 2014, Mr. Moscoso served in various internal audit roles with increasing responsibility, most recently as the senior director - internal audit, at AEI Services, LLC, a private company which owned and operated interests in multiple power generation assets, as well as natural gas transportation and distribution businesses in Central and South America, the Caribbean, and other international locations. From April 2014 until July 2014, Mr. Moscoso was self-employed. Mr. Moscoso’s prior experience includes serving as the director of settlements and, prior to that, as manager of risk reporting and controls of Enron Corporation, the assistant treasurer of Zilkha Energy Company, and as controller - Latin America division of Weatherford International. Mr. Moscoso began his career in 1989 with KPMG, where his responsibilities primarily included managing and executing audits of exploration and production companies and pipeline companies. Mr. Moscoso received his B.B.A. degree in accounting from the University of Houston, is a certified public accountant in the State of Texas, and a certified internal auditor.
Matthew B. Pitcock has served as Vice President North America Sales, Compression Services of our general partner since January 2020 and as Regional Sales Manager for the Permian Basin from March 2014 to January 2020. Mr. Pitcock returned to work for our general partner in 2014 after serving for two years as a Category Management Advisor (Compression) at Devon Energy. In 2006, Mr. Pitcock joined the Account Manager Training Program of Compressor Systems Inc., which was acquired by the partnership in 2014. He continued to serve in several sales leadership roles with increasing responsibilities for Compressor Systems through 2012. Mr. Pitcock received his B.B.A. in Management from Angelo State University in 2004 and his M.B.A from Oklahoma Christian University in 2012.
Bass C. Wallace, Jr.Robert W. Price has served as the General CounselChief Operating Officer of our general partner and as a member of its Board since January 2021 and as Chief Operating Officer of Spartan since 2010. Prior to joining Spartan, Mr. Price held senior management positions with Exterran Corporation (NYSE: EXTN), Hanover Compressor Company and Ariel Compressor Corporation. Mr. Price has spent most of his career developing and executing gas treating and processing applications in the U.S. and Latin America. Mr. Price holds a B.S. in Mechanical Engineering from The University of Notre Dame and an MBA from Carnegie Mellon.
Rodney P. Pruski has served as Vice President of Operations of our general partner since October 2008.January 2022, responsible for North American Compression Services, Aftermarket Operations and Supply Chain. Rodney joined Compressor Systems, Inc. in November 1998, which was acquired by the partnership in 2014. He has also served in numerous roles as TETRA’s General Counsel since 1994Controller (1999-2006), Operational Support (2006-2012), Regional Manager for South Texas (2012-2020), and as Director of Operations (2020-2022). Mr. Pruski earned a Senior Vice President since May 2011. From 1984 to 1994 he was engaged in the private practice of law. Mr. Wallace received his B.A. degree in Economics from the University of Virginia and his J.D. degree from the University of Texas School of Law.
Jacek M. Mucha has served as the Treasurer of our general partner since September 2019. He has also served as TETRA’s Vice President - Finance, Treasurer and Assistant Secretary since September 2019 and as TETRA’s senior director of financial planning and analysis from February 2018 until September 2019. From March 2014 to February 2018, Mr. Mucha served in various financial roles at Tesco Corporation, including Vice President - Finance and Director, Corporate Development, Investor Relations and Financial Planning and Analysis. From May 2011 to March 2014, Mr. Mucha served in various financial roles with increasing responsibility at Lufkin Industries, Inc. From 2001 until May 2011, he held various financial roles at several investment banking and consulting firms. Mr. Mucha received his B.A. degree in Economics from Washington and Lee University, and his MasterBachelor of Business Administration degree in Accounting and Computer Information Systems from the University of Texas at Austin, McCombs School of Business.
Elisabeth K. Evans has served as the Vice President - Human Resources of TETRA Technologies, Inc. since January 2013 and provides similar services to the Partnership. Prior to joining TETRA, Ms. Evans served as senior vice president of human resources and corporate communications of Boardwalk Pipeline Partners, LP from February 2009 through September 2012. Following her departure from Boardwalk Pipeline Partners, LP and until her acceptance of the position with TETRA in January 2013, Ms. Evans was engaged in independent consulting on human resources issues. Earlier in her career, she served as vice president of human resources and administrative services for AGL Resources Inc., global human resources director for Accenture, Ltd., and in various human resources positions at ARAMARK Corporation and BP p.l.c. Ms. Evans received her B.A. and M.A. degrees in Economics from IndianaState University.
Tim Moeller has served as the Vice President and Chief Procurement Officer of TETRA Technologies, Inc. since April 2018 and provides similar services to the Partnership. Prior to joining TETRA, from September 2012 until March 2018, Mr. Moeller served as Chief Operating Officer of Melior Innovations and Chief Executive Officer of TessaFrac. From May 2006 until February 2012, Mr. Moeller held numerous Supply Chain management positions with increasing responsibility at Halliburton. Earlier in his career, Mr. Moeller held several supply chain management positions with Tyco International and YPF/Maxus Corporation. Mr. Moeller received a bachelor’s degree in business administration from Texas A&M University.
Board Meetings and Committees
During 2019,2021, the Board held elevenseven meetings. The standing committees of the Board during 20192021 consisted of an Audit Committee and a Conflicts Committee. During 2019,2021, the Audit Committee held four meetings, and the Conflicts Committee held ninefourteen meetings.
Audit Committee. TheDuring 2021, the Audit Committee is currentlywas composed of Mr. Larson, as Chairman, Mr. Gill and Messrs. Harrison and Sullivan.Ms. Essenberg. The purposes of the Audit Committee are to (i) oversee the financial and reporting processes of the Partnership and the general partner, and the audit of the Partnership’s financial statements, (ii) assist the Board in fulfilling its oversight responsibilities with regard to the integrity of the Partnership’s financial statements, the Partnership’s and the general partners’ compliance with legal and regulatory requirements, the qualifications, independence and performance of the Partnership’s independent registered public accounting firm, and the effectiveness and performance of the Partnership’s and the general partner’s internal audit function, and (iii) perform such other functions as the Board may assign from time to time. The Audit Committee has sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and terms, and approve any non-audit service to be performed by our independent registered public accounting firm. To promote the independence of its audit, the Audit Committee consults separately and jointly with the independent registered public accounting firm, our internal auditor, and management.
As required by NASDAQ and SEC rules regarding audit committees, the Board has reviewed the qualifications of the Audit Committee and has determined that no current committee member has a relationship with us that might interfere with the exercise of his independence from us or our affiliates. Included within such determination, the Board has determined that Messrs. Larson Harrison, and SullivanGill and Ms. Essenberg are independent as defined in Section 10A of the Exchange Act and the listing standards of the NASDAQ. In addition, the Board has determined
that Mr. Larson, the Chairman of the Audit Committee, is an audit committee financial expert within the definition established by the SEC.
Conflicts Committee. TheMembership of the Conflicts Committee, which was formed in April 2012, is currentlywas composed of Mr. Harrison, as Chairman,Messrs. Larson and Mr. Larson.Gill and Ms. Essenberg during 2021. It is anticipated that committee membership will be established on an ad hoc basis going forward. The purposes of the Conflicts Committee are to (i) as requested by the Board, review and evaluate any potential conflicts of interest between us and the owner of our general partner or its affiliates or us and TETRASpartan or its subsidiaries or affiliates, and (ii) carry out any other duties assigned by the Board that relate to potential conflicts of interest between us and the owner of our general partner or its affiliates or us and TETRASpartan or its subsidiaries or affiliates. The Conflicts Committee has the sole authority to retain and terminate any consultants, attorneys, independent accountants or other service providers to assist it in the evaluation of conflicts matters, including the sole authority to approve their fees and other terms of retention.
As required by the SecondThird Amended and Restated Agreement of Limited Partnership Agreement of the Partnership, the Board has reviewed the independence of Messrs. Harrison and Larson and hasGill and Ms. Essenberg and determined that each of them meets the independence standards established thereunder as required for service on the Conflicts Committee. Included within such determination, the Board has also determined that each of Messrs. HarrisonLarson and Larson isGill and Ms. Essenberg was independent as defined in Section 10A of the Exchange Act and the listing standards of the NASDAQ.
Delinquent Section 16(a) Reports
Section 16(a) of the Exchange Act requires our directors, executive officers, and persons who own more than 10% of our common units to file initial reports of ownership and reports of changes in ownership of common units (Forms 3, 4 and 5) with the SEC and the NASDAQ. Executive officers, directors, and greater than 10% holders are required by SEC regulations to furnish us with copies of all such forms they file.
To our knowledge, and based solely on our review of the copies of such reports and written representations provided to us by certain reporting persons that no reports on Form 5 were required, we believe that during the fiscal year ended December 31, 2019, all Section 16(a) filing requirements applicable to our executive officers, directors, and 10% holders were complied with in a timely manner, with the exception of one late Form 4 reporting the conversion of Series A Preferred Units by TETRA Technologies, Inc. (1 transaction) that was filed one day late on February 13, 2019.
Item 11. Executive Compensation.
Compensation of Named Executive Officers
Introductory Note
Our Named Executive Officers (defined below) divide their business time between us and Spartan. TETRA and our general partner entered into a Co-Employer Agreement in connection with the GP Sale in order to ensure that certain employees received continued coverage through existing TETRA plans for certain employee benefits
and administrative services for a transition period, although our general partner continued to maintain the CSI Compressco LP Second Amended and Restated 2011 Long Term Incentive Plan (the “LTIP”) following the GP Sale.
Beginning in February 2021, we reimbursed our general partner under the terms of our partnership agreement for any expenses and expenditures incurred or payments made on our behalf, including operating expenses related to our operations and for the provision of various general and administrative services for our benefit.
Pursuant to the Management Services Agreement dated November 10, 2021, the general partner, Spartan Operating and Spartan GP will provide certain services reasonably necessary for the operation of the businesses of the Partnership and its subsidiaries, Spartan, Spartan GP and Spartan Treating, including certain corporate and general and administrative services. The general partner and Spartan GP will allocate any costs and expenses incurred on a reasonable basis, and the parties will reimburse such other parties for costs and expenses allocated to them.
Summary Compensation
The following table sets forth the aggregate compensation earned by (i) each individual serving as our President (“Principalor Chief Executive Officer (our “Principal Executive Officer”),and (ii) our former President , who served in such position until May 17, 2019, and (iii) each of our two other most highly compensated executive officers (each a “Named Executive Officer” or “NEO”) for the fiscal year ended December 31, 2019.2021 (and solely with respect to Mr. Murphy, the fiscal year ended December 31, 2020).
Summary Compensation Table
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| Name and Principal Position | Year | | Salary(1) | | Bonus | | Unit Awards(2) | | Non-Equity
Incentive Plan Compensation | | All Other Compensation(3) | | Total(5) |
| | | | ($) | | ($) | | ($) | | ($) | | ($) | | ($) |
Brady Murphy(4) | 2021 | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Former President, Chief Executive Officer, Director | 2020 | | $ | — | | | $ | — | | | $ | 523,837 | | | $ | — | | | $ | — | | | $ | 523,837 | |
| | | | | | | | | | | | | |
| John E. Jackson | 2021 | | $ | 439,167 | | | $ | — | | | $ | 900,000 | | | $ | 489,167 | | | $ | 10,700 | | | $ | 1,839,034 | |
| Chief Executive Officer, Director | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Jonathan W. Byers | 2021 | | $ | 355,833 | | | $ | — | | | $ | 900,000 | | | $ | 234,167 | | | $ | 10,700 | | | $ | 1,500,700 | |
| Chief Financial Officer, Director | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Robert W. Price | 2021 | | $ | 355,833 | | | $ | — | | | $ | 900,000 | | | $ | 234,167 | | | $ | 10,700 | | | $ | 1,500,700 | |
| Chief Operations Officer | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
(1) Compensation shown for Mr. Murphy is discussed in footnote 4 below. Compensation for Messrs. Jackson, Byers and Price reflects compensation from the date of the GP Sale to fiscal year end (January 29, 2021 to December 31, 2021).
(2) The amounts included in the “Unit Awards” column reflect the aggregate grant date fair value of awards granted during the fiscal year ended December 31, 2021 or December 31, 2020, as applicable, in accordance with FASB ASC Topic 718. Phantom unit awards granted under the LTIP on February 19, 2021 relate to our common units and were valued at $1.96 per common unit in accordance with FASB ASC Topic 718. See Note 12 to our consolidated financial statements for the year ended December 31, 2021 for a discussion of other assumptions used in determining the grant date value of these awards.
(3) The amounts reflected represent matching contributions under the Spartan 401(k) Retirement Plan.
(4) Other than the 2020 award of phantom units included in the “Unit Awards” column, the compensation of Mr. Murphy, the President and CEO of TETRA and former CEO of CSI Compressco, was determined by TETRA. No compensation has been reported for Mr. Murphy because none of his compensation was specifically allocated to us or payable by us under our previous Omnibus Agreement during 2020 or 2021, and he did not receive a phantom unit award during the 2021 year. Mr. Murphy resigned as both an officer and director of CSI Compressco effective January 29, 2021.
(5) As noted above, the formula that determines the compensation costs allocated to us pursuant to the Management Services Agreement does not divide the costs between specific compensation elements, therefore out of an abundance of caution we have chosen to report the total compensation provided to each of the applicable Named Executive Officers for the 2021 year within this column. However, pursuant to the Management Services Agreement, we only reimbursed Spartan for the following amounts in 2021: Mr. Jackson, $0.4 million; Mr. Byers, $0.4 million; and Mr. Price, $0.3 million.
Salary and Bonus Compensation
The base salary for Messrs. Jackson, Byers and Price was determined at the time of the GP Sale by our Board. During the 2021 year, none of Messrs. Jackson, Byers and Price was a party to an employment agreement or other individual service agreement.None of our NEOs participated in a cash bonus or incentive compensation program with respect to the 2021 year.
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| Name and Principal Position | Year | | Salary | | Bonus | | Unit Awards(1) | | Non-Equity
Incentive Plan Compensation(2) | | All Other Compensation(3) | | Total |
| | | | ($) | | ($) | | ($) | | ($) | | ($) | | ($) |
| Brady M. Murphy | 2019 | | (4 | ) | | (4 | ) | | $ | — |
| | (4 | ) | | (4 | ) | | $ | — |
|
| President | 2018 | | (4 | ) | | (4 | ) | | — |
| | (4 | ) | | (4 | ) | | — |
|
| | | | | | | | | | | | | | |
Roy E. McNiven(5) | 2019 | | $ | 286,460 |
| | $ | — |
| | $ | 151,035 |
| | $ | 104,021 |
| | $ | 10,909 |
| | $ | 552,425 |
|
| SVP, Operations & Manufacturing | 2018 | | 64,615 |
| | 88,000 |
| | 103,498 |
| | 23,842 |
| | 1,292 |
| | 281,247 |
|
| | | | | | | | | | | | | | |
| Ronald J. Foster | 2019 | | $ | 328,752 |
| | $ | — |
| | $ | 100,692 |
| | $ | 128,405 |
| | $ | 15,275 |
| | $ | 573,124 |
|
| SVP, Chief Marketing Officer | 2018 | | 325,000 |
| | — |
| | 98,353 |
| | 121,475 |
| | 16,325 |
| | 561,153 |
|
| | | | | | | | | | | | | | |
| Owen A. Serjeant | 2019 | | $ | 249,154 |
| | $ | — |
| | $ | 604,134 |
| | $ | — |
| | $ | 28,376 |
| | $ | 881,664 |
|
| Former President | 2018 | | 410,000 |
| | — |
| | 737,584 |
| | 238,382 |
| | 1,715 |
| | 1,387,681 |
|
| | | | | | | | | | | | | |
|
|
| |
(1) | The amounts included in the “Unit Awards” column reflect the aggregate grant date fair value of awards granted during the fiscal years ended December 31, 2019 and 2018, as applicable, in accordance with FASB ASC Topic 718. The grant date fair value of performance phantom unit awards granted in each year are reported based on the probable outcome of the performance conditions on the grant2021 Payment of Cash Retention Awards
On July 27, 2020 we entered into Cash Retention Award Agreements (the “2020 Retention Agreements”) with Mr. Roy McNiven, our former Senior Vice President of Operations and Mr. Moscoso. Under the 2020 Retention Agreements, each NEO was given an opportunity to earn a cash award equal to 100% of their annual base salary; 25% of the total award was contingent upon their continued employment with us through April 2, 2021, and 75% of the award could be earned based on our attainment of fourth quarter 2020 adjusted EBITDA and year-end liquidity targets, and targeted increase in the market price of our units through the determination date. Determination of amounts earned under the 2020 Retention Agreements was accelerated as of the date of the GP Sale, and on February 8, 2021, the earned amounts of the awards were paid to Messrs. McNiven and Moscoso ($188,370 and $128,575, respectively).
The value of the 2019 performance phantom unit awards assuming achievement of the maximum performance level would be: Mr. Serjeant, $604,134; Mr. McNiven, $151,035; and Mr. Foster, $100,692. Phantom unit awards and performance phantom unit awards granted under the CSI Compressco equity plan on February 21, 2019 relate to our common units and are valued at $2.66 per common unit in accordance with FASB ASC Topic 718. Each phantom unit award and performance phantom unit award granted on February 21, 2019 was granted in tandem with distribution equivalent rights (“DERs”) that entitle the award holder to receive an additional number of units equal in value to any distributions we pay during the period the award is outstanding times the number of units subject to the award. Each phantom unit award vests ratably over three years on the anniversary of the grant date until fully vested on February 21, 2022. Each performance phantom unit covers a three-year performance period and vesting of such award is subject to satisfaction of the performance criteria as determined by our Board.
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| |
(2) | Amounts shown in the "Non-Equity Incentive Compensation Plan" column are the earned portions of awards granted under TETRA's Cash Incentive Compensation Plan for the annual performance period ended December 31, 2019. Such awards are payable, to the extent earned, based on financial and operational performance measures, including CSI Compressco's 2019 EBITDA and Distributable Cash Flow, Total Recordable Incident Rate (TRIR), Chargeable Vehicle Incident Rate (CVIR), and individual performance objectives. Amounts earned as of December 31, 2019 are expected to be paid on March 16, 2020. |
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(3) | The amounts reflected represent: (i) matching contributions under our 401(k) Retirement Plan; (ii) for Messrs. McNiven, Foster, and Serjeant, the value of distribution equivalent rights settled in connection with the vesting of unit awards that relate to CSI Compressco's common units, which was $21,059 for Mr. Serjeant, $1,409 for Mr. McNiven, and $7,383 for Mr. Foster in 2019; and (iii) for Mr. Foster, the use of a company-owned vehicle. Mr. Serjeant's employment with our general partner ceased on July 22, 2019 and the unvested phantom units held by Mr. Serjeant were forfeited. |
| |
(4) | The compensation of Mr. Murphy, the President and CEO of TETRA, is determined by TETRA. As noted above, no compensation has been reported for Mr. Murphy because none of his compensation is specifically allocated to us and no portion payable by us under the Omnibus Agreement is specifically allocated to the services provided to us by Mr. Murphy. |
| |
(5) | Mr. McNiven was first employed by us on October 1, 2018. The amount included in the "Bonus" column for Mr. McNiven is a guaranteed cash bonus payable to him under the terms of his initial employment with us. |
Retirement, Health and Welfare Benefits
Due to our relationship with TETRA, ourOur employees are eligible to participate in a variety of health and welfare and retirement programs sponsored by TETRA.the Partnership. Members of our senior management are generally eligible for the same benefit programs on the same basis as the remainder of our employees. Our health and welfare programs are intended to protect employees against catastrophic loss and to encourage a healthy lifestyle. These health and welfare programs include medical, wellness, pharmacy, dental, life insurance, short-term and long-term disability insurance, and insurance against accidental death and disability.
401(k) Plan.Plan
Our
Our employees, areexcluding the Named Executive Officers, were eligible to participate in TETRA’s 401(k) Retirement Plan (the “401(k)“TETRA 401(k) Plan”), which is prior to the GP Sale. Following the GP Sale, the employees continued to participate in the TETRA 401(k) Plan pursuant to the Co-Employer Agreement until August 1, 2021 when the employees were no longer eligible to participate in the TETRA 401(k) plan and began to participate in the CSI Compressco 401(k) Retirement plan (the “CSI Compressco 401(k) Plan”). The TETRA 401(k) Plan and the CSI Compressco 401(k) Plan are intended to supplement a participant’s personal savings and social security. Under the 401(k) Plan,these plans, eligible employees may contribute on a pretax basis up to 70% of their compensation, subject to an annual maximum established under the Code. Our general partnerThe Partnership generally makes a matching contribution under the 401(k) Planthese plans equal to 50% of the first 8% of a participant’s annual compensation that is contributed to the 401(k) Plan.plan. Such matching contribution was suspended in April 2020 and reinstated in December 2021. All employees (other than nonresident aliens) who have reached the age of eighteen are eligible to
participate in the CSI Compressco 401(k) Plan beginning on the first day of the month following their completion of 30thirty (30) days of service with us.
Nonqualified Deferred Compensation Plan.Certain of our Senior Management, directors, and certain other key employees have the opportunityThe Named Executive Officers were eligible to participate in TETRA’sSpartan’s 401(k) retirement plan through December 31, 2021. Effective January 1, 2022 the Spartan plan was eliminated and the Named Executive Nonqualified Excess Plan, which is an unfunded, deferred compensation program.Officers transitioned to the CSI Compressco 401(k) Retirement Plan. Under the program, participantsSpartan 401(k) plan, eligible employees may defercontribute on a specified portion of their annual total cash compensation, including salary and performance-based cash incentive,pretax basis subject to certainan annual maximum established minimums. The amounts deferred increase or decrease dependingunder the Code. Spartan made a matching contribution of 100% on the deemed investment elections selected byfirst 3% of a participants annual compensation that was contributed to the participant from among various hypothetical investment election options. Deferral contributions and earnings credited401(k) plan. All employees (other than non resident aliens) who have reached the age of twenty-one (21) were eligible to such contributions are 100% vested and may be distributed in cash at a time selected by the participant and irrevocably designated on the participant’s deferral form. In-service distributions may not be withdrawn until two years following the participant’s initial enrollment. Notwithstanding the participant’s deferral election, the participant will receive distribution of his deferral account if the participant becomes disabled or dies, or upon a change in control. None of our NEOs participated in the Executive Nonqualified Excess Plan during 2019.participate.
Perquisites
Perquisites (“perks”) are not a material component of our compensation. In general, NEOs do not receive reimbursements for meals, airline and travel costs other than those costs allowed for all employees, or for tickets to sporting events or entertainment events, unless such tickets are used for business purposes. Mr. Foster is entitled to the use of a company-owned vehicle, as is the case for all of our sales and field service personnel. During 2019, except for the car allowance (or the use of acompany-owned car) for Mr. Foster,2021, no NEO received an allowance from us for any of the above or a reimbursement for any expense incurred for non-business purposes.
Outstanding Equity Awards at Fiscal Year End
The Partnership continued to maintain our LTIP following the GP Sale, and each of Messrs. Jackson, Byers and Price was eligible to receive a grant of phantom unit awards during the 2021 year. Each phantom unit award granted on February 19, 2021 was granted in tandem with distribution equivalent rights (“DERs”) that entitle the award holder to receive an additional number of units equal in value to any distributions we pay during the period the award is outstanding times the number of units subject to the award. The awards are intended to cover equity-based incentive awards for these NEOs for a period of three years and no new equity-based awards are currently planned for Messrs. Jackson, Byers and Price until 2024. Due to his resignation in January 2021, Mr. Murphy did not receive equity awards pursuant to the LTIP during the 2021 year, and all equity awards that he received pursuant to the LTIP in previous years received accelerated vesting and settlement in connection with the GP Sale.
The following table discloses the number and value of unvested phantom unit awards granted under the CSI Compressco LP Second Amended and Restated 2011 Long Term Incentive Plan as of December 31, 2021.
Outstanding Equity Awards at Fiscal Year End Table
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| | | Unit Awards | | | | |
| | Number of Units that Have Not Vested(1) | | Market Value of Units that Have Not Vested(2) | | | | |
| Name | | | | |
| | | (#) | | ($) | | | | |
| John E. Jackson | | 459,184 | | $ | 546,429 | | | | | |
| Jonathan W. Byers | | 459,184 | | $ | 546,429 | | | | | |
| Robert W. Price | | 459,184 | | $ | 546,429 | | | | | |
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(1)One third of the unvested phantom unit awards granted on February 19, 2021 will vest on February 19, 2022, February 19, 2023, and February 19, 2024.
(2)All outstanding unit awards relate to our common units. Market value is determined by multiplying the number of units that have not vested by $1.19, the closing price of our common units on December 31, 2021.
Potential Payments upon a Change of Control or Termination
We do not have previously entered intoa severance plan for, or any agreement with, any Named Executive Officer that would require us to make any termination payments.
TETRA has a Change of Control Agreement with Mr. Murphy, which was in effect during the brief period of time in which he provided services to us in 2021. Payments and benefits under the TETRA Change of Control Agreement are triggered only on a change of control of TETRA, therefore Mr. Murphy did not receive severance or change in control benefits in connection with his resignation on January 29, 2021.The terms of the TETRA Change of Control Agreement and a quantification of potential benefits to Mr. Murphy under the TETRA Change of Control Agreement will be disclosed in TETRA’s 2022 Proxy Statement.
Under the LTIP, our general partner’s Board of Directors, in its sole discretion, may accelerate the vesting of restricted units, phantom units, and performance phantom units held by our Named Executive Officers upon termination of their employment.Solely for purposes of these disclosures, we have assumed that all outstanding unit awards would be accelerated if the Named Executive Officer’s employment agreementswas terminated without cause in connection with a change of control, or upon the death, disability, or retirement of such officer, although such an acceleration is not a guaranteed benefit. The amounts that each NEO that was providing services to us as of December 31, 2021 could receive in connection with the potential acceleration of their outstanding equity awards would have been $546,429.
Director Compensation
Each director who is not an employee of our general partner or any of its subsidiaries, receives non-cash compensation of $60,000 per year for attending regularly scheduled board meetings. The non-cash compensation is paid for the upcoming service year in the form of phantom unit awards that have an intended grant date value of $60,000, prorated for any newly-elected director to such director’s date of election and that vest over the service
year as set forth below. Directors who are appointed as the chairmen of the Audit Committee receive additional non-cash compensation of $10,000 per year, prorated from their respective dates of appointment in their initial year of service, which is also paid in the form of phantom unit awards. All such awards of phantom units are granted under our LTIP. Directors are reimbursed for out-of-pocket expenses incurred in connection with their service as directors. In addition, each non-employee director is paid an annual cash retainer of $60,000 per year, paid in quarterly installments.
Directors who are also our officers or employees, or officers or employees of our general partner or any of its subsidiaries, did not receive any compensation for duties performed as our directors. Consequently, none of Mr. Murphy (our former President and Chief Executive Officer,) Mr. Serrano (our former Chief Financial Officer), Mr. Jackson (our current Chief Executive Officer), Mr. Byers (our current Chief Financial Officer) or Mr. Price (our current Chief Operating Officer) was compensated for his service to us as a director during 2021. Had any of the current NEOs received compensation as a director, that compensation would have been reported within the Summary Compensation Table above.
The following table discloses the cash, equity awards, and other compensation earned, paid, or awarded, as the case may be, to each of our NEOs that are substantially identical tonon-employee directors during the formfiscal year ended December 31, 2021.
Director Compensation Table | | | | | | | | | | | | | | | | | | | | | | | |
| Name | | Fees Earned or Paid in Cash(1)(2) | | Unit Awards(3) | | Total | |
| | | | | | | |
| Denise Essenberg | | $ | 70,467 | | | $ | 60,000 | | | $ | 130,467 | | |
| Ted Gardner | | $ | 53,267 | | | $ | 60,000 | | | $ | 113,267 | | |
| Stephen Gill | | $ | 73,267 | | | $ | 60,000 | | | $ | 133,267 | | |
James R. Larson(4) | | $ | 84,500 | | | $ | 70,000 | | | $ | 154,500 | | |
Paul D. Coombs(5) | | $ | 3,887 | | | $ | — | | | $ | 3,887 | | |
D. Frank Harrison(5) | | $ | 3,887 | | | $ | — | | | $ | 3,887 | | |
William D. Sullivan(5) | | $ | 3,887 | | | $ | — | | | $ | 3,887 | | |
Elijio V. Serrano(5) | | $ | — | | | $ | — | | | $ | — | | |
| | | | | | | |
(1) The amounts in this column reflect payments earned for service as a non-employee director during 2021.
(2) Fees earned includes cash retainer of agreement executed by all$20,000 for service on the Conflicts Committee for the following Board of our employees. Each agreement evidencesDirectors: James Larson (Chairman), Denise Essenberg, and Stephen Gill.
(3) Unit awards granted on February 19, 2021 with vest date on February 19, 2022. The amounts included in the at-will nature“Unit Awards” column reflect the aggregate grant date fair value of employment and does not guarantee the term of employment, which is entirely at the discretion of our Board, or otherwise set forth the salary and other compensation of the NEOs, which is establishedawards granted on February 19, 2021 (which will vest on February 19, 2022), in accordance with FASB ASC Topic 718. Phantom unit awards granted under the procedures described above.LTIP on February 19, 2021 relate to our common units and were valued at $1.96 per common unit in accordance with FASB ASC Topic 718. See Note [12] to our consolidated financial statements for the year ended December 31, 2021 for a discussion of other assumptions used in determining the grant date value of these awards. As of December 31, 2021, each of Messrs. Essenberg, Gardner and Gill held [30,612] outstanding phantom units, and Mr. Larson held [36,902] outstanding phantom units.
(4) Mr. Larson received an additional unit award on May 5, 2021 for his service as the Board of Directors Audit Committee Chairman, which will also vest on February 19, 2022.
(5) Paul D. Coombs, D. Frank Harrison, William D. Sullivan and Elijio V. Serrano all resigned from the Board on 1/29/2021 at the closing of the GP Sale.
Indemnification Agreements
We andanticipate entering into indemnification agreements with each of our current directors and our NEOs have executed an indemnification agreement that providesofficers, which will provide that we will indemnify them to the fullest extent permitted by our SecondThird Amended and Restated Agreement of Limited Partnership, Bylaws, and applicable law. The indemnification agreement is also providesexpected to provide that our directors and officers will be entitled to the advancement of fees as permitted by applicable law and sets out the procedures required for determining entitlement to and obtaining indemnification and expense advancement. In addition, our charter documents provide that each of our directors and officers and any person serving at our request as a director or officer of another corporation, partnership, joint venture, trust, or other enterprise shall be indemnified to the fullest extent permitted by law in connection with any threatened, pending, or completed action, suit, or proceeding (including civil, criminal, administrative, or investigative proceedings) arising out of or in connection with his or her services to us or to another corporation, partnership, joint venture, trust, or other enterprise, at our request. We purchase and maintain insurance on behalf of any person who is a director or
officer of the aforementioned corporation, partnership, joint venture, trust, or other enterprise, against any liability asserted against him or her and incurred by him or her in any such capacity, or arising out of his or her status as an officer or director, subject to the terms and conditions of that insurance. In addition, Messrs. Coombs, Murphy, Serrano, Wallace, and Sullivan, in their capacities as directors and/or executive officers of TETRA, have executed indemnification agreements with TETRA that are substantially similar to the indemnification agreements executed by each of them in connection with their services to us, and they benefit from the protection of similar insurance.
Potential Payments upon a Change of Control or Termination
Other than the Change of Control Agreement with Mr. Foster and the Letter Agreement with Mr. McNiven that are further described below, as of the date of this filing, we do not have a defined severance plan for, or any agreement with, any Named Executive Officer that would require us to make any termination payments. We have previously entered into employment agreements with each of our Named Executive Officers that are substantially
identical to the form of agreement executed by all of our employees. These agreements evidence the at-will nature of employment, and do not guarantee term of employment, salary, severance or change in control payments.
Under the CSI Compressco LP Second Amended and Restated 2011 Long Term Incentive Plan, our Board of Directors, in its sole discretion, may accelerate the vesting of restricted units, phantom units, and performance phantom units held by our Named Executive Officers upon termination of their employment. For purposes of the following disclosure, we have assumed that all outstanding unit awards would be accelerated if the Named Executive Officer's employment was terminated in connection with a change of control, or upon the death, disability, or retirement of such officer.
Outstanding Equity Awards at Fiscal Year End
The following table shows outstanding stock option awards previously awarded by TETRA and classified as exercisable as of December 31, 2019 for each Named Executive Officer. The table also discloses the number and value of unvested phantom unit awards granted under the CSI Compressco LP Second Amended and Restated 2011 Long Term Incentive Plan as of December 31, 2019.
Outstanding Equity Awards at Fiscal Year End Table
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | Option Awards(1) | | Unit Awards |
| | | Number of Securities Underlying Unexercised Options | | Option Exercise Price | | Option Expiration Date | | Number of Units that Have Not Vested | | Market Value of Units that Have Not Vested(2) | | Equity Incentive Plan Awards: Number of Unearned Units that Have Not Vested(3) | | Equity Incentive Plan Awards: Market Value or Payout Value of Unearned Units that Have Not Vested(3) |
| Name | | Options Exercisable | | Options Unexercisable | | | | | | |
| | | (#) | | (#) | | ($/Share) | | | | (#) | | ($) | | (#) | | ($) |
| Brady M. Murphy | | | | | | | | | | 0 | | $ | — |
| | 0 | | $ | — |
|
Owen A. Serjeant(4) | | | | | | | | | | 0 | — | $ | — |
| | | | |
Owen A. Serjeant(4) | | | | | | | | | | 0 | — | $ | — |
| | 0 | — | $ | — |
|
| Ronald J. Foster | | 31,500 |
| | — |
| | $ | 4.17 |
| | 4/9/2019 | | | | | | | | |
| Ronald J. Foster | | 14,500 |
| | — |
| | $ | 10.20 |
| | 5/20/2020 | | | | | | | | |
| Ronald J. Foster | | | | | | | | | | 935 | (5) | $ | 2,538 |
| | | | |
| Ronald J. Foster | | | | | | | | | | 4,247 | (6) | $ | 11,529 |
| | 6,370 | (7) | $ | 17,293 |
|
| Ronald J. Foster | | | | | | | | | | 4,927 | (8) | $ | 51,381 |
| | 18,927 | (9) | $ | 51,381 |
|
| Roy E. McNiven | | | | | | | | | | 12,946 | (10) |
|
| | | |
|
|
| Roy E. McNiven | | | | | | | | | | 28,390 | (8) | $ | 77,070 |
| | 28,390 | (9) | $ | 77,070 |
|
| |
(1) | All outstanding option awards relate to TETRA’s common stock. Under the terms of TETRA’s equity plans, the option exercise price must be greater than or equal to 100% of the closing price of the common stock on the date of grant. |
| |
(2) | All outstanding unit awards relate to our common units. Market value is determined by multiplying the number of units that have not vested by $2.71, the closing price of our common units on December 31, 2019. |
| |
(3) | The number of units earned under these performance phantom unit awards will be determined based on actual level of achievement of an established performance objective. The amounts shown in these columns assume achievement of the target performance objective. Market value is determined by multiplying the target number of unearned units that have not vested by $2.71, the closing price of our common units on December 31, 2019. |
| |
(4) | Mr. Serjeant terminated employment July 22, 2019 and forfeited all unvested phantom units. |
| |
(5) | Two-third of the phantom unit award granted on February 24, 2017 vested on February 24, 2018 and February 24, 2019; the remaining one-third portion vested on February 24, 2020. |
| |
(6) | One-third of the unvested phantom unit award granted on February 24, 2018 vested on each of February 24, 2019 and February 24, 2020; the remaining one-third portion will vest on February 24, 2021. |
| |
(7) | The performance phantom unit award for the performance period of January 1, 2018 through December 31, 2020 may be settled pursuant to the terms of the award in March of 2021 if applicable performance objectives are met. The number of units shown is the target number of units that may be issued under the award. |
| |
(8) | One-third of the unvested phantom unit award granted on February 21, 2019 vested on February 21, 2020; the remaining one-third portions will vest on February 21, 2021, and February 21, 2022. |
| |
(9) | The performance phantom unit award for the performance period of January 1, 2019 through December 31, 2021 may be settled pursuant to the terms of the award in March of 2022 if applicable performance objectives are met. The number of units shown is the target number of units that may be issued under the award. |
| |
(10) | One-third of the unvested phantom unit award granted on October 1, 2018 vested on October 1, 2019; the remaining one-third portions will vest on October 1, 2020, and October 1, 2021. |
Change of Control Agreement with Mr. Foster.
We have entered into a change of control agreement (the “Foster COC Agreement”) with Mr. Foster. The Foster COC Agreement has an initial two-year term, with an automatic one-year extension on the second anniversary of the effective date (and any anniversary date thereafter) unless a cancellation notice is given at least 90 days prior to the expiration of the then applicable term. Under the Foster COC Agreement, we have an obligation to provide certain benefits to Mr. Foster upon a qualifying termination event that occurs in connection with or within two years following a “change of control” of us or TETRA. A qualifying termination event under the Foster COC Agreement includes the termination of Mr. Foster’s employment with us other than for Cause (as that term is defined in the Foster COC Agreement) or termination by Mr. Foster for Good Reason (as that term is defined in the Foster COC Agreement).
Under the Foster COC Agreement, if a qualifying termination event occurs in connection with or within two years following a change of control, we have an obligation to pay Mr. Foster the following cash severance amounts: (i)(A) an amount equal to Mr. Foster’s earned but unpaid Annual Bonus (as that term is defined in the Foster COC Agreement) attributable to the immediately preceding calendar year and earned but unpaid Long Term Bonus (as that term is defined in the Foster COC Agreement) attributable to the performance period ended as of the end of the immediately preceding calendar year to the extent such amounts would have been paid to Mr. Foster had he remained employed by us, and in each case only to the extent the performance goals for such bonus were achieved for the applicable performance period, plus (B) Mr. Foster’s prorated target Annual Bonus for the current year, plus (C) an amount equal to Mr. Foster’s target Long-Term Bonus for each outstanding award; plus (ii) the product of 2 times the sum of Mr. Foster’s Base Salary and target Annual Bonus amount for the year in which the qualifying termination event occurs; plus (iii) an amount equal to the aggregate premiums and any administrative fees applicable to Mr. Foster due to an election of continuation of coverage that he would be required to pay if he elected to continue medical and dental benefits under the group health plan for Mr. Foster and his eligible dependents without subsidy from us for a period of two years following the date of Mr. Foster’s qualifying termination event. The Foster COC Agreement also provides for full acceleration of vesting of any outstanding restricted unit awards, phantom unit awards, and other unit-based awards upon Mr. Foster’s qualifying termination event to the extent permitted under the applicable plan. All payments and benefits due under the Foster COC Agreement are conditioned upon the execution and nonrevocation by Mr. Foster of a release for our benefit. All payments under the Foster COC Agreement are subject to reduction as may be necessary to avoid exceeding the amount allowed under Section 280G of the Internal Revenue Code of 1986, as amended.
The Foster COC Agreement also contains certain confidentiality provisions and other restrictions applicable to Mr. Foster. In addition to restrictions upon improper disclosure and use of Confidential Information (as defined in the Foster COC Agreement), Mr. Foster agrees that for a period of two years following a termination of employment for any reason, he will not solicit our employees or otherwise engage in a competitive business with us as more specifically set forth in the Foster COC Agreement. Such obligations are only binding on Mr. Foster if he receives the severance benefits described above.
TETRA has a Change of Control Agreement with Mr. Murphy, which was in effect during 2019. Payments and benefits under the TETRA Change of Control Agreement are triggered only on a change of control of TETRA. The terms of the TETRA Change of Control Agreement and a quantification of potential benefits to Mr. Murphy under the TETRA Change of Control Agreement will be disclosed in TETRA’s 2020 Proxy Statement.
Letter Agreement with McNiven Rider. On June 23, 2019, we entered into a letter agreement (the “Bonus Letter Agreement”) with Mr. McNiven. Under the terms of the Bonus Letter Agreement, Mr. McNiven is eligible to receive two separate bonus payments. The first bonus opportunity is a bonus of $175,000, the payment of which is conditioned upon Mr. McNiven’s continued employment through the earlier of a designated date or the completion of certain corporate transactions. The second bonus opportunity ranges from $275,000 to $475,000 and is subject to the completion of certain corporate transactions prior to a designated date. The Bonus Letter Agreement requires Mr. McNiven to comply with certain confidentiality, non-solicitation and non-competition covenants for the time periods set forth in the agreement.
Director Compensation
As of January 1, 2019, each director who is not an employee of our general partner, TETRA, or any of its subsidiaries, receives non-cash compensation of $60,000 per year for attending regularly scheduled board meetings. The non-cash compensation is paid for the upcoming service year in the form of phantom unit awards that have an intended value of $60,000, prorated for any newly-elected director to such director's date of election and that vest over the service year as set forth below. Directors who are appointed as the chairmen of our Conflicts Committee and Audit Committee receive additional non-cash compensation of $5,000 and $10,000 per year, respectively, prorated from their respective dates of appointment in their initial year of service, which is also paid in the form of phantom unit awards. All such awards of phantom units are granted under our Second Amended and Restated 2011 Long Term Incentive Plan. Directors are reimbursed for out-of-pocket expenses incurred in connection with their service as directors. In addition, each non-employee director is paid an annual cash retainer of $60,000 per year, paid in quarterly installments.
Directors who are also our officers or employees, or officers or employees of TETRA, do not receive any compensation for duties performed as our directors. Consequently, none of Mr. Murphy, our President and the President and Chief Executive Officer of TETRA, Stuart M. Brightman, the former Chairman of the Board of the general partner and Chief Executive Officer of TETRA who retired from such positions on May 3, 2019, Mr. Serjeant, our former President, or Mr. Serrano, our Chief Financial Officer and the Chief Financial Officer of TETRA, was compensated for his service to us as a director during 2019.
On May 3, 2019, the Board approved awards of 19,994 phantom units with an aggregate grant date fair market value of $64,380 to Messrs. Coombs, Harrison, Larson, and Sullivan for their service as directors during the May 2019 through May 2020 service year. Also on May 3, 2019, with regard to the May 2019 through May 2020 service year, Mr. Harrison received an additional award of 1,666 phantom units with a grant date fair market value of $5,365 for his service as chairman of the Conflicts Committee, and Mr. Larson received an additional award of 3,332 phantom units with a grant date fair market value of $10,729 for his service as chairman of the Audit Committee. One-third of all of the phantom units so awarded were immediately vested on May 3, 2019, and additional one-third portions of each award vest on January 3, 2020 and May 3, 2020. A phantom unit is a notional unit that entitles the director to receive a common unit of the Partnership upon vesting of the phantom unit. Each award of phantom units to Messrs. Coombs, Harrison, Larson, and Sullivan was granted in tandem with distribution equivalent rights (“DERs”) that entitle the award holder to receive an additional number of common units equal in value to any distributions we pay during the period the award is outstanding times the number of unvested phantom units subject to the award. DERs are subject to the same vesting restrictions and risk of forfeiture applicable to the corresponding phantom units. It is anticipated that directors will be appointed to the Board in May of each calendar year.
The following table discloses the cash, equity awards, and other compensation earned, paid, or awarded, as the case may be, to each of our non-employee directors during the fiscal year ended December 31, 2019.
Director Compensation Table
|
| | | | | | | | | | | | | |
| Name | | Fees Earned or Paid in Cash(1) | | Unit Awards(2) | | Total | |
| | | ($) | | ($) | | ($) | |
| Stuart M. Brightman | | $ | — |
| (3) | $ | — |
| (3) | $ | — |
| (3) |
| Paul D. Coombs | | 60,000 |
| | 64,381 |
| | 124,381 |
| |
| D. Frank Harrison | | 60,000 |
| | 69,745 |
| | 129,745 |
| |
| James R. Larson | | 60,000 |
| | 75,110 |
| | 135,110 |
| |
| Brady M. Murphy | | — |
| (3) | — |
| (3) | — |
| (3) |
| Owen A. Serjeant | | — |
| (3) | — |
| (3) | — |
| (3) |
| Elijio V. Serrano | | — |
| (3) | — |
| (3) | — |
| (3) |
| William D. Sullivan | | 60,000 |
| | 64,381 |
| | 124,381 |
| |
| |
(1) | The amounts in this column reflect payments earned for service as a non-employee director during 2019. |
| |
(2) | Phantom units granted on May 3, 2019 are valued at $3.22 per common unit in accordance with FASB ASC Topic 718. As of December 31, 2019, the following phantom units are unvested for the respective director: Mr. Coombs - 13,996 phantom units; Mr. Harrison - 14,512 phantom units; Mr. Larson - 15,628 phantom units; and, Mr. Sullivan - 13,396 phantom units. |
| |
(3) | Messrs. Brightman, Murphy, Serjeant, and Serrano did not receive compensation for their service as directors during 2019 since they are/were employees of our general partner or TETRA. |
Compensation Policies and Risk Management
The following will discuss our policies and practices for compensating our employees (including our employees that are not Named Executive Officers) as they relate to our risk management practices and risk-taking incentives. We have determined that our compensation policies and practices for our employees are not reasonably likely to have a material adverse effect on us, thus no such disclosure exists at this time. We seek to structure a balance between achieving strong short-term annual results and ensuring long-term viability and success by providing both annual and long-term incentive opportunities. We believe that providing both short- and long-term awards also helps to minimize any risk to us or our unitholders that could arise from excessive focus on short-term performance. Our general partner’s board of directors is aware of the need to routinely assess our compensation policies and practices and will make a determination as to the necessity of this particular disclosure on an annual basis.
Management and Compensation Committee Interlocks and Insider Participation
As previously discussed, our general partner’s Board is not required to maintain, and does not maintain, a compensation committee. During 2019,2021, Messrs. Brightman, Murphy Serrano and Serjeant,Serrano, who were directors of our general partner prior to the GP Sale, were also executive officers of TETRA. All compensation decisions with respect to Mr. Brightman, Mr.Messrs. Murphy and Mr. Serrano arewere made by TETRA and they dodid not receive any other compensation directly from us or from our former general partner. All compensation decisions with respect to Mr. Serjeant were made by TETRA and our general partner as described above, with the exception of equity awards under the CSI Compressco LP Second Amended and Restated 2011 Long Term Incentive Plan which, if awarded, are granted by our general partner’s Board. Please read Item 13, “Certain“Item 13. Certain Relationships and Related Party Transactions, and Director Independence” below, for information about relationships among us, our former general partner, and TETRA.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
Beneficial Ownership of Certain Unitholders and Management
The following table sets forth certain information with respect to the beneficial ownership of our common units as of December 31, 20192021 with respect to each person that beneficially owns five percent (5%) or more of our outstanding common units, and as of March 12, 2020,2, 2021 with respect to Spartan Energy Holdco LLC and (i) our directors; (ii) our Named Executive Officers ("NEOs"(“NEOs”); and (iii) our directors and executive officers as a group.group during 2021.
| | | | | | | | | | | | | | | | | | | | |
| Name and Business Address of Beneficial Owner | | Common Units Beneficially Owned | | | | Percentage of Class(1) |
| | | | | | |
Spartan Energy Partners LP
1735 Hughes Landing Blvd., Suite 200
The Woodlands, Texas 77380 | | 63,824,877 | | | (2) | | 45.4 | % |
| | | | | | |
| | | | | | |
Hill City Capital Mast Fund LP
89 Nexus Way
Camara Bay, Grand Cayman KY1-9009 | | 7,407,407 | | | | | 5.3 | % |
| | | | | | |
| | | | | | |
Brady M. Murphy (3) | | 195,121 | | | | | * |
| John E. Jackson | | 594,476 | | | | | * |
| Jonathan W. Byers | | 443,450 | | | | | * |
| Denise Essenberg | | 31,475 | | | | | * |
| Ted Gardner | | 1,207,586 | | | | | * |
| James R. Larson | | 154,069 | | | | | * |
| Stephen R. Gill | | 370,370 | | | | | |
| Robert W. Price | | 326,209 | | | | | * |
| | | | | | |
| Director and executive officers as a group (11 persons) | | 3,234,250 | | | | | 2.3 | % |
|
| | | | | | | | |
| Name and Business Address of Beneficial Owner | | Common Units Beneficially Owned | | | | Percentage of Class(1) |
| | | | | | | |
TETRA Technologies, Inc. 24955 Interstate 45 North The Woodlands, Texas 77380 | | 16,190,448 |
| | (2) | | 34.4 | % |
Invesco Ltd. 1555 Peachtree Street NE, Suite 1800 Atlanta, Georgia 30309 | | 5,451,670 |
| | (3) | | 11.6 | % |
Merced Capital, L.P.
601 Carlson Parkway, Suite 200
Minnetonka, Minnesota 55305 | | 3,754,987 |
| | (4) | | 7.98 | % |
| Brady M. Murphy | | — |
| | | | * |
|
| Owen A. Serjeant | | 39,503 |
| | | | * |
|
| Paul D. Coombs | | 55,338 |
| | | | * |
|
| D. Frank Harrison | | 56,917 |
| | | | * |
|
| James R. Larson | | 64,891 |
| | | | * |
|
| Elijio V. Serrano | | 8,046 |
| | | | * |
|
(1)Reflects common units beneficially owned as a percentage of common units outstanding.
|
| | | | | | | | |
| Name and Business Address of Beneficial Owner | | Common Units Beneficially Owned | | | | Percentage of Class(1) |
| William D. Sullivan | | 70,107 |
| | | | * |
|
| Ronald J. Foster | | 101,710 |
| | | | * |
|
| Roy E. McNiven | | 11,314 |
| | | | * |
|
| Director and executive officers as a group (16 persons) | | 457,219 |
| | | | 0.97 | % |
| |
(1) | Reflects common units beneficially owned as a percentage of common units outstanding. |
| |
(2) | The common units beneficially owned by TETRA Technologies, Inc. are directly held of record by our general partner, CSI Compressco Investment, LLC, and TETRA International Incorporated, each a wholly owned subsidiary of TETRA Technologies, Inc. Each of our general partner and TETRA International Incorporated(2)The common units beneficially owned by Spartan Energy Partners LP. are directly held of record by our general partner, CSI Compressco GP LLC, and CSI Compressco Investment LLC, each a wholly owned subsidiary of Spartan Energy Holdco LLC. Each of our general partner and CSI Compressco Investment, L.L.C. has sole voting and investment power over the common units held by them. As a result, TETRA Technologies, Inc. has indirect, sole voting and investment power over the common units held by our general partner and TETRA International Incorporated. |
| |
(3) | Pursuant to a Schedule 13G/A dated February 11, 2020, Invesco Ltd. reports sole voting power and sole dispositive power with respect to 5,451,670 of our common units. |
| |
(4) | Pursuant to a Schedule 13G/A dated January 23, 2020, Merced Capital, L.P., together with Series E of Merced Capital Partners, LLC and David A. Ericson, report shared voting power and shared dispositive power with respect to 3,754,987 of our common units. |
The following table sets forth certain information with respect to the beneficial ownership of the common stockunits held by them. As a result, Spartan Energy Holdco LLC has indirect, sole voting and investment power over the common units held by our general partner and CSI Compressco Investment LLC.
(3)Mr. Murphy resigned as both an officer and director of TETRA as of March 12, 2020 with respect to (i) our directors; (ii) our NEOs; and (iii) our directors and executive officers asCSI Compressco effective January 29, 2021. He did not receive a group.phantom unit award during the 2021 year.
|
| | | | | | | | |
| Name of Beneficial Owner | | Amount and Nature of Beneficial Ownership | | | | Percentage of Class |
| | | | | | | |
| Brady M. Murphy | | 552,667 |
| | (1) | | * |
|
| Owen A. Serjeant | | — |
| | | | * |
|
| Paul D. Coombs | | 925,552 |
| | (1) | | * |
|
| D. Frank Harrison | | — |
| | | | * |
|
| James R. Larson | | — |
| | | | * |
|
| Elijio Serrano | | 399,155 |
| | | | * |
|
| William D. Sullivan | | 191,624 |
| | (1) | | * |
|
| Ronald J. Foster | | 6,601 |
| | (2) | | * |
|
| Roy E. McNiven | | — |
| | | | * |
|
| Director and executive officers as a group (16 persons) | | 2,396,174 |
| | (3) | | 1.91 | % |
| |
(1) | Includes 0 shares subject to options exercisable within 60 days of March 12, 2020. |
| |
(2) | Includes 14,500 shares subject to options exercisable within 60 days of March 12, 2020. |
| |
(3) | Includes 774,494 shares subject to options exercisable within 60 days of March 12, 2020. |
Equity Compensation Plan Information
The following table provides information as of December 31, 2019,2021, regarding compensation plans (including individual compensation arrangements) under which our common units are authorized for issuance.
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| Plan Category | | Number of Securities
to be Issued upon
Exercise of
Outstanding Options,
Warrants or Rights | | Weighted Average
Exercise Price of
Outstanding Options,
Warrants, or Rights | | | | Number of Securities
Remaining Available for Future
Issuance under Equity Comp.
Plans (Excluding Securities
Shown in the First Column) |
Equity compensation plans approved by security holders(1) | | 2,275,622 | | | $ | — | | | (2) | | 1,000,492 | |
| Equity compensation plans not approved by security holders | | — | | | $ | — | | | | | — | |
| Total: | | 2,275,622 | | | $ | — | | | | | 1,000,492 | |
(1)Consists of the Second Amended and Restated 2011 Long Term Incentive Plan.
(2)Represents phantom unit awards and performance phantom unit awards outstanding under the Second Amended and Restated 2011 Long Term Incentive Plan. These phantom unit awards and performance phantom unit awards do not have an exercise price.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
In February 2019, we entered into a transaction with TETRA under which a subsidiary of TETRA agreed to fund the construction of and purchase from one of our subsidiaries up to $15.0 million of new compressor packages and to subsequently lease the packages back to us in exchange for a monthly rental fee. As of December 31, 2019, pursuantPursuant to this arrangement, $14.8 million has beenwas funded by TETRA for the construction of new compressor packages and all compressor packages were completed and leased to us under this agreement. TheDuring December 2020, TETRA sold the compressor packages aresubject to the existing lease to Spartan. As of December 31, 2020, the financing obligation was $14.7 million and is included in property, plant,accrued liabilities and equipment
Under the Omnibus Agreement, subject to certain limitations, TETRA and our general partner agreed to indemnify us against certain potential environmental claims, losses, and expenses associated with TETRA’s operation of our Predecessor entity prior to the completion of the Initial Public Offering, and we have agreed to indemnify TETRA and our general partner for environmental claims arising following the completion of the Initial Public Offering regarding the businesses contributed by TETRA and our general partner to us. TETRA and our general partner also agreed to indemnify us for liabilities related to certain defects in title to our assets and certain consents and permits necessary to own and operate such assets, and tax liabilities attributable to TETRA’s operation of our assets prior to the completion of the Initial Public Offering.
Item 14. Principal Accounting Fees and Services.
The following table sets forth the aggregate fees for professional services rendered to us by our principal accounting firm, Ernst & Young LLP, forGrant Thornton and its member firms and respective affiliates during the fiscal years ended December 31, 2019,2021, and 2018, respectively:2020, respectively (in thousands):
The Audit Committee of our general partner has adopted a pre-approval policy with respect to services which may be performed by our independent registered public accounting firm (the “Audit Firm”). This policy provides that all audit and non-audit services to be performed by the Audit Firm must be specifically pre-approved on a case-by-case basis by the Audit Committee. The Audit Committee may delegate pre-approval authority to one or more of its members. The member to whom such authority is delegated must report, for informational purposes only, any pre-approval decisions to the entire Audit Committee at or before its next scheduled meeting. As of the date hereof, the Audit Committee has delegated this authority to the Chairman of the Audit Committee. Neither the Audit Committee, nor the person to whom pre-approval authority is delegated, may delegate their responsibilities to pre-approve services performed by the Audit Firm to our management.
Item 15. Exhibits and Financial Statement Schedules.
Item 16. Form 10-K Summary.
None.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, CSI Compressco LP has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the Registrant and in the capacities with CSI Compressco GP Inc,LLC, its general partner, and on the dates indicated:
Board of Directors of CSI Compressco GP Inc.
We have audited the accompanying consolidated balance sheets of CSI Compressco LP (a Delaware limited partnership) and subsidiaries (the Partnership)“Partnership”) as of December 31, 20192021 and 2018,2020, the related consolidated statements of operations, comprehensive income (loss), partners’ capital, and cash flows for each of the threetwo years in the period ended December 31, 2019,2021, and the related notes (collectively referred to as the “consolidated financial“financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership atas of December 31, 20192021 and 2018,2020, and the results of its operations and its cash flows for each of the threetwo years in the period ended December 31, 2019,2021, in conformity with U.S.accounting principles generally accepted accounting principles.
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOBPublic Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.