CSI Compressco LP - Annual Report: 2019 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON D.C. 20549

FORM 10-K

(Mark One)

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2019

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

COMMISSION FILE NUMBER 001-35195

CSI Compressco LP

(EXACT NAME OF THE REGISTRANT AS SPECIFIED IN ITS CHARTER)



Delaware			94-3450907
(State or Other Jurisdiction of Incorporation or Organization)			(I.R.S. Employer Identification No.)

24955 Interstate 45 North	The Woodlands,	Texas	77380
(Address of Principal Executive Offices)			(ZIP CODE)

(281) 364-2244

(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
COMMON UNITS REPRESENTING LIMITED PARTNERSHIP INTERESTS	CCLP	NASDAQ

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.



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

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

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

The aggregate market value of common stock held by non-affiliates of the Registrant was $107,685,200 as of June 28, 2019.

As of March 12, 2020, there were 47,268,857 Common Units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE- NONE

TABLE OF CONTENTS



	Part I
Item 1.	Business	1
Item 1A.	Risk Factors	9
Item 1B.	Unresolved Staff Comments	29
Item 2.	Properties	29
Item 3.	Legal Proceedings	29
Item 4.	Mine Safety Disclosures	29

	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	30
Item 6.	Selected Financial Data	32
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	33
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	45
Item 8.	Financial Statements and Supplementary Data	45
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	45
Item 9A.	Controls and Procedures	45
Item 9B.	Other Information	48

	Part III
Item 10.	Directors, Executive Officers, and Corporate Governance	48
Item 11.	Executive Compensation	53
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	59
Item 13.	Certain Relationships and Related Transactions, and Director Independence	61
Item 14.	Principal Accounting Fees and Services	64

	Part IV
Item 15.	Exhibits, Financial Statement Schedules	64
Item 16.	Form 10-K Summary	67

(i)

Forward-Looking Statements

This Annual Report on Form 10-K contains “forward-looking statements” and information based on our beliefs and those of our general partner. Forward-looking statements in this annual 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;


•	our existing debt levels and our flexibility 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 replace 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;


•	the ability of our general partner to retain key personnel;


•	information technology risks including the risk from cyberattack;


•	global or national health concerns, including the outbreak of pandemics or epidemics such as the coronavirus (COVID-19),


•	the effect and results of litigation, regulatory matters, settlements, audits, assessments, and 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.

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 Inc. References to “TETRA” refer to TETRA Technologies, Inc. and TETRA’s controlled subsidiaries, other than us. References to “Compressco” 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. 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") 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") pursuant to the Securities Act of 1933, as amended (the "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).

(ii)

PART I

Item 1. Business.

The financial statements presented in this annual 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, The Woodlands, Texas, 77380. Our phone number is 281-364-2244, and our website is www.csicompressco.com.

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 compression services and equipment for natural gas and oil production, gathering, artificial lift, transmission, processing, and storage. We sell both standard and custom-designed, engineered compressor packages, and provide aftermarket services and compressor package parts and components manufactured by third-party suppliers. We provide these compression services and equipment to a broad base of natural gas and oil exploration and production, midstream, and transmission 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, and Argentina. We design and fabricate a majority of the compressor packages that we use to provide compression services or sell to customers.

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 trained technicians in most of the major oil and natural gas producing basins in the United States.

Our long-term growth strategy includes expanding our existing businesses through organic growth and accretive acquisitions, both domestic and international.

Our operations are organized into a single business segment. See "Note 13 - 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 14 - Geographic Information" contained in the Notes to Consolidated Financial Statements in this Annual Report.

Certain of our domestic 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 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 legal counsel has not concluded generate qualifying income, and pay U.S. federal income tax with respect to such operations. We strive to ensure that all new domestic 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.

Through TETRA’s wholly owned subsidiary and our general partner, CSI Compressco GP Inc., TETRA 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. Unlike shareholders in a publicly traded corporation, our unitholders are not entitled to elect our general partner or its directors. All of our general partner’s directors are elected by TETRA. 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.

Products and Services

We are a provider of compression services and equipment for natural gas and oil production, gathering, artificial lift, transmission, processing, and storage. 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 fabricate and sell both standard compressor packages and custom-designed, engineered compressor packages. We also provide aftermarket compression services and compressor package parts and components manufactured by third-party suppliers.

Compression 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 5,200 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, 2019 is summarized in the following table:



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	%

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"). 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.

Other Related Services. In certain Latin America markets, 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.

Compression Services Contract Terms. Our compression services are primarily performed under service contracts using our low-, medium-, and high-horsepower compressor packages. A significant portion of these compression services are provided under services contracts that our legal counsel has concluded generate qualifying income that is not subject to U.S. federal income taxes. 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' notice, continue on a month-to-month basis thereafter. Our medium- and high- horsepower compression service contracts typically have an initial term of twelve months, but range from six months to twenty-four months. After the initial terms on our medium- and high-horsepower compression service 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. 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 domestic 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 Sales

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 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 domestic and international markets in which we operate. Beginning in 2017 and continuing throughout all of 2019, shale production for oil and the associated natural gas produced from these wells provided improved compression demand opportunities for our products and services. Further, over the same period, the shift to gas lift as a preferred lifting method improved demand for our complete range of product offerings.

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 America and certain other regions outside of the United States. While most of our domestic services are performed throughout Texas (with a concentration in the Permian Basin), the San Juan Basin, the Rocky Mountain region, and the Mid-Continent region of the United States, we also have a presence in

other producing regions. We continue to seek opportunities to further expand our operations into other regions in the United States and elsewhere in the world.

Our service contracts are generally terminable upon thirty days’ notice after the primary term has expired. Although we enter into short-term contracts, many of our largest customers have been with us for over five years. Our significant customers for the year ended December 31, 2019 include various major integrated oil companies, public and private independent exploration and production companies and midstream companies, none of which individually accounted for more than 10% of our consolidated revenues for the year ended December 31, 2019. 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 are 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, 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, Kodiak Gas Services, and USA Compression. Our competition in the standard compressor package fabrication 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.

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 attempt to build close working relationships with our existing and potential customers to educate 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 call center.

Backlog

Our equipment 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 of 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. 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 subsidiaries had approximately 791 full-time employees who provide services to conduct our operations. Our general partner’s U.S. employees and our employees in Canada 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.

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 our service and sales operations and fabricating plants are in substantial compliance with all applicable U.S. and foreign health, safety, and environmental laws and regulations. We are committed to conducting all of our operations under the highest standards of safety and respect for the environment. However, risks of substantial costs and liabilities 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 in the future. Changes in health, safety, and environmental regulations could subject us to more rigorous standards and could affect demand for our customer's product which in turn would impact demand for our products. We cannot predict the extent to which our operations may be affected by future laws, regulations, and enforcement policies.

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 States include:


•	the Clean Air Act ("CAA") and comparable state laws, and regulations thereunder, which regulate air emissions;


•	the Federal Water Pollution Control Act of 1972 (the "Clean Water 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, or (“CERCLA”), 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 States are subject to regulation under the Occupational Safety and Health Act ("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, 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, the EPA finalized rules that establish new air emission controls under the EPA's New Source Performance Standards ("NSPS") and NESHAP for natural gas and natural gas liquids production, processing and transportation activities. These rules establish specific requirements associated with emissions from compressor packages and controllers at natural gas gathering and boosting stations. However, these rules are the subject of a recently proposed rule modifying or removing certain requirements. In addition, 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 proposed rules to remove or modify certain of these requirements. We are not currently aware of any material impacts to our operations associated with these rules.

The EPA has determined that greenhouse gases ("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. These rules have also been the subject of EPA's current deregulatory agenda, which has resulted in further legal challenges to attempts to modify these rules. 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 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 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, 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 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 believe that we are in substantial compliance with these requirements and other applicable similar laws.

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 States are subject to foreign governmental laws and regulations relating to health, safety, and the environment and other regulated activities. We believe that our operations are in substantial compliance with existing foreign governmental laws and regulations.

Related Party Agreements

Under our Omnibus Agreement with TETRA, our general partner provides 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 provide personnel and services necessary for the conduct of certain of our Latin American business. In addition, under the Omnibus Agreement, TETRA provides 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.

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, 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 domestic and 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 domestic 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 prices steadily rose during late 2017 and early 2018, they fell during late 2018, with 2018 West Texas Intermediate oil prices dropping from a high of $76.90 per barrel in October 2018 to a low of $42.36 per barrel in December 2018. The West Texas Intermediate price averaged $57.05 per barrel during 2019. 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 per million British thermal units ("MMBtu") in November 2018 to a low of $2.03 per MMBtu in August 2019. Beginning in February 2020, there has been a severe drop in the price of oil. As of March 12, 2020, the price of West Texas Intermediate oil was $31.50 per barrel and the Henry Hub price for natural gas was $1.84 per MMBtu. Despite the previous 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 we have experienced in 2020 continues or further declines, this may negatively impact the operating cash flows and exploration and development activities and plans of many of our customers and have a negative impact on the demand for our compression products and services.

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 Arabia of a significant reduction in its export prices as well as a recent announcement by Russia that previously agreed upon production cuts will expire 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 impact our operations and business by reducing global and national economic activity resulting in a decline in the demand for oil and for our compression services and equipment, and affecting the health 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 of the business disruption and related financial impact from the coronavirus (COVID-19)

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 and equipment and our ability to operate our business in the manner and on the timelines previously planned. The extent to which the coronavirus (COVID-19) or other health pandemics or epidemics may impact our results will depend on future developments, which are highly uncertain and cannot be predicted.

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 beginning in March 2020 will make it more difficult to obtain debt and equity financing in the near future. As of December 31, 2019, the market price for our common units was $2.71 per common unit, down from the 2019 high of $3.98 per common unit during August 2019. Due, in part, to recent stock market decline, the closing price of our common units was $0.82 as of March 12, 2020. 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, we had approximately $649.4 million aggregate principal amount outstanding of our 7.25% Senior Notes and 7.50% Senior Secured 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, our aggregate capital expenditures totaled $75.8 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. As of December 31, 2019, our total cash balance was $2.4 million. 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 and 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 $2.4 million of cash on hand at the beginning of 2020 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 Secured Notes as of December 31, 2019 is $344.2 million. In addition, we have an aggregate carrying value of $291.4 million of our 7.25% Senior Notes outstanding as of December 31, 2019. 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). 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 million per quarter, or $1.9 million per year, based on the number of common units outstanding as of March 12, 2020. 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 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. 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 Secured Notes and our 7.25% Senior 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 Secured 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. 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 Secured Notes and 7.25% Senior Notes may declare all of the 7.50% Senior Secured Notes and 7.25% Senior 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% of our 2019 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. 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 TETRA could adversely affect our business and our ability to make distributions to our common unitholders.

The credit and business risk profile of TETRA 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 TETRA and its affiliates in assigning a rating because of TETRA's control of us, their performance of 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. If the pledge of TETRA's ownership of our general partner becomes effective in the future, control over our general partner could be transferred to TETRA’s lenders in the event of a default by TETRA.

We may be unable to negotiate extensions or replacements of our contracts with our customers, which are generally cancellable on 30-days' notice, which could adversely affect our results of operations and cash available for distribution to our common unitholders.

We generally provide compression services to our customers under contracts that, after the initial term, are cancellable on thirty days’ notice. We may be unable to negotiate extensions or replacements 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.

We depend on particular suppliers and are vulnerable to engine and compressor component shortages and

price increases, which could have a negative impact on our 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 suppliers 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 in our business strategy or any of these factors could cause cash flows from the sale of compressor packages to decrease.

Our sales to and operations in foreign countries 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, and Argentina as well as a number of other foreign countries. A portion of our expected future growth could include expansion in these and other foreign countries. Foreign 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. We are also subject to the FCPA, which prohibits U.S. companies and their intermediaries from bribing foreign 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 foreign 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 expose us to the changing economic, legal, and political environment in that country, including changing regulations governing the repatriation of cash generated from our operations in Argentina.

The current economic, legal, and political environment in Argentina and 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 increased over the past three 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.

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 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. 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. 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 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, which could cause our 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.

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.

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 and Argentina, and in certain other foreign countries, 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 and Argentinian peso 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 the economic environment could result in further significant impairments of certain of our long-lived assets.

Decreased commodity prices have, 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. The EPA rules also require so-called “green” completions at hydraulically fractured natural gas wells. Under the current administration, EPA proposed rules in 2019 to loosen these requirements; however the rules have not yet been finalized. In addition, the EPA requires the annual reporting of GHG emissions from specified large GHG emission sources in the United States, 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, 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, ratified or otherwise indicated their intent to be bound by the Paris Agreement. However, in June 2017, President Trump announced that the United States intends to withdraw 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 which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time. In November 2019 the United States submitted formal notice required under the Paris Agreement. The withdrawal is scheduled to be effective November 4, 2020. To the extent that other countries implement the Paris Agreement or the United States imposes other climate change regulations on the oil and natural gas industry, it could have an adverse effect on our business.

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. 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 increased frequency and severity of storms, floods, and other climatic events; 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 for the oil and natural gas hydraulic fracturing industry (however, rules have been proposed in 2019 to modify or rescind some of these requirements); 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 2015 that established new or more stringent standards for performing hydraulic fracturing on federal and Indian lands. BLM has issued a final rule rescinding the 2015 action; this new rule remains subject to legal challenge.

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.

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 information technology systems of our general partner and TETRA 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 outsources certain business process functions to TETRA and third-party providers and similarly relies 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 allocates 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 invests in security technology, performs penetration tests from time to time, and designs our 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 experience 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, the market price for our common units ranged from a high of $3.98 per common unit to a low of $2.18 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) outbreak and its potential impact on the world economy. The volatility of our common units may make it difficult for you to resell our common units when you want at attractive prices.

We are listed on the NASDAQ Exchange (“NASDAQ”). We are required to meet NASDAQ’s continued listing standards, including a requirement that the closing market price of our common units not be below $1.00 per common unit for any period of thirty consecutive trading days. As indicated above, the closing market price of our common units was recently below $1.00. In addition, the continued listing standards have minimum market capitalization and partners’ 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 capital expenditures, the payment of distributions on those additional units will decrease the amount we distribute on each outstanding unit.

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 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 quarterly 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 redemption of our remaining outstanding Preferred Units). Our estimates of these future cash requirements are used 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 reduced amount per common unit, or that there will not be further decreases in the amount of distributions in the future.

TETRA controls our general partner, which has sole responsibility for conducting our business and managing our operations, and thereby controls us. TETRA has conflicts of interest, which may permit it to favor its own interests to our unitholders’ detriment.

TETRA controls our general partner, and through the general partner controls us. Some of our general partner’s directors are directors of TETRA or its affiliates that own our general partner. Therefore, conflicts of interest may arise between TETRA 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 TETRA 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 TETRA to pursue a business strategy that favors us. The directors and officers of TETRA and its affiliates have a fiduciary duty to make these decisions in the best interests of TETRA, 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, 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 TETRA 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 TETRA 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 resetting 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 TETRA 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. 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 of 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 may be transferred to a third party without common unitholder consent.

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 TETRA 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. 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, 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, our general partner and its affiliates own an aggregate of 34% 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. 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). As of March 12, 2020, our general partner and its affiliates own an aggregate of 34% 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 the 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 interpretation 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 of partnership tax treatment 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, repeal the qualifying income exception within Section 7704(d)(1)(E) of the Internal Revenue Code of 1986, as amended, upon which we rely for our status as a partnership for U.S. federal income tax purposes.

In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. 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% of our consolidated revenues for the year ended December 31, 2019, was generated in non-U.S. jurisdictions, primarily Mexico, Canada, and Argentina. 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’ 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 unitholders will be treated as partners 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 of U.S. federal income taxes, and, in some cases, state and local income taxes on the unitholder’s share of our taxable income, even if the unitholder receives no 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 States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. 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 by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferees but were not withheld. Because the “amount realized” includes a partner’s share of the partnership’s liabilities, 10% 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 rule to transfers of publicly traded interests 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 purposes of determining the amount subject to withholding. However, it is not clear when such regulations will be finalized and if they will be finalized in their current form.

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 (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, and Argentina, 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 States 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, 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 facility in Oklahoma City, Oklahoma, and additional service facilities in North Dakota, Oklahoma, Texas, and Utah. We lease 23 additional service facilities in Alabama, Arkansas, California, Colorado, Kansas, Louisiana, New Mexico, Oklahoma, Texas, West Virginia, Wyoming, and foreign locations in Argentina, Canada, and Mexico. We lease a number of storage facilities located across the geographic markets we serve. We utilize a portion of TETRA’s headquarters in The Woodlands, Texas as our headquarters office. Our primary assets include our fleet of compression and other equipment. See "Item 1 Business - Compression Services," for a discussion and description of our compression fleet. All obligations under our 7.50% Senior Secured Notes are secured by a first-lien security interest in substantially all of our assets, including our fabrication facilities in Midland, Texas and Oklahoma City, Oklahoma, but excluding other real property assets.

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, there were 31 holders of record of the common units.

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 there 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 fiscal quarter, the sum of all cash and cash equivalents on hand at the end of the quarter:


•	less the amount of cash reserves established by our general partner to:


◦	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 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);


•	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. 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. 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 2019 totaled $0.04 per common unit. See "Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources - Cash Flows - Financing 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 reduced to approximately 1.4% and may be 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 of Units Purchased	Average Price Paid per 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
Oct 1 – Oct 31, 2019	—	—	N/A	N/A
Nov 1 – Nov 30, 2019	—	—	N/A	N/A
Dec 1 – Dec 31, 2019	—	—	N/A	N/A
Total	—		N/A	N/A

Securities Authorized for Issuance under Equity Compensation Plans.

See "Item 12. Security Ownership of Certain Beneficial Owners and Management" for information regarding our equity compensation plans as of December 31, 2019.

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.



	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



	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 our Consolidated Financial Statements and accompanying Notes included 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- looking statements involve risks and uncertainties. See “Item 1A. Risk Factors,” for additional discussion of these factors and risks.

Business Overview

We provide compression services and equipment for natural gas and oil production, gathering, artificial lift, transmission, processing, and storage. Our compression and related services business includes a fleet of more than 5,200 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 business includes the fabrication, assembly, and sale of both standard and custom-designed, engineered compressor packages. Our design aftermarket business provides compressor package 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 and Argentina.

Our operations are significantly dependent upon the demand for, and production of, oil and the associated natural gas from unconventional oil and natural gas production in the domestic and international markets in which we operate. Beginning in 2017 and continuing throughout all of 2019, shale production for oil and the associated natural gas produced from these wells provided improved compression demand opportunities for our products and services. This growth in demand continues to drive increases in our compression services revenues, through increased activity and customer contract pricing. This has resulted 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 oil prices as well as the volatility and declines in the stock market may impact the demand for our compression services and equipment.

We are focused on aligning our compression fleet to meet the growing demand for high-horsepower. Our high-horsepower engines are well suited for centralized gas lift, which is 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, we are refocusing our low-horsepower engines to target liquids (oil 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.

Given the high demand for compression services we have experienced through February 2020 and the high utilization of our compression equipment fleet, we continue to focus on our ability to appropriately expand 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 options available to us to expand our fleet.

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, 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, is provided within the Results of Operations sections below.

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 non-cash charges 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. 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 and general partner;


•	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

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,
	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

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 as of the dates shown.



	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,
	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 utilization figures for December 31, 2019 above reflect the impairment of certain low-horsepower class compressor packages 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.

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.

New Equipment Sales Backlog. Our new equipment sales business includes the design, fabrication, assembly, and sale of both standard 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 order to meet the customer delivery dates and performance criteria. New equipment sales backlog was $35.5 million as of December 31, 2019 compared to $105.2 million as of December 31, 2018. Changes in our new equipment sales backlog are a function of additional customer orders less completed orders that result in equipment sales revenues for the period. During the year ended December 31, 2019, we received cumulative orders of $64.4 million for new compressor packages. All of our December 31, 2019 new equipment sales backlog is expected to be recognized during 2020. 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 marketing effectiveness that allows us to plan future labor and raw material needs and measure our success in winning bids from our customers.

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 judgment and estimate used in the preparation of our financial statements.

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. 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. During the years ended December 31, 2018 and 2017, we recorded no impairments of long-lived assets. 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, it includes 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 sources of funds are our 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 require ongoing capital expenditure investment, 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. Please read 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 in 2018. 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 customer budgetary 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 during the 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 of December 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 "Note 2 - 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.

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.

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 Internal 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, 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"). 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.

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, 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.

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”) 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, wholly owned subsidiary of TETRA. We do not hold annual unitholder meetings. References in this Part III to the “Board,” “directors,” "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 charters 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, 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 six directors, four of whom, Paul D. Coombs, D. Frank Harrison, James R. Larson, and William D. Sullivan, are independent as defined under the listing standards of the NASDAQ.

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. Coombs has served as an independent director of our general partner's Board since May 6, 2014. Mr. Coombs has served as a member of TETRA’s 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 committee since May 2015. From April 2005 until his retirement in June 2007, Mr. Coombs served 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 committees of the board of directors of Balchem Corporation, a public company that is subject to the reporting requirements of the Exchange Act.

Mr. Coombs has more than 30 years of experience with TETRA, which, together with his entrepreneurial approach to management, provides our general partner’s Board with insight into our capabilities and personnel. Mr. Coombs has substantial experience with the services we provide and with oil and gas exploration and production operations in general.

D. Frank Harrison has served as an independent director of our general partner's Board and as Chairman of its Conflicts Committee and a member of its Audit Committee since April 2012. Since June 2011, 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. Harrison served as chairman of the board of directors (since 2007) and as chief executive officer and a director (since 2005) of Bronco Drilling Company, Inc. ("Bronco") until the acquisition of Bronco by Chesapeake Energy Corporation in June 2011. Bronco was a publicly traded company that provided contract drilling and well services. From 2002 to 2005, Mr. Harrison served as an agent for the purchase of oil and gas properties for entities controlled by Wexford Capital LLC. From 1999 to 2002, Mr. Harrison 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. He received his B.S. degree in Sociology from Oklahoma State 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'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"). 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 - 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. has served as the General Counsel of our general partner since October 2008. He has also served as TETRA’s General Counsel since 1994 and as 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 Master of Business Administration 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 Indiana 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, the Board held eleven meetings. The standing committees of the Board during 2019 consisted of an Audit Committee and a Conflicts Committee. During 2019, the Audit Committee held four meetings, and the Conflicts Committee held nine meetings.

Audit Committee. The Audit Committee is currently composed of Mr. Larson, as Chairman, and Messrs. Harrison and Sullivan. 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 Sullivan 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. The Conflicts Committee, which was formed in April 2012, is currently composed of Mr. Harrison, as Chairman, and Mr. Larson. 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 our general partner or its affiliates or us and TETRA 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 our general partner or its affiliates or us and TETRA 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 Second Amended and Restated Partnership Agreement of the Partnership, the Board has reviewed the independence of Messrs. Harrison and Larson and has 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. Harrison and Larson is 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 Executive Officers

Summary Compensation

The following table sets forth the compensation earned by (i) our President (“Principal Executive Officer”), (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”) for the fiscal year ended December 31, 2019.

Summary Compensation Table



Name and Principal Position	Year	Salary			Bonus			Unit Awards⁽¹⁾		Non-Equity Incentive PlanCompensation⁽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 grant date. 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.

(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.

(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, our employees are eligible to participate in a variety of health and welfare and retirement programs sponsored by TETRA. 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. Our employees are eligible to participate in TETRA’s 401(k) Retirement Plan (the “401(k) Plan”), which is intended to supplement a participant’s personal savings and social security. Under the 401(k) Plan, 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 partner generally makes a matching contribution under the 401(k) Plan equal to 50% of the first 8% of a participant’s annual compensation that is contributed to the 401(k) Plan. All employees (other than nonresident aliens) who have reached the age of eighteen are eligible to

participate in the 401(k) Plan beginning on the first day of the month following their completion of 30 days of service with us.

Nonqualified Deferred Compensation Plan. Certain of our Senior Management, directors, and certain other key employees have the opportunity to participate in TETRA’s Executive Nonqualified Excess Plan, which is an unfunded, deferred compensation program. Under the program, participants may defer a specified portion of their annual total cash compensation, including salary and performance-based cash incentive, subject to certain established minimums. The amounts deferred increase or decrease depending on the deemed investment elections selected by the participant from among various hypothetical investment election options. Deferral contributions and earnings credited 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.

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 a company-owned car) for Mr. Foster, no NEO received an allowance from us for any of the above or a reimbursement for any expense incurred for non-business purposes.

Employment Agreements

We have previously entered into employment agreements with each of our NEOs that are substantially identical to the form of agreement executed by all of our employees. Each agreement evidences the at-will nature 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 established in accordance with the procedures described above.

Indemnification Agreements

We and each of our current directors and our NEOs have executed an indemnification agreement that provides that we will indemnify them to the fullest extent permitted by our Second Amended and Restated Agreement of Limited Partnership, Bylaws, and applicable law. The indemnification agreement also provides 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	Option Exercise Price		Option Expiration Date	Number of Units that Have Not Vested		Market Value of Units that Have Not Vested⁽²⁾
	(#)	(#)	($/Share)			(#)		($)		(#)		($)
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, Messrs. Brightman, Murphy, Serrano and Serjeant, who were directors of our general partner, were also executive officers of TETRA. All compensation decisions with respect to Mr. Brightman, Mr. Murphy, and Mr. Serrano are made by TETRA and they do not receive any compensation directly from us or from our 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 Relationships and Related Party Transactions, and Director Independence” below, for information about relationships among us, our 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, 2019 with respect to each person that beneficially owns five percent (5%) or more of our outstanding common units, and as of March 12, 2020, with respect to (i) our directors; (ii) our Named Executive Officers ("NEOs"); and (iii) our directors and executive officers as a group.



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		*



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	%


*	Less than 1%.


(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 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 stock of TETRA as of March 12, 2020 with respect to (i) our directors; (ii) our NEOs; and (iii) our directors and executive officers as a group.



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	%


*	Less than 1%.


(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, 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⁾	761,332	$	—	⁽²⁾	3,390,000
Equity compensation plans not approved by security holders	—	$	—		—
Total:	761,332	$	—		3,390,000


(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.

Certain Transactions

Review, Approval or Ratification of Transactions with Related Persons

The related person transactions in which we engaged in 2019 were typically of a recurring, ordinary course nature, were previously made known to the Board of our general partner, and generally were of the sort contemplated by the Omnibus Agreement dated June 20, 2011, as amended on June 20, 2014 as described below, among us, our general partner and TETRA Technologies, Inc. (the “Omnibus Agreement”) and other related party agreements entered into in connection with our Initial Public Offering. We do not have formal, specified policies for the review, approval or ratification of transactions required to be reported under paragraph (a) of Regulation S-K Item 404. However, because related person transactions may result in potential conflicts of interest among management and board-level decision makers, our Partnership Agreement does set forth procedures that the general partner may utilize in connection with resolutions of potential conflicts of interest, including the referral of such matters to an independent conflicts committee for its review and approval or disapproval of such matters.

The Conflicts Committee, which was formed in April 2012, is currently composed of two directors of the Board of our general partner, each of whom has been deemed by the Board to meet the independence standards established under the Partnership Agreement. The purposes of the Conflicts Committee are to carry out certain duties set forth in our Partnership Agreement and the Omnibus Agreement, and to carry out any other duties delegated by the Board that involve or relate to conflicts of interest between us and TETRA, including its operating subsidiaries. The Conflicts Committee has sole authority to retain and terminate any consultants, attorneys, independent accountants or other service providers to assist it in the evaluation of conflicts matters.

The Conflicts Committee is charged with acting on an informed basis, in good faith and with an honest belief that any action taken by the committee is in our best interests. In taking any such action, including the resolution of a conflict of interest, the conflicts committee will be authorized to consider any factors it determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.

Transactions with our General Partner and its Affiliates

As of March 12, 2020, TETRA and certain of its subsidiaries, including our general partner, owned 16,190,448 common units, which constitutes a 34% limited partner interest in us, and an approximate 1% general partner interest in us. TETRA is, therefore, a “related person” to us as such term is defined by the SEC.

Distributions and Payments to the General Partner and its Affiliates

We will generally make cash distributions 99% to unitholders on a pro rata basis, including our general partner and certain subsidiaries of TETRA, as the holders of 16,190,448 common units and approximately 1% to our general partner. In addition, because distributions have exceeded certain higher target distribution levels (beginning with the distribution for the three month period ended June 30, 2014) as provided for in our Partnership Agreement, TETRA and our general partner were entitled to Incentive Distribution Rights of the distributions up to 48% of the distributions above the highest target distribution level. However, beginning with the distribution paid in February 2019, our quarterly cash distribution was reduced to $0.01 per common unit, and fell below the target distribution levels needed to result in Incentive Distribution Rights distribution to the General Partner.

For the year ended December 31, 2019, we paid aggregate cash distributions of approximately $1.9 million on our common units, and $27,000 on our general partner interest to TETRA and our general partner. On February 14, 2020, we paid quarterly distributions with respect to the period from October 1, 2019 through December 31, 2019, including approximately $0.3 million aggregate cash distribution on our common units, and $0.2 million of such cash distribution was paid to TETRA and our general partner.

Omnibus Agreement

Our ongoing relationship with TETRA and our general partner is governed by the Omnibus Agreement. Pursuant to the terms of the Omnibus Agreement, TETRA and our general partner are reimbursed for direct costs incurred in operating and maintaining our business and allocated expenses for personnel who perform corporate, general and administrative services on our behalf. TETRA and our general partner do not receive any separate management fee or other compensation for management of us. The Omnibus Agreement (other than the indemnification obligations described under “Indemnification for Environmental and Related Liabilities,” below) will terminate upon the earlier to occur of (i) a change in control of TETRA or our general partner, or (ii) any party providing at least 180 days prior written notice of termination to each of the other parties.

Subcontract Services

Under the Omnibus Agreement, we or TETRA and our general partner may, but neither 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 entity retaining such services, for such periods of time and in such amounts as may be mutually agreed upon by us and TETRA and our general partner. Any such services are required to be performed on terms that are either (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 us and TETRA, as determined by our general partner.

Sales, Leases, or Like-Kind Exchanges of Equipment

Under the Omnibus Agreement, we or TETRA and our general partner may, but neither 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 by the acquiring entity to meet its production enhancement or other oilfield services obligations, in such amounts, in such conditions, and for such periods of time as may be mutually agreed upon by us and our general partner. Any such sales, leases, or like-kind exchanges are required to be on terms that are either (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 us and TETRA, as determined by our general partner. In addition, unless otherwise approved by the conflicts committee of our general partner’s board of directors, TETRA may purchase newly fabricated equipment from us, but only for a price not less than the sum of the total costs (other than any allocations of general and administrative expenses) incurred by us in manufacturing 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. For the years ended December 31, 2019 and December 31, 2018, the approximate dollar value of the amounts involved in transactions between us and TETRA that were related to the sale, lease or like-kind exchange of equipment was as follows:

•

Pursuant to an equipment sharing agreement between two of our subsidiaries and a subsidiary of TETRA in connection with operations in Mexico, TETRA’s subsidiary charged our subsidiaries no equipment rental fees in 2019 and approximately $0.2 million during 2018. In addition, another TETRA subsidiary charged our subsidiaries $0.4 million and $0.3 million during 2019 and 2018, respectively, for parts and insurance coverage purchased for use by our subsidiaries in Mexico and for reimbursement to a TETRA subsidiary for certain capital expenditures.

•

In addition to the foregoing, we also provide early production services to a customer in Argentina. Two subsidiaries of TETRA charged a subsidiary of ours in Argentina approximately $0.7 million and $2.1 million during 2019 and 2018, respectively, for equipment that is leased, and other equipment that is subleased, along with associated technical service charges, from TETRA's subsidiary to our subsidiary in Argentina related to those operations. In connection with our operations in Argentina, our subsidiary invoiced another subsidiary of TETRA for reimbursement of expenses incurred on behalf of TETRA's subsidiary of approximately $0.1 million and $0.2 million during 2019 and 2018, respectively.

•

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, pursuant to this arrangement, $14.8 million has been funded by TETRA for the construction of new compressor packages and all compressor packages were completed and leased to us under this agreement. The compressor packages are included in property, plant, and equipment and corresponding financing obligations are included in amounts payable to affiliates and long-term affiliate payable in our consolidated balance sheet. As of December 31, 2019, the financing obligation was $15.3 million. Imputed interest expense recognized for the year ended December 31, 2019 was $1.3 million.

Provision of Personnel and Services

Our business operations are conducted by our general partner’s employees, our Canadian employees, and certain employees of TETRA’s Mexico-based subsidiaries. In addition, TETRA and our general partner provide certain corporate general and administrative services to us that are reasonably necessary for the conduct of our business. Such corporate general and administrative services include 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. Under the Omnibus Agreement, the services TETRA and our general partner provide to us must be substantially similar in nature and quantity to the services TETRA and our general partner previously provided to our successor entity and they can be no lower in quantity than is reasonably necessary to assist us in the management and operation of our business. For the year ending December 31, 2019 and December 31, 2018, TETRA and our general partner charged us approximately $31.9 million and $28.0 million, respectively, in reimbursement for such services. Interest related to these charges were $0.1 million and $0.0 million, respectively, on balances that were past due.

Indemnification for Environmental and Related Liabilities

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.

Director Independence

Please see Part III, Item 10 of this annual report (“Corporate Governance and Director Independence”) for a discussion of director independence matters, which discussion is incorporated by reference into this Item 13.

Item 14. Principal Accounting Fees and Services.

Fees Paid to Principal Accounting Firm

The following table sets forth the aggregate fees for professional services rendered to us by our principal accounting firm, Ernst & Young LLP, for the fiscal years ended December 31, 2019, and 2018, respectively:



	2019		2018
Audit fees	$	880,000	$	920,000
Audit related fees	—		—
Tax fees	—		—
Total fees	$	880,000	$	920,000

Our Audit Committee pre-approved all of the services and fees shown in the above table. Before approving these services and fees, our Audit Committee considered whether the provision of services by Ernst & Young LLP that are not related to the audit of our financial statements was compatible with maintaining the independence of Ernst & Young LLP, and concluded that it was.

Audit Committee Pre-Approval of Audit and Non-Audit Services

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.

PART IV

Item 15. Exhibits and Financial Statement Schedules.

(a) List of documents filed as part of this Report



1.	Financial Statements of the Partnership
		Page
	Reports of Independent Registered Public Accounting Firm	F-1
	Consolidated Balance Sheets at December 31, 2019 and 2018	F-3
	Consolidated Statements of Operations for the years ended December 31, 2019, 2018 and 2017	F-4
	Consolidated Statements of Comprehensive Income for the years ended December 31, 2019, 2018 and 2017	F-5
	Consolidated Statements of Partners’ Capital for the years ended December 31, 2019, 2018 and 2017	F-6
	Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017	F-7
	Notes to Consolidated Financial Statements	F-8
2.	Financial statement schedules have been omitted as they are not required, are not applicable, or the required information is included in the financial statements or notes thereto.
3.	List of Exhibits



3.1	Certificate of Limited Partnership of Compressco Partners, L.P., dated October 31, 2008 (incorporated by reference to Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 filed on November 10, 2008 (SEC File No. 333-155260)).



3.2	Certificate of Incorporation of Compressco Partners GP Inc., dated October 30, 2008 (incorporated by reference to Exhibit 3.3 to the Partnership’s Registration Statement on Form S-1 filed on November 10, 2008 (SEC File No. 333-155260)).
3.3	Certificate of Correction of the Certificate of Limited Partnership of Compressco Partners, L.P. (incorporated by reference to Exhibit 3.5 to Amendment No.1 to the Partnership’s Registration Statement on Form S-1/A filed on December 19, 2008 (SEC File No. 333-155260)).
3.4	Amendment to the Certificate of Limited Partnership of Compressco Partners, L.P., dated November 19, 2014 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on December 1, 2014 (SEC File No. 001-35195)).
3.5	Certificate of Amendment to the Certificate of Incorporation of Compressco Partners GP Inc., dated November 19, 2014 (incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K filed on December 1, 2014 (SEC File No. 001-35195)).
3.6	Second Amended and Restated Bylaws of Compressco Partners GP Inc., dated December 1, 2014 (incorporated by reference to Exhibit 3.4 to the Current Report on Form 8-K filed on December 1, 2014 (SEC File No. 001-35195)).
3.7	Second Amended and Restated Agreement of Limited Partnership of CSI Compressco LP, dated as of August 8, 2016 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on August 8, 2016 (SEC File No. 001-35195)).
3.8	Amendment No.1 to the Second Amended and Restated Agreement of Limited Partnership of CSI Compressco, LP, dated November 5, 2018 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed on November 8, 2018 (SEC File No. 001-35195)).
3.9	Amendment No. 2 to the Second Amended And Restated Agreement of Limited Partnership of CSI Compressco LP, dated December 24, 2018 (incorporated by reference to the Current Report on Form 8-K filed on December 26, 2018 (SEC File No. 001-35195)).
4.1	Specimen Unit Certificate representing Common Units (incorporated by reference to Exhibit 4.1 to Amendment No. 3 to the Partnership’s Registration Statement on Form S-1/A filed on April 12, 2011 (SEC File No. 333-155260)).
4.2	Indenture, dated as of August 4, 2014, by and among Compressco Partners, L.P., Compressco Finance Inc., the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on August 4, 2014 (SEC File No. 001-35195)).
4.3	Indenture, dated as of March 22, 2018, by and among CSI Compressco LP, CSI Compressco Finance Inc., the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Partnership’s Form 8-K filed on March 27, 2018 (SEC File No. 001-35195)).
4.4	Form of 7.500% Senior Secured First Lien Note due 2025 (incorporated by reference to Exhibit 4.1 to the Partnership’s Form 8-K filed on March 27, 2018 (SEC File No. 001-35195)).
4.5+	Description of the Registrant's Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934
10.1	Contribution, Conveyance and Assumption Agreement, dated June 20, 2011, by and among Compressco, Inc., Compressco Field Services, Inc., Compressco Canada, Inc., Compressco de Mexico, S. de R.L. de C.V., Compressco Partners GP Inc., Compressco Partners, L.P., Compressco Partners Operating, LLC, Compressco Netherlands B.V., Compressco Holdings, LLC, Compressco Netherlands Coöperatief U.A., Compressco Partners Sub, Inc., TETRA International Incorporated, Production Enhancement Mexico, S. de R.L. de C.V. and TETRA Technologies, Inc. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 24, 2011 (SEC File No. 001-35195)).
10.2	Omnibus Agreement, dated June 20, 2011, by and among Compressco Partners, L.P., TETRA Technologies, Inc. and Compressco Partners GP Inc. (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on June 24, 2011 (SEC File No. 001-35195)).
10.3	Form of Indemnification Agreement (incorporated by reference to Exhibit 10.5 to Amendment No. 4 to the Partnership’s Registration Statement on Form S-1/A filed on May 27, 2011 (SEC File No. 333-155260)).
10.4***	Change of Control Agreement with Ronald J. Foster (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 4, 2013 (SEC File No. 001-35195)).
10.5	First Amendment to Omnibus Agreement, dated June 20, 2014, by and among TETRA Technologies, Inc., Compressco Partners, L.P., and Compressco Partners GP Inc. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 26, 2014 (SEC File No. 001-35195)).
10.6***	Form of Director Restricted Unit Agreement under the CSI Compressco LP Second Amended and Restated 2011 Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q filed on May 9, 2019 (SEC File No. 001-35195).
10.7***	Form of Performance Phantom Unit Agreement under the CSI Compressco LP Second Amended and Restated 2011 Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Partnership’s Quarterly Report on Form 10-Q filed on May 9, 2019 (SEC File No. 001-35195).
10.8***	Form of Phantom Unit Agreement under the CSI Compressco LP Second Amended and Restated 2011 Long Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Partnership’s Quarterly Report on Form 10-Q filed on May 9, 2019 (SEC File No. 001-35195).



10.9***	Form of Non-Employee Director Phantom Unit Agreement under the CSI Compressco LP Second Amended and Restated 2011 Long Term Incentive Plan (incorporated by reference to Exhibit 10.4 to the Partnership’s Quarterly Report on Form 10-Q filed on May 9, 2019 (SEC File No. 001-35195).
10.10	First Amendment to Loan and Security Agreement, dated June 26, 2019, by and among CSI Compressco LP, CSI Compressco Sub Inc., and CSI Compressco Operating LLC, as borrowers, and Bank of America, N.A., as administrative agent, collateral agent, letters of credit issuer and swing line issuer (incorporated by reference to Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q filed on August 8, 2019 (SEC File No. 001-35195).
10.11***	First Amendment to Change of Control Agreement, dated June 23, 2019, by and between CSI Compressco GP Inc. and Ronald J. Foster (incorporated by reference to Exhibit 10.2 to the Partnership’s Quarterly Report on Form 10-Q filed on August 8, 2019 (SEC File No. 001-35195).
10.12	Loan and Security Agreement, dated as of June 29, 2018, by and among CSI Compressco LP, CSI Compressco Sub Inc., CSI Compressco Operating LLC, as borrowers, certain subsidiaries the borrowers named as guarantors therein, the lenders from time to time party thereto, and Bank of America, N.A., as administrative agent, collateral agent, letter of credit issuer and swing line issuer (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on July 3, 2018 (SEC File No. 001-35195)).
10.13	Purchase Agreement, dated as of March 8, 2018, by and among CSI Compressco LP, CSI Compressco Finance Inc., the guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 10.1 to the Partnership's Form 8-K filed on March 13, 2018 (SEC File No. 001-35195)).
10.14***	CSI Compressco LP Amended and Restated 2011 Long Term Incentive Plan, as amended through March 3, 2015 (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q filed on August 11, 2015 (SEC File No. 001-35195)).
10.15	Collateral Trust Agreement, dated as of March 22, 2018, by and among CSI Compressco LP, CSI Compressco Finance Inc., the other Grantors from time to time party thereto, U.S. Bank National Association, as Trustee, the other Priority Lien Representatives from time to time party thereto, and U.S. Bank National Association, as Collateral Trustee (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on March 27, 2018 (SEC File No. 001-35195)).
10.16	CSI Compressco LP Second Amended and Restated 2011 Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Partnership's 8-K filed on December 4, 2018 (SEC File No. 001-35195)).
10.17***+	Form of Bonus Letter Agreement under the CSI Compressco LP Second Amended and Restated 2011 Long Term Incentive Plan.
21+	Subsidiaries of the Partnership
23.1+	Consent of Ernst & Young LLP
31.1+	Certification of Principal Executive Officer Pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2+	Certification of Principal Financial Officer Pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Principal Executive Officer Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**	Certification of Principal Financial Officer Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS++	XBRL Instance Document
101.SCH++	XBRL Taxonomy Extension Schema Document
101.CAL++	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF++	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB++	XBRL Taxonomy Extension Label Linkbase Document
101.PRE++	XBRL Taxonomy Extension Presentation Linkbase Document


+	Filed with this report.


**	Furnished with this report.


***	Management contract or compensatory plan or arrangement.

Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Statements of Operations for the years ended December 31, 2019, 2018 and 2017; (ii) Consolidated Balance Sheets as of December 31, 2019 and December 31, 2018; (iii) Consolidated Statements of Partners’ Capital/Net Parent Equity for the years ended December 31, 2019, 2018 and 2017; (iv) Consolidated Statements of Comprehensive Income for the years ended December 31, 2019, 2018 and 2017; (v) Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017; and (vi) Notes to Consolidated Financial Statements for the year ended December 31, 2019.

Item 16. Form 10-K Summary.

None.

SIGNATURES

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.



		CSI COMPRESSCO LP
		By:	CSI Compressco GP Inc.,
			its general partner
Date:	March 16, 2020	By:	/s/Brady M. Murphy
			Brady M. Murphy, President
			(Principal Executive Officer)

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, its general partner, and on the dates indicated:



Signature	Title	Date
/s/Brady M. Murphy	President and Chairman of	March 16, 2020
Brady M. Murphy	the Board of Directors
	(Principal Executive Officer)

/s/Elijio V. Serrano	Chief Financial Officer and Director	March 16, 2020
Elijio V. Serrano	(Principal Financial Officer)

/s/Michael E. Moscoso	Vice President - Finance	March 16, 2020
Michael E. Moscoso	(Principal Accounting Officer)

/s/Paul D. Coombs	Director	March 16, 2020
Paul D. Coombs

/s/D. Frank Harrison	Director	March 16, 2020
D. Frank Harrison

/s/James R. Larson	Director	March 16, 2020
James R. Larson

/s/William D. Sullivan	Director	March 16, 2020
William D. Sullivan

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of CSI Compressco GP Inc.

and the Unitholders of CSI Compressco LP

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of CSI Compressco LP (the Partnership) as of December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive income (loss), partners’ capital, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 Framework), and our report dated March 16, 2020, expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence 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.

/s/ ERNST & YOUNG LLP

We have served as the Partnership's auditor since 2008.

Houston, Texas

March 16, 2020

F-1

CSI Compressco LP

Consolidated Balance Sheets

(In Thousands, Except Unit Amounts)



	December 31, 2019			December 31, 2018
ASSETS
Current assets:
Cash and cash equivalents	$	2,370		$	15,858
Trade accounts receivable, net of allowance for doubtful accounts of $3,350 in 2019 and $1,229 in 2018	64,760			65,067
Inventories	56,037			65,222
Prepaid expenses and other current assets	4,126			5,600
Total current assets	127,293			151,747
Property, plant, and equipment:
Land and building	35,125			35,024
Compressors and equipment	976,469			913,488
Vehicles	9,205			10,354
Construction in progress	26,985			41,086
Total property, plant, and equipment	1,047,784			999,952
Less accumulated depreciation	(405,417		)	(358,633		)
Net property, plant, and equipment	642,367			641,319
Other assets:
Deferred tax assets	24			13
Intangible assets, net of accumulated amortization of $27,751 in 2019 and $24,790 in 2018	28,017			30,978
Operating lease right-of-use assets	21,006			—
Other assets	3,539			2,687
Total other assets	52,586			33,678
Total assets	$	822,246		$	826,744
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable	$	47,837		$	33,408
Unearned income	9,505			24,898
Accrued liabilities and other	42,581			32,530
Amounts payable to affiliates	7,704			3,517
Total current liabilities	107,627			94,353
Other liabilities:
Long-term debt, net	638,238			633,013
Series A Preferred Units	—			30,900
Deferred tax liabilities	1,211			1,012
Long-term affiliate payable	12,324			—
Operating lease liabilities	13,822			—
Other long-term liabilities	33			63
Total other liabilities	665,628			664,988
Commitments and contingencies
Partners' capital:
General partner interest	180			505
Common units (47,078,529 units issued and outstanding at December 31, 2019 and 45,769,019 units issued and outstanding at December 31, 2018)	63,384			81,984
Accumulated other comprehensive income (loss)	(14,573		)	(15,086		)
Total partners' capital	48,991			67,403
Total liabilities and partners' capital	$	822,246		$	826,744

See Notes to Consolidated Financial Statements

F-2

CSI Compressco LP

Consolidated Statements of Operations

(In Thousands, Except Unit and Per Unit Amounts)



	Year Ended December 31,
	2019			2018			2017
Revenues:
Compression and related services	$	257,723		$	229,895		$	205,774
Aftermarket services	76,290			70,907			40,287
Equipment sales	142,568			137,861			49,505
Total revenues	476,581			438,663			295,566
Cost of revenues (excluding depreciation and amortization expense):
Cost of compression and related services	125,104			127,128			116,956
Cost of aftermarket services	63,757			57,870			32,256
Cost of equipment sales	128,638			123,399			44,286
Total cost of revenues	317,499			308,397			193,498
Depreciation and amortization	76,663			70,500			69,140
Impairments and other charges	3,160			681			—
Insurance recoveries	(555		)	—			(2,352		)
Selling, general, and administrative expense	43,100			39,600			33,438
Interest expense, net	53,375			52,585			43,135
Series A Preferred fair value adjustment (income) expense	1,470			(838		)	(3,402		)
Other (income) expense, net	(511		)	2,101			(216		)
Loss before income tax provision	(17,620		)	(34,363		)	(37,675		)
Provision for income taxes	3,353			2,615			2,784
Net loss	$	(20,973	)	$	(36,978	)	$	(40,459	)

General partner interest in net loss	$	(298	)	$	(607	)	$	(809	)
Common units interest in net loss	$	(20,675	)	$	(36,371	)	$	(39,650	)
Net loss per common unit:
Basic and diluted	$	(0.44	)	$	(0.88	)	$	(1.13	)
Weighted average common units outstanding:
Basic and diluted	47,006,543			41,552,804			35,035,428

See Notes to Consolidated Financial Statements

F-3

CSI Compressco LP

Consolidated Statements of Comprehensive Income (Loss)

(In Thousands)



	Year Ended December 31,
	2019			2018			2017
Net loss	$	(20,973	)	$	(36,978	)	$	(40,459	)
Foreign currency translation adjustment, net of tax of $0 in 2019, 2018, and 2017	513			(3,597		)	(1,078		)
Comprehensive loss	$	(20,460	)	$	(40,575	)	$	(41,537	)

See Notes to Consolidated Financial Statements

F-4

CSI Compressco LP

Consolidated Statement of Partners’ Capital

(In Thousands)



	Partners' Capital							Accumulated Other Comprehensive Income (Loss)			Total Partners' Capital
				Limited Partners
	General Partner			Common Unitholders
	Amount			Units	Amount
Balance as of December 31, 2016	$	3,061		33,262	$	150,599		$	(10,411	)	$	143,249
Net loss for 2017	(809		)	—	(39,650		)	—			(40,459		)
Distributions ($0.94 per unit)	(634		)	—	(32,434		)	—			(33,068		)
Equity compensation	—			—	862			—			862
Vesting of Phantom Units	—			212	—			—			—
Conversions of Series A Preferred	—			3,705	22,848			—			22,848
Omnibus agreement charges settled with common units	—			439	3,322			—			3,322
Translation adjustment, net of taxes of $0	—			—	—			(1,078		)	(1,078		)
Other	—			—	(649		)	—			(649		)
Balance as of December 31, 2017	$	1,618		37,618	$	104,898		$	(11,489	)	$	95,027
Net loss for 2018	(607		)	—	(36,371		)	—			(36,978		)
Distributions ($0.75 per unit)	(506		)	—	(30,788		)	—			(31,294		)
Equity compensation	—			—	420			—			420
Vesting of Phantom Units	—			129	—			—			—
Conversions of Series A Preferred	—			8,022	43,825			—			43,825
Translation adjustment, net of taxes of $0	—			—	—			(3,597		)	(3,597		)
Balance as of December 31, 2018	$	505		45,769	$	81,984		$	(15,086	)	$	67,403
Net loss for 2019	(298		)	—	(20,675		)	—			(20,973		)
Distributions ($0.04 per unit)	(27		)	—	(1,880		)	—			(1,907		)
Equity compensation	—			—	988			—			988
Vesting of Phantom Units	—			197	—			—			—
Conversions of Series A Preferred	—			1,113	3,048			—			3,048
Translation adjustment, net of taxes of $0	—			—	—			513			513
Other	—			—	(81		)	—			(81		)
Balance as of December 31, 2019	$	180		47,079	$	63,384		$	(14,573	)	$	48,991

See Notes to Consolidated Financial Statements

F-5

CSI Compressco LP

Consolidated Statements of Cash Flows

(In Thousands)



	Year Ended December 31,
	2019			2018			2017
Operating activities:
Net loss	$	(20,973	)	$	(36,978	)	$	(40,459	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization	76,663			70,500			69,140
Impairments and other charges	3,160			681			—
Provision (benefit) for deferred income taxes	129			(178		)	757
Gain on insurance recoveries associated with damaged equipment	(555		)	—			(2,352		)
Series A Preferred Unit distributions and adjustments	4,061			4,581			5,015
Equity-based compensation expense	1,064			639			1,219
Provision for doubtful accounts	2,459			1,004			968
Amortization and expense of financing costs	2,570			6,070			3,167
Other non-cash charges and credits	96			633			571
Gain on sale of property, plant, and equipment	(667		)	(217		)	(315		)
Changes in operating assets and liabilities:
Accounts receivable	(2,070		)	(19,287		)	(2,706		)
Inventories	(291		)	(23,536		)	(10,840		)
Prepaid expenses and other current assets	1,441			(2,247		)	(501		)
Accounts payable and accrued expenses	1,789			29,788			15,765
Other	(1,180		)	(1,332		)	(361		)
Net cash provided by operating activities	67,696			30,121			39,068
Investing activities:
Purchases of property, plant, and equipment, net	(75,798		)	(104,001		)	(27,953		)
Proceeds from sale of property, plant, and equipment	11,025			512			2,827
Proceeds from insurance recoveries associated with damaged equipment	555			—			2,352
Advances and other investing activities	—			(1		)	21
Net cash used in investing activities	(64,218		)	(103,490		)	(22,753		)
Financing activities:
Proceeds from long-term debt	45,000			380,000			80,900
Payments of long-term debt	(41,567		)	(258,000		)	(74,900		)
Cash redemptions of Preferred Units	(31,913		)	—			—
Distributions	(1,907		)	(31,294		)	(33,068		)
Debt issuance costs and other financing activities	(1,365		)	(8,999		)	(2,266		)
Advances from affiliates	14,782			—			—
Net cash provided by (used in) financing activities	(16,970		)	81,707			(29,334		)
Effect of exchange rate changes on cash	4			(81		)	(177		)
Increase (decrease) in cash and cash equivalents and restricted cash	(13,488		)	8,257			(13,196		)
Cash and cash equivalents and restricted cash at beginning of period	15,858			7,601			20,797
Cash and cash equivalents and restricted cash at end of period	$	2,370		$	15,858		$	7,601
Supplemental cash flow information:
Interest paid	$	47,788		$	38,550		$	31,674
Income taxes paid	$	3,133		$	2,056		$	3,005

See Notes to Consolidated Financial Statements

F-6

CSI COMPRESSCO LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2019

NOTE 1 — ORGANIZATION AND OPERATIONS

CSI Compressco LP, a Delaware limited partnership, is a provider of compression services and equipment for natural gas and oil production, gathering, artificial lift, transmission, processing, and storage. We sell standard and custom-designed, engineered compressor packages, and provide aftermarket services and compressor package parts and components manufactured by third-party suppliers. We provide these compression services and equipment to a broad base of natural gas and oil exploration and production, midstream, and transmission 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, and Argentina. We design and fabricate a majority of the compressor packages that we use to provide compression services or sell to customers. Unless the context requires otherwise, when we refer to “the Partnership,” “we,” “us,” and “our,” we are describing CSI Compressco LP and its wholly owned subsidiaries.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our consolidated financial statements include the accounts of our wholly owned subsidiaries. All intercompany balances and transactions have been eliminated.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles ("GAAP") requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclose contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues, expenses, and impairments during the reporting period. Actual results could differ from those estimates, and such differences could be material.

Reclassifications

Certain previously reported financial information has been reclassified to conform to the current year's presentation. The impact of such reclassifications was not significant to the prior year's overall presentation.

Cash Equivalents

We consider all highly liquid cash investments with maturities of three months or less when purchased to be cash equivalents.

Financial Instruments

Financial instruments that subject us to concentrations of credit risk consist principally of trade accounts receivable, which are primarily due from companies of varying size engaged in oil and gas activities in the United States, Canada, Mexico, and Argentina. Our policy is to review the financial condition of customers before extending credit and periodically update customer credit information. Payment terms are on a short-term basis. The risk of loss from the inability to collect trade receivables is heightened during prolonged periods of low oil and natural gas commodity prices.

We have currency exchange rate risk exposure related to transactions denominated in a foreign currency as well as to investments in certain of our international operations. Our risk management activities include the use of foreign currency forward purchase and sale derivative contracts as part of a program designed to mitigate the currency exchange rate risk exposure on selected international operations.

We have a $3.5 million outstanding balance under our variable rate revolving credit facility as of December 31, 2019 and face market risk exposure related to changes in applicable interest rates.

F-7

Significant Customers

During the year ended December 31, 2019, no individual customer accounted for 10% or more of our revenues. During the years ended December 31, 2018 and 2017, two different customers accounted for approximately 15% and 11% of our revenues, respectively.

Foreign Currencies

We have designated the Canadian dollar as the functional currency for our operations in Canada. We are exposed to fluctuations between the U.S. dollar and certain foreign currencies, including the Canadian dollar, the Mexican peso, and the Argentine peso, as a result of our international operations. Foreign currency exchange losses and (gains) are included in other (income) expense, net, and totaled $(2.6) million, $(1.4) million, and $(48,000) during the years ended December 31, 2019, 2018, and 2017, respectively.

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. The remeasurement did not have a material impact on our consolidated financial position or results of operations.

Leases

As a lessee, unless the lease meets the criteria of short-term and is excluded per our policy election described below, we initially recognize a lease liability and related right-of-use asset on the commencement date. The right-of-use asset represents our right to use an underlying asset and the lease liability represents our obligation to make lease payments to the lessor over the lease term.

All of our long-term leases are operating leases and are included in operating lease right-of-use assets, accrued liabilities and other, and operating lease liabilities in our consolidated balance sheet as of December 31, 2019. We determine whether a contract is or contains a lease at inception of the contract. Where we are a lessee in a contract that includes an option to extend or terminate the lease, we include the extension period or exclude the period covered by the termination option in our lease term, if it is reasonably certain that we would exercise the option.

As an accounting policy election, we do not include short-term leases on our balance sheet. Short-term leases include leases with a term of 12 months or less, inclusive of renewal options we are reasonably certain to exercise. The lease payments for short-term leases are included as operating lease costs on a straight-line basis over the lease term in cost of revenues or selling, general, and administrative expense based on the use of the underlying asset. We recognize lease costs for variable lease payments not included in the determination of a lease liability in the period in which an obligation is incurred.

As allowed by U.S. GAAP, we do not separate nonlease components from the associated lease component for our compression services contracts and instead account for those components as a single component based on the accounting treatment of the predominant component. In our evaluation of whether Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 842 "Leases" or ASC 606 "Revenue from Contracts with Customers" is applicable to the combined component based on the predominant component, we determined the services nonlease component is predominant, resulting in the ongoing recognition of our compression services contracts following ASC 606.

Our operating leases are recognized at the present value of lease payments over the lease term. When the implicit discount rate is not readily determinable, we use our incremental borrowing rate to calculate the discount rate used to determine the present value of lease payments. Consistent with other long-lived assets or asset groups that are held and used, we test for impairment of our right-of-use assets when impairment indicators are present.

F-8

Allowance for Doubtful Accounts

The allowance for doubtful accounts is determined on a specific identification basis when we believe that the collection of specific amounts owed to us is not probable. Changes in the allowance are as follows:



	Year Ended December 31,
	2019			2018			2017
	(In Thousands)
At beginning of period	$	1,229		$	822		$	2,253
Activity in the period:
Provision for doubtful accounts	2,459			1,004			968
Account (chargeoffs) recoveries, net	(338		)	(597		)	(2,399		)
At end of period	$	3,350		$	1,229		$	822

Inventories

Inventories consist primarily of compressor package parts and supplies and work in process and are stated at the lower of cost or net realizable value. For parts and supplies, cost is determined using the weighted average cost method. The cost of work in progress is determined using the specific identification method.

Property, Plant, and Equipment

Property, plant, and equipment are stated at cost. Expenditures that increase the useful lives of assets are capitalized. The cost of repairs and maintenance is charged to cost of revenues as incurred. Compressors include compressor packages currently placed in service and available for service. Depreciation is computed using the straight-line method based on the following estimated useful lives:



Buildings	15 – 30 years
Compressors	12 – 20 years
Other equipment	2 – 8 years
Vehicles	3 – 5 years
Information systems	7 years

Leasehold improvements are depreciated over the shorter of the remaining term of the associated building lease or their useful lives. Depreciation expense for the years ended December 31, 2019, 2018, and 2017 was $73.3 million, $67.5 million, and $66.0 million, respectively.

Construction in progress as of December 31, 2019 and 2018 consists primarily of new compressor packages under fabrication and capital expenditures that sustain the capacity of our existing fleet.

Intangible Assets

Trademarks/trade names, customer relationships, and other intangible assets are amortized on a straight-line basis over their estimated useful lives, ranging from 2 to 15 years. Amortization expense related to intangible assets was $3.0 million, $3.0 million, and $3.2 million for the years ended December 31, 2019, 2018, and 2017, respectively, and is included in depreciation and amortization. The estimated future annual amortization expense of trademarks/trade names, customer relationships, and other intangible assets is $2.9 million for 2020, $2.9 million for 2021, $2.9 million for 2022, $2.9 million for 2023, and $2.9 million for 2024.

Our intangible assets are tested for recoverability whenever events or changes in circumstances indicate that the carrying value of the asset may not be recoverable. In such an event, we will determine the fair value of the asset using an undiscounted cash flow analysis of the asset at the lowest level for which identifiable cash flows exist. If an impairment has occurred, we will recognize a loss for the difference between the carrying value and the estimated fair value of the intangible asset.

F-9

Impairments and Other Charges

Impairments of long-lived assets, including identified intangible assets, are determined periodically, when 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 undiscounted operating cash flows to be generated from these assets throughout their remaining estimated useful lives. If these undiscounted cash flows are less than the carrying amount of the related asset, an impairment is recognized for the excess of the carrying value over its fair value. Fair value of intangible assets is generally determined using the discounted present value of future cash flows using discount rates commensurate with the risks inherent with the specific assets. Assets held for disposal are recorded at the lower of carrying value or estimated fair value less estimated selling costs.

During 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. There were 441 GasJack units impaired, representing 20,286 of total horsepower. 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. During 2018 and 2017, we recorded no impairments of long-lived assets.

Revenue Recognition

Performance Obligations. Revenue is recognized when performance obligations under the terms of a contract with our customer are satisfied. Revenue is generally recognized when we transfer control of our products or services to our customers. Revenue is measured as the amount of consideration we expect to receive in exchange for transferring products or providing services to our customers. We receive cash equal to the invoice price for most product sales and services and payment terms typically range from 30 to 60 days from the date we invoice our customer. With the exception of the initial terms of our compression services contracts of our medium- and high-horsepower compressor packages, our customer contracts are generally for terms of one year or less. Since the period between when we deliver products or services and when the customer pays for products or services is not to exceed one year, we have elected not to calculate or disclose a financing component for our customer contracts.

Depending on the terms of the arrangement, we may also defer the recognition of revenue for a portion of the consideration received because we have to satisfy a future performance obligation. For example, consideration received from customers during the fabrication of new compressor packages is typically deferred until control of the compressor package is transferred to our customer.

For revenue associated with mobilization of service equipment as part of a service contract arrangement, such revenue, if significant, is deferred and amortized over the estimated service period.

Compression and related services. For compression services revenues recognized over time, our customer contracts typically provide agreed upon monthly service rates and we recognize service revenue based upon the number of days that services have been performed. The majority of our compression services are provided pursuant to contract terms ranging from one month to twenty-four months. Monthly agreements are generally cancellable with 30 days written notice by the customer.

Sales taxes, value added taxes, and other taxes we collect concurrent with revenue-producing activities are excluded from revenue. We recognize the cost for freight and shipping costs when control over our products (i.e. delivery) has transferred to the customer as part of cost of product sales.

Use of Estimates. Our revenues do not include material amounts of variable consideration, as our revenues typically do not require significant estimates or judgments. The transaction price on a majority of our arrangements are fixed and product returns are immaterial. Additionally, our arrangements typically do not include multiple performance obligations that require estimates of the stand-alone purchase price for each performance obligation. Revenue on certain aftermarket service arrangements that include time as a component of the transaction price is not recognized until the performance obligation is complete.

Contract Assets and Liabilities. We consider contract assets to be trade accounts receivable when we have an unconditional right to consideration and only the passage of time is required before payment is due. In certain

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instances, particularly those requiring customer specific documentation prior to invoicing, our invoicing of the customer is delayed until certain documentation requirements are met. In those cases, we recognize a contract asset rather than a billed trade accounts receivable until we are able to invoice the customer. Contract assets, along with billed trade accounts receivable, are included in trade accounts receivable in our consolidated balance sheets.

We classify contract liabilities as unearned income in our consolidated balance sheets. Such unearned income typically results from advance payments received on orders for new compressor equipment prior to the time such equipment is completed and transferred to the customer in accordance with the customer contract. New equipment sales orders generally take less than twelve months to build and deliver.

Bill-and-Hold Arrangements. We design and fabricate compressor packages based on our customer’s specifications. In some cases, the customer will request us to hold the equipment, upon completion of the unit, until the job site is ready to receive the equipment. When this occurs, we along with the customer sign a bill-and-hold agreement, which outlines that the customer has title to the equipment, the equipment is ready for delivery, we cannot use the equipment or direct it to another customer, and we have a present right to payment. When those criteria have been met and the agreement is executed, we recognize the revenue on the equipment because control of the equipment has passed to our customer and our performance obligations are complete. Entering into these arrangements is something we have done as a courtesy for certain customers for many years. The equipment subject to the bill-and-hold agreements have generally been invoiced and paid for through progressive billings such that at the time the bill-and-hold agreement is executed, the majority of the contractual cash obligation of the customer has been received by us.

Equity-Based Compensation

We have an equity incentive compensation plan which provides for the granting of phantom units and performance phantom units to the executive officers, key employees, nonexecutive officers, and directors of our general partner. Total equity-based compensation expense for the years ended December 31, 2019, 2018, and 2017, was $1.1 million, $0.6 million, and $1.2 million, respectively. For further discussion of equity-based compensation, see Note 9 - Equity-Based Compensation.

Income Taxes

Our operations are not subject to U.S. federal income tax other than the operations that are conducted through taxable subsidiaries. We incur state and local income taxes in certain of the United States in which we conduct business. We incur income taxes and are subject to withholding requirements related to certain of our operations in Latin America, Canada, and other foreign countries in which we operate. Furthermore, we also incur Texas Margin Tax, which, in accordance with Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 740, is classified as an income tax for reporting purposes. A portion of the carrying value of certain deferred tax assets is subject to a valuation allowance. See Note 11 - Income Taxes for further discussion.

In January 2018, the FASB released guidance on the accounting for tax on the global intangible low-taxed income ("GILTI") provisions of the Act. The GILTI provisions impose a tax on foreign income in excess of a deemed return on tangible assets of foreign corporations. The guidance indicates that either accounting for deferred taxes related to GILTI inclusions or to treat any taxes on GILTI inclusions as period costs are both acceptable methods subject to an accounting policy election. As of December 31, 2018, we elected to account for GILTI as a period cost in the year the tax is incurred.

Accumulated Other Comprehensive Income (Loss)

Certain of our international operations maintain their accounting records in the local currencies that are their functional currencies. For these operations, the functional currency financial statements are converted to United States dollar equivalents, with the effect of the foreign currency translation adjustment reflected as a component of accumulated other comprehensive income (loss). Accumulated other comprehensive income (loss) is included in partners' capital in the accompanying audited consolidated balance sheets and consists of the cumulative currency translation adjustments associated with such international operations.

Activity within accumulated other comprehensive income (loss) includes no reclassifications to net income.

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Allocation of Net Income

Our net income (loss) is allocated to partners’ capital accounts in accordance with the provisions of the Partnership Agreement.

Fair Value Measurements

We utilize fair value measurements to account for certain items and account balances within our consolidated financial statements. Fair value measurements were utilized in the determination of the carrying value of our Series A Preferred Units (a Level 3 fair value measurement). We also utilize fair value measurements on a recurring basis in the accounting for our foreign currency forward purchase and sale derivative contracts. For these fair value measurements, we utilize the quoted value (a Level 2 fair value measurement). Refer to Note 10 - "Fair Value Measurements" for further discussion.

Fair value measurements are also utilized on a nonrecurring basis, such as in the allocation of purchase consideration for acquisition transactions to the assets and liabilities acquired, including intangible assets (a Level 3 fair value measurement) and for the impairment of long-lived assets (a Level 3 fair value measurement).

Distributions

On January 22, 2019, April 18, 2019, and July 19, 2019, our General Partner declared a cash distribution attributable to the respective quarter end of $0.01 per common unit. These distributions each equate to a distribution of $0.04 per outstanding common unit on an annualized basis. Also on January 22, 2019, April 18, 2019, and July 19, 2019, our General Partner approved the paid-in-kind distributions of 85,565, 59,953, and 32,872, Preferred Units attributable at the respective quarter ends in accordance with the provisions of our partnership agreement, as amended. These distributions were paid on February 14, 2019, May 15, 2019, and August 14, 2019, respectively, to the holders of common units and the holders of the Preferred Units in the aggregate of record as of the close of business on February 1, 2019, May 1, 2019, and August 1, 2019, respectively.

Series A Preferred Units

The fair value of the Series A Preferred Units were classified as a long-term liability on our consolidated balance sheets in accordance with ASC 480 "Distinguishing Liabilities and Equity," with changes in the fair value resulting in credits or charges to earnings in the accompanying consolidated statements of operations. Unless otherwise redeemed for cash, a ratable portion of the Preferred Units were converted into common units on the eighth day of each month over a period of thirty months that began in March 2017. 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 approximately $1.5 million of redemption premium that was paid and charged to other (income) expense, net in the accompanying consolidated statements of operation. The last redemption of all remaining Preferred Units occurred on August 8, 2019.

New Accounting Pronouncements

Standards adopted

In February 2016, the FASB issued Accounting Standards Update ("ASU") 2016-02, "Leases (Topic 842)" to increase comparability and transparency among different organizations. Organizations are required to recognize right-of-use lease assets and lease liabilities in the balance sheet related to the right to use the underlying asset for the lease term. In addition, through improved disclosure requirements, ASC 842 will enable users of financial statements to further understand the amount, timing, and uncertainty of cash flows arising from leases. We adopted the standard effective January 1, 2019.

We chose to transition using a modified retrospective approach which allows for the recognition of a cumulative effect adjustment to the opening balance of retained earnings in the period of adoption rather than the earliest period presented. Comparative information is reported under the accounting standards that were in effect for those periods. In addition, upon transition, we elected the package of practical expedients, which allows us to continue to apply historical lease classifications to existing contracts. Upon adoption, we recognized $8.3 million in operating right-of-use assets, $3.5 million in accrued liabilities, and $4.8 million in operating lease liabilities. Refer to Note 5 - "Leases" for further information on our leases.

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In February 2018, the FASB issued ASU 2018-02, "Income Statement-Reporting Comprehensive Income (Topic 220)" that gives entities the option to reclassify the income tax effects of the Tax Cuts and Jobs Act from accumulated other comprehensive income to retained earnings. This was effective for us on January 1, 2019, however, as we do not have associated tax effects in accumulated other comprehensive income, there was no impact.

In June 2018, the FASB issued ASU 2018-07, “Compensation-Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting” to align the measurement and classification guidance for share-based payments to nonemployees with the guidance currently applied to employees, with certain exceptions. We adopted this ASU during the three months ended March 31, 2019, with no material impact to our consolidated financial statements.

Standards not yet adopted

In June 2016, the FASB issued ASU 2016-13, "Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments." ASU 2016-13 amends the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology, which will result in the more timely recognition of losses on financial instruments not accounted for at fair value through net income. The provisions require credit impairments to be measured over the contractual life of an asset and developed with consideration for past events, current conditions, and forecasts of future economic information. Credit impairments will be accounted for as an allowance for credit losses deducted from the amortized cost basis at each reporting date. Updates at each reporting date after initial adoption will be recorded through selling, general, and administrative expense. ASU 2016-13 is effective for us the first quarter of fiscal 2023. We continue to assess the potential effects of these changes to our consolidated financial statements.

In August 2018, the FASB issued ASU 2018-15, "Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract." ASU 2018-15 clarifies the accounting for implementation costs in cloud computing arrangements. ASU 2018-15 is effective for us the first quarter of fiscal 2020. We do not expect the adoption of this standard to have a material impact on our consolidated financial statements.

In December 2019, the FASB issued ASU 2019-12, "Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes." ASU 2019-12 simplifies the accounting for income taxes by eliminating certain exceptions related to intraperiod tax allocation, interim period income tax calculation methodology, and the recognition of deferred tax liabilities for outside basis differences. It also simplifies certain aspects of accounting for franchise taxes and clarifies the accounting for transactions that results in a step-up in the tax basis of goodwill. ASU 2019-12 is effective for us the first quarter of fiscal 2021. We continue to assess the potential effects of these changes to our consolidated financial statements.

NOTE 3 — REVENUE FROM CONTRACTS WITH CUSTOMERS

As of December 31, 2019, we had $62.3 million of remaining contractual performance obligations for compression services. As a practical expedient, this amount does not reflect revenue for compression service contracts whose original expected duration is less than twelve months and does not consider the effects of the time value of money. Expected revenue to be recognized in the future as of December 31, 2019 for completion of performance obligations of compression service contracts are as follows:



	2020		2021		2022		2023		2024		Total
	(In Thousands)
Compression service contracts remaining performance obligations	$	48,113	$	12,578	$	1,633	$	—	$	—	$	62,324

Our contract asset balances included in trade accounts receivable in our consolidated balance sheets, primarily associated with customer documentation requirements prior to invoicing, were $9.6 million and $5.9 million as of December 31, 2019 and December 31, 2018, respectively.

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Collections associated with progressive billings to customers for the construction of compression equipment is included in unearned income in the consolidated balance sheets. The following table reflects the changes in unearned income in our consolidated balance sheets for the periods indicated:



	December 31, 2019			December 31, 2018
	(In Thousands)
Unearned income, beginning of period	$	24,898		$	15,526
Additional unearned income	120,050			136,473
Revenue recognized	(135,443		)	(127,101		)
Unearned income, end of period	$	9,505		$	24,898

During the year ended December 31, 2019, we recognized in equipment sales revenue $22.2 million from unearned income that was deferred as of December 31, 2018. During the year ended December 31, 2018, we recognized in equipment sales revenue $14.7 million from unearned income that was deferred as of our adoption of ASC 606 on January 1, 2018.

As of December 31, 2019 and December 31, 2018, contract costs are immaterial.

Disaggregated revenue from contracts with customers by geography is as follows:



	Twelve Months Ended December 31,
	2019		2018		2017
	(In Thousands)
Compression and related services
U.S.	$	223,701	$	197,976	$	178,470
International	34,022		31,919		27,304
	257,723		229,895		205,774
Aftermarket services
U.S.	72,597		67,316		38,345
International	3,693		3,591		1,942
	76,290		70,907		40,287
Equipment sales
U.S.	141,098		135,693		48,496
International	1,470		2,168		1,009
	142,568		137,861		49,505
Total Revenue
U.S.	437,396		400,985		265,311
International	39,185		37,678		30,255
	$	476,581	$	438,663	$	295,566

NOTE 4 — INVENTORIES

Components of inventories, net of reserve, as of December 31, 2019, and December 31, 2018, are as follows:



	December 31, 2019		December 31, 2018
	(In Thousands)
Parts and supplies	$	42,814	$	43,538
Work in progress	13,223		21,684
Total inventories	$	56,037	$	65,222

Inventories consist primarily of compressor package parts and supplies. Work in progress inventories consist primarily of new compressor packages located at our fabrication facility in Midland, Texas.

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NOTE 5 — 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. Our leases generally require us to pay all maintenance and insurance costs. During the fourth quarter of 2019, we entered into a lease agreement commitment for 14 compressor packages that are currently being fabricated. The leases are for a term of seven years and will commence upon the completion of the equipment fabrication, which is expected to occur during the second quarter of 2020. We have no other leases that have not yet commenced that create significant rights and obligations. Our lease agreements do not contain any material residual value guarantees or material restrictive covenants.

In November 2019, we entered into a sale and leaseback transaction with a third-party lessor whereby we received $9.8 million of proceeds from the sale of compression equipment in service and entered into an associated lease of the equipment having an initial lease term of seven years.

Lease costs are included in either cost of revenues or selling, general, and administrative expense depending on the use of the underlying asset. Total lease expense (inclusive of lease expense for leases not included on our consolidated balance sheet based on our accounting policy election to exclude leases with a term of 12 months or less), was $8.2 million for the period ended December 31, 2019, of which, $2.8 million related to short-term leases. Total lease expense was $5.6 million and $5.6 million in 2018 and 2017, respectively. Variable rent expense was not material.

Operating lease supplemental cash flow information:



	Twelve Months Ended December 31, 2019
	(In Thousands)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows - operating leases	$	5,447

Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	16,598

Supplemental balance sheet information:



	December 31, 2019
	(In Thousands)
Operating leases:
Operating right-of-use asset	$	21,006

Accrued liabilities and other	$	6,706
Operating lease liabilities	13,822
Total operating lease liabilities	$	20,528

Additional operating lease information:



	December 31, 2019
Weighted average remaining lease term:
Operating leases	4.51 years

Weighted average discount rate:
Operating leases	8.73	%

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Future minimum lease payments by year and in the aggregate, under non-cancelable operating leases with terms in excess of one year, consist of the following at December 31, 2019:



	Operating Leases
	(In Thousands)
2020	$	7,840
2021	5,791
2022	3,684
2023	1,934
2024	1,934
Thereafter	3,604
Total lease payments	24,787
Less imputed interest	(4,259		)
Total lease liabilities	$	20,528

NOTE 6 — LONG-TERM DEBT AND OTHER BORROWINGS

Long-term debt, net of associated deferred financing costs, consists of the following:



		December 31,
		2019		2018
	Scheduled Maturity	(In Thousands)
Credit Agreement (presented net of the unamortized deferred financing costs of $0.9 million as of December 31, 2019)	June 2023	$	2,622	$	—
7.25% Senior Notes (presented net of the unamortized discount of $1.7 million as of December 31, 2019 and $2.2 million as of December 31, 2018 and unamortized deferred financing costs of $2.8 million as of December 31, 2019 and $3.9 million as of December 31, 2018)	August 2022	291,444		289,797
7.50% Senior Secured Notes (presented net of the unamortized deferred financing costs of $5.8 million as of December 31, 2019 and $6.8 million as of December 31, 2018)	April 2025	344,172		343,216
Total debt		638,238		633,013
Less current portion		—		—
Total long-term debt		$	638,238	$	633,013

There was a $3.5 million balance outstanding and $3.5 million in letters of credit against the Credit Agreement as of December 31, 2019. 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.

Our credit and senior note agreements contain certain affirmative and negative covenants, including covenants that restrict the ability to pay dividends or other restricted payments. We are in compliance with all covenants of our credit and senior note agreements as of December 31, 2019.

Refer to Note 7 - "Related Party Transactions," for a discussion of our amounts payable to affiliates and long-term affiliate payable to TETRA.

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Bank Credit Facility

On March 22, 2018, in connection with the closing of the Offering (as defined below), we repaid all outstanding borrowings and obligations under our then existing bank credit agreement (the "Prior Credit Agreement") with a portion of the net proceeds from the Offering, and terminated this Prior Credit Agreement. As a result of the termination of the Prior Credit Agreement, associated unamortized deferred financing costs of $3.5 million were charged to other (income) expense, net during 2018.

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 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 our and any other borrowers’ accounts receivable. 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.

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, $3.5 million balance was outstanding under the Credit Agreement and $17.2 million was available for borrowings.

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”) (adjusted to reflect any required bank reserves) for an interest period equal to 30, 60, 90, 180, or 360 days (as selected by the Borrowers, subject to availability and with the consent of the Lenders for 360 days) 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 (adjusted to reflect any required bank reserves) for a 30-day interest period on such day plus 1.0% per annum. The applicable margin will range between 1.75% and 2.25% per annum for LIBOR-based loans and 0.75% and 1.25% per annum for base-rate loans, 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 at a 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, the incurrence of debt, the granting of liens, the making of investments, entering into transactions with affiliates, the payment of dividends, and the sale of assets. The Credit Agreement also contains a provision that may require 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 of the foregoing.

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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 December 31, 2019, $295.9 million in aggregate principal amount of the 7.25% Senior Notes were outstanding.

The 7.25% Senior Notes Obligors issued the Securities pursuant to the Indenture dated as of August 4, 2014 (the "7.25% Senior Notes Indenture") by and among the 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. Interest on the 7.25% Senior Notes is payable semi-annually in arrears on February 15 and August 15 of each year. The 7.25% Senior Notes 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 assets; (vi) enter into transactions with affiliates; and (vii) designate our 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.

7.50% Senior Secured Notes

On March 8, 2018, we and CSI Compressco Finance Inc., a Delaware corporation and one of our wholly owned subsidiaries (we, together with CSI Compressco Finance Inc., the “Issuers”), and the guarantors named therein (the “Guarantors” and, together with the Issuers, the "7.50% Senior Secured Notes Obligors"), entered into the Purchase Agreement (the “Purchase Agreement”) with Merrill Lynch, Pierce, Fenner & Smith Incorporated as representative of the initial purchasers listed in Schedule A thereto (collectively, the “Initial Purchasers”), pursuant to which the Issuers agreed to issue and sell to the Initial Purchasers $350.0 million aggregate principal amount of the Issuers’ 7.50% Senior Secured First Lien Notes due 2025 (the “7.50% Senior Secured Notes”) (the "Offering") pursuant to an exemption from the registration requirements of the Securities Act of 1933, as amended (the "Securities Act").

The Offering closed on March 22, 2018. The 7.50% Senior Secured Notes were issued at par for net proceeds of approximately $342.5 million, after deducting certain financing costs. We used a portion of the net proceeds to repay in full and terminate our existing bank Prior Credit Agreement and for general partnership purposes, including the expansion of our compression fleet. The 7.50% Senior Secured Notes are jointly and severally, and fully and unconditionally, guaranteed (the "Guarantees" and, together with the 7.50% Senior Secured Notes, the "Securities") on a senior secured basis initially by each of our domestic restricted subsidiaries (other than CSI Compressco Finance Inc., certain immaterial subsidiaries, and certain other excluded domestic subsidiaries) and are secured by a first-priority security interest in substantially all of the Issuers' and the Guarantors' assets (other than certain excluded assets) (the "Collateral") as collateral security for their obligations under the Securities, subject to certain permitted encumbrances and exceptions. On the closing date, we entered into an indenture (the "7.50% Senior Secured Notes Indenture") by and among the Obligors and U.S. Bank National Association, as trustee with respect to the Securities. The 7.50% Senior Secured Notes accrue interest at a rate of 7.50% per annum. Interest on the 7.50% Senior Secured Notes is payable semi-annually in arrears on April 1 and October 1 of each year. The 7.50% Senior Secured Notes are scheduled to mature on April 1, 2025. In connection with the Offering, we incurred total financing costs of $7.6 million related to the 7.50% Senior Secured Notes. These costs are deferred, netting against the carrying value of the amount outstanding.

On and after April 1, 2021, we may redeem all or a part of the 7.50% Senior Secured Notes, from time to time, at the following redemption prices (expressed as a percentage of principal amount), plus accrued and unpaid interest thereon to, but not including, the applicable redemption date, subject to the right of holders of record on the

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relevant record date to receive interest due on the relevant interest payment date, if redeemed during the 12-month period beginning on April 1 of the years indicated below:




Date	Price
2021	105.625	%
2022	103.750	%
2023	101.875	%
2024	100.000	%

In addition, at any time and from time to time before April 1, 2021, we may, at our option, redeem all or a portion of the 7.50% Senior Secured Notes at a redemption price equal to 100% of the principal amount thereof plus the Applicable Premium (as defined in the 7.50% Senior Secured Notes Indenture) with respect to the 7.50% Senior Secured Notes plus accrued and unpaid interest, if any, to, but not including, the applicable redemption date, subject to the rights of holders of 7.50% Senior Secured Notes on the relevant record date to receive interest due on the relevant interest payment date.

Prior to April 1, 2021, we may on one or more occasions redeem up to 35% of the principal amount of the 7.50% Senior Secured Notes with an amount of cash not greater than the amount of the net cash proceeds from one or more equity offerings at a redemption price equal to 107.500% of the principal amount of the 7.50% Senior Secured Notes to be redeemed, plus accrued and unpaid interest, if any, to, but not including, the date of redemption, subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date, provided that (a) at least 65% of the aggregate principal amount of the 7.50% Senior Secured Notes originally issued on the issue date (excluding notes held by us and our subsidiaries) remains outstanding after each such redemption; and (b) the redemption occurs within 180 days after the date of the closing of the equity offering.

If we experience certain kinds of changes of control, each holder of the 7.50% Senior Secured Notes will be entitled to require us to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess of $2,000) of that holder’s 7.50% Senior Secured Notes pursuant to an offer on the terms set forth in the 7.50% Senior Secured Notes Indenture. We will offer to make a cash payment equal to 101% of the aggregate principal amount of the 7.50% Senior Secured Notes repurchased plus accrued and unpaid interest, if any, on the 7.50% Senior Secured Notes repurchased to the date of repurchase, subject to the rights of holders of the 7.50% Senior Secured Notes on the relevant record date to receive interest due on the relevant interest payment date.

NOTE 7 — RELATED PARTY TRANSACTIONS

Omnibus Agreement

On June 20, 2014, the Partnership, CSI Compressco GP Inc. (the "General Partner"), and TETRA Technologies, Inc. ("TETRA") entered into a First Amendment to Omnibus Agreement (the "First Amendment"). The First Amendment amended the Omnibus Agreement previously entered into on June 20, 2011 (as amended, the

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"Omnibus Agreement") to extend the term thereof. The Omnibus Agreement will terminate on the earlier of (i) a change of control of the General Partner or TETRA, or (ii) upon any party providing at least 180 days' prior written notice of termination.

Under the terms of the Omnibus Agreement, our General Partner provides all personnel and services reasonably necessary to manage our operations and conduct our business (other than in Mexico, Canada, and Argentina), and certain of TETRA’s Latin American-based subsidiaries provide personnel and services necessary for the conduct of certain of our Latin American-based businesses. In addition, under the Omnibus Agreement, TETRA provides certain corporate and general and administrative services as requested by our General Partner, including, without limitation, 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 for services they provide to us. For the years ended December 31, 2019, 2018, and 2017, we were charged by TETRA $36.3 million, $34.8 million, and $37.2 million, respectively, for expenses incurred on our behalf as described below. Amounts charged under the Omnibus Agreement and outstanding as of December 31, 2019 and 2018 are included in amounts payable to affiliates in the accompanying consolidated balance sheets.

In January 2017 and again in May 2017, our General Partner and TETRA agreed that $1.6 million and $1.7 million of amounts payable to affiliates as of December 31, 2016 and March 31, 2017, respectively, that were charged to us by TETRA under the Omnibus Agreement would be paid with common units in lieu of cash, with the number of common units calculated based on the average trading price of our common units over a defined period. These amounts represented certain corporate and general and administrative services for the fourth quarter of 2016 and the first quarter of 2017. Pursuant to these agreement, 159,192 units were issued to TETRA in January 2017 and 280,257 common units were issued to TETRA in June 2017.

Under the terms of the Omnibus Agreement, we or TETRA may, but neither are 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. In addition, we or TETRA may, but are under no obligation to, sell, lease or exchange on a like-kind basis to the other such production enhancement or other oilfield services equipment as is needed or desired to meet either of our production enhancement or other oilfield services obligations, in such amounts, upon such conditions and for such periods of time, if applicable, as may be mutually agreed upon by TETRA and our General Partner. Any such services, sales, leases, or like-kind exchanges 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.

Unless otherwise approved by the conflicts committee of our General Partner’s board of directors, 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.

This description is not a complete discussion of this agreement and is qualified in its entirety by reference to the full text of the complete agreement, which is filed, along with other agreements, as exhibits to our filings with the SEC.

In addition to the Omnibus Agreement, we have entered into other agreements with TETRA in the course of our operations.

TETRA and General Partner Ownership

TETRA's ownership interest in us as of December 31, 2019 and 2018 is approximately 35% and 36%, respectively, with the common units held by the public representing an approximate 65% and 64% interest in us, respectively. As of December 31, 2019, TETRA's ownership is through various wholly owned subsidiaries and consists of approximately 34% of the limited partner interests plus the approximately 1% general partner interest,

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through which it holds incentive distribution rights. As a result of its ownership of common units and its general partner interest in us, TETRA received distributions of $0.7 million, $12.1 million, and $14.2 million during the years ended December 31, 2019, 2018, and 2017, respectively.

Indemnification Agreement

Each of our directors and officers entered into an indemnification agreement with regard to their services as a director or officer, in order to enhance the indemnification rights provided under Delaware law and our Partnership Agreement. The individual indemnification agreements provide each such director or officer with the right to receive his or her costs of defense if he or she is made a party or witness to any proceeding other than a proceeding brought by or in the right of us, provided that such director or officer has not acted in bad faith or engaged in fraud with respect to the action that gave rise to his or her participation in the proceeding.

Other Sources of Financing

In February 2019, we entered into a transaction with TETRA whereby TETRA agreed to fund the construction of and purchase from us up to $15.0 million of new 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 and all compression units were completed and deployed under this agreement. For accounting purposes, the inclusion of a repurchase option that allowed us to repurchase the equipment at a fixed price during certain periods of the agreement caused the transaction to be accounted for as a financing transaction, as opposed to a sale-leaseback, resulting in the funded amount being recorded as a financing obligation. Accordingly, the compressor services equipment is included in property, plant, and equipment and corresponding financing obligations are included in amounts payable to affiliates and long-term affiliate payable in our consolidated balance sheet. As of December 31, 2019, the financing obligation was $15.3 million. Imputed interest expense recognized for the year ended December 31, 2019 was $1.3 million.

The following table summarizes future financing obligation payments by fiscal year:



Year		As of December 31, 2019
		(In Thousands)
2020		3,015
2021		3,015
2022		3,015
2023		3,015
2024		2,312
Total financing obligation payments		14,372

NOTE 8 — COMMITMENTS AND CONTINGENCIES

Insurance Recoveries

During the third quarter of 2017, our insurer paid $3.0 million of claim proceeds associated with damages sustained to certain compression equipment packages that we had impaired as a result of such damage. The amount was credited to earnings, with $2.4 million classified as insurance recoveries for the damaged equipment, and $0.6 million classified as other income.

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NOTE 9 — EQUITY-BASED COMPENSATION

2011 Long Term Incentive Plan

We have granted phantom unit and performance phantom unit awards to certain employees, officers, and directors of our general partner pursuant to the CSI Compressco LP Second Amended and Restated 2011 Long Term Incentive Plan. Awards of phantom units generally vest over a three year period. Awards of performance phantom units cliff vest at the end of a performance period and are settled based on achievement of related performance measures over the performance period. Each of the phantom unit and performance phantom unit awards includes distribution equivalent rights that enable the recipient to receive additional units equal in value to the accumulated cash distributions made on the units subject to the award from the date of grant. Accumulated distributions associated with each underlying unit are payable upon settlement of the related phantom unit award (and are forfeited if the related award is forfeited). Phantom units are notional units that entitle the grantee to receive a common unit upon the vesting of the award.

During the year ended December 31, 2019, we granted to certain officers and employees an aggregate of 1,001,071 phantom unit and performance phantom unit awards, having an average market value (equal to the closing price of the common units on the dates of grant) of $2.71 per unit, or an aggregate market value of $2.7 million. During the year ended December 31, 2018, we granted to certain officers and employees 330,395 phantom and performance phantom unit awards, having an average market value (equal to the closing price of the common units on the dates of grant) of $7.33 per unit, or an aggregate market value of $2.4 million. During the year ended December 31, 2017, we granted to certain officers and employees 290,190 restricted common unit awards, having an average market value (equal to the closing price of the common units on the dates of grant) of $8.40 per unit, or an aggregate market value of $2.4 million. The fair value of awards vesting during 2019, 2018, and 2017 was approximately $1.2 million, $1.5 million, and $2.8 million, respectively. The fair value of awards is amortized straight-line over the vesting period. Adjustments to the amortized expense related to performance phantom units may be recognized prior to vesting depending on the expected achievement of the performance target.

The following is a summary of unit activity for the year ended December 31, 2019:



	Units		Weighted Average Grant Date Fair Value Per Unit
	(In Thousands)
Nonvested units outstanding at December 31, 2018	492		$	7.36
Units granted⁽¹⁾	1,001		2.71
Cancelled/forfeited	(491	)	4.51
Exercised/released	(185	)	6.39
Nonvested units outstanding at December 31, 2019⁽²⁾	817		$	3.59


(1)	This number excludes 290,528 performance-based phantom units, which represents the maximum number of common units that would be issued if the maximum level of performance under the awards is achieved.


(2)	This number excludes an additional 44,314 performance-based phantom units, which, when combined with the 172,237 granted, (net of 2019 forfeitures), represents the maximum number of common units that would be issued if the maximum level of performance under the awards is achieved. The number of units actually issued under the awards may range from zero to 433,102.

Total estimated unrecognized equity-based compensation expense from unvested units as of December 31, 2019, was approximately $1.8 million and is expected to be recognized over a weighted average period of approximately 1.7 years. The amount recognized in 2019, 2018, and 2017 was approximately $1.1 million, $0.6 million, and $1.2 million, respectively, and included in selling, general, and administrative expense.

NOTE 10 — FAIR VALUE MEASUREMENTS

Fair value is defined as “the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date” within an entity’s principal market, if any. The principal market is the market in which the reporting entity would sell the asset or transfer the liability with the greatest volume and level of activity, regardless of whether it is the market in which the entity will ultimately transact for a particular asset or liability or if a different market is potentially more advantageous. Accordingly, this exit price concept may result in a fair value that may differ from the transaction price or market price of the asset or liability.

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Under U.S. GAAP, the fair value hierarchy prioritizes inputs to valuation techniques used to measure fair value. Fair value measurements should maximize the use of observable inputs and minimize the use of unobservable inputs, where possible. Observable inputs are developed based on market data obtained from sources independent of the reporting entity. Unobservable inputs may be needed to measure fair value in situations where there is little or no market activity for the asset or liability at the measurement date and are developed based on the best information available in the circumstances, which could include the reporting entity’s own judgments about the assumptions market participants would utilize in pricing the asset or liability.

Financial Instruments

Series A Preferred Units

All remaining outstanding Preferred Units were redeemed for cash on August 8, 2019. Prior to that, the Preferred Units were valued using a lattice modeling technique that, among a number of lattice structures, included significant unobservable items (a level 3 fair value measurement). These unobservable items included (i) the volatility of the trading price of our common units compared to a volatility analysis of equity prices of comparable peer companies, (ii) a yield analysis that utilized market information related to the debt yields of comparable peer companies, and (iii) a future conversion price analysis. Increases (or decreases) in the fair value of our Preferred Units increased (decreased) the associated liability and resulted in adjustments to earnings for the associated valuation losses (gains).

Derivative Contracts

We have currency exchange rate risk exposure related to transactions denominated in a foreign currency as well as to investments in certain of our international operations. We enter into 30-day foreign currency forward derivative contracts as part of a program designed to mitigate the currency exchange rate risk exposure on selected transactions of certain foreign subsidiaries. As of December 31, 2019 and 2018, we had the following foreign currency derivative contracts outstanding relating to a portion of our foreign operations:



	December 31, 2019
	US Dollar Notional Amount		Traded Exchange Rate	Settlement Date
	(In Thousands)
Forward sale Mexican peso	$	8,656	19.06	1/17/2020



	December 31, 2018
	US Dollar Notional Amount		Traded Exchange Rate	Settlement Date
	(In Thousands)
Forward sale Mexican peso	$	4,783	20.07	1/17/2019

Under a program designed to mitigate the currency exchange rate risk exposure on selected transactions of certain foreign subsidiaries, we may enter into similar derivative contracts from time to time. Although contracts pursuant to this program will serve as economic hedges of the cash flow of our currency exchange risk exposure, they will not be formally designated as hedge contracts or qualify for hedge accounting treatment. Accordingly, any change in the fair value of these derivative instruments during a period will be included in the determination of earnings for that period.

The fair values of our foreign currency derivative instruments are based on quoted market values (a Level 2 fair value measurement). The fair value of our foreign currency derivative instruments as of December 31, 2019 and 2018, are as follows:

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	Balance Sheet	Fair Value at			Fair Value at
Foreign currency derivative instruments	Location	December 31, 2019			December 31, 2018
		(In Thousands)
Forward sale contracts	Current liabilities	(53		)	(98	)
Net asset (liability)		$	(53	)	(98	)

None of the foreign currency derivative contracts contains credit risk related contingent features that would require us to post assets or collateral for contracts that are classified as liabilities. During the year ended December 31, 2019, 2018, and 2017, we recognized approximately $0.8 million, $0.05 million, and $0.04 million of net losses, respectively, associated with our foreign currency derivative program, and such amount is included in other (income) expense, net in the accompanying consolidated statement of operations.

Recurring fair value measurements by valuation hierarchy as of December 31, 2019 and 2018 are as follows:



				Fair Value Measurements Using
Description	Total as of December 31, 2019			Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)	Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(In Thousands)
Liability for foreign currency derivative contracts	(53		)	—	(53	)	—
	$	(53	)



				Fair Value Measurements Using
Description	Total as of December 31, 2018			Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
	(In Thousands)
Series A Preferred Units	$	(30,900	)	$	—	$	—		$	(30,900	)
Liability for foreign currency derivative contracts	(98		)	—		(98		)	—
	$	(30,998	)

The fair values of cash, accounts receivable, accounts payable, accrued liabilities, short-term borrowings, and variable-rate long-term debt pursuant to our Credit Agreement approximate their carrying amounts. The fair values of our publicly traded long-term 7.25% Senior Notes at December 31, 2019 and December 31, 2018, were approximately $266.0 million and $266.3 million, respectively. Those fair values compared to an aggregate principal amount of such notes at December 31, 2019 and 2018 of $295.9 million. The fair values of our long-term 7.50% Senior Secured Notes at December 31, 2019 and December 31, 2018 were approximately $344.8 million and $332.5 million, respectively. These fair values compare to an aggregate principal amount of such notes at December 31, 2019 and December 31, 2018 of $350.0 million. We based the fair values of our 7.25% Senior Notes and our 7.50% Senior Secured Notes as of December 31, 2019 on recent trades for these notes. See Note 6 - "Long-Term Debt and Other Borrowings," for a complete discussion of our debt.

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NOTE 11 — 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. We have a tax sharing agreement with TETRA with respect to the Texas franchise tax liability. The resulting state tax expense is included in the provision for income taxes. Certain of our operations are located outside of the U.S., and the Partnership is responsible for income taxes in these countries.

The income tax provision (benefit) attributable to our operations for the years ended December 31, 2019, 2018, and 2017 consists of the following:



	Year Ended December 31,
	2019			2018			2017
	(In Thousands)
Current
Federal	$	—		$	—		$	(47	)
State	1,455			1,105			688
Foreign	1,769			1,688			1,386
	3,224			2,793			2,027
Deferred
Federal	—			72			—
State	(11		)	(4		)	19
Foreign	140			(246		)	738
	129			(178		)	757
Total tax provision (benefit)	$	3,353		$	2,615		$	2,784

A reconciliation of the provision (benefit) for income taxes, computed by applying the federal statutory rate to income (loss) before income taxes and the reported income taxes, is as follows:



	Year Ended December 31,
	2019			2018			2017
	(In Thousands)
Income (loss) tax provision computed at statutory federal income tax rates	$	(3,700	)	$	(7,216	)	$	(12,809	)
Partnership (earnings) losses	3,700			7,216			12,809
Corporate subsidiary earnings (loss) subject to federal tax	408			745			5,805
Impact of U.S. tax law change	—			—			21,928
Valuation allowances	(51		)	(1,733		)	(28,236		)
Income tax expense attributable to foreign earnings	1,047			1,992			2,565
State income taxes (net of federal benefit)	1,824			1,525			734
Other	125			86			(12		)
Total tax provision (benefit)	$	3,353		$	2,615		$	2,784

Income (loss) before income tax provision includes the following components:



	Year Ended December 31,
	2019			2018			2017
	(In Thousands)
Domestic	$	(26,548	)	$	(37,303	)	$	(40,649	)
International	8,928			2,940			2,974
Total	$	(17,620	)	$	(34,363	)	$	(37,675	)

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We file U.S. federal, state, and foreign income tax returns on behalf of all of our consolidated subsidiaries. With few exceptions, we are not subject to U.S. federal, state, local, or non-U.S. income tax examinations by tax authorities for years prior to 2010. We file tax returns in the U.S. and in various state, local and non-U.S. jurisdictions. The following table summarizes the earliest tax years that remain subject to examination by taxing authorities in any major jurisdiction in which we operate:



Jurisdiction	Earliest Open Tax Period
United States – Federal	2014
United States – State and Local	2014
Non-U.S. jurisdictions	2012

We use the liability method for reporting income taxes, under which current and deferred tax assets and liabilities are recorded in accordance with enacted tax laws and rates. Under this method, at the end of each period, the amounts of deferred tax assets and liabilities are determined using the tax rate expected to be in effect when the taxes are actually paid or recovered. We establish a valuation allowance to reduce the deferred tax assets when it is more likely than not that some portion or all of the deferred tax assets will not be realized. While we consider taxable income in prior carryback years, future reversals of existing taxable temporary differences, future taxable income, and tax planning strategies in assessing the need for the valuation allowance, there can be no guarantee that we will be able to realize all of our deferred tax assets. Significant components of our deferred tax assets and liabilities are as follows:

Deferred Tax Assets



	December 31,
	2019			2018
	(In Thousands)
Amortization for book in excess of tax expense	22,396			25,146
Accruals	3,318			185
Net operating losses	18,164			18,078
Other	2,729			864
Total deferred tax assets	46,607			44,273
Valuation allowance	(37,649		)	(37,704		)
Net deferred tax assets	$	8,958		$	6,569

Deferred Tax Liabilities



	December 31,
	2019		2018
	(In Thousands)
Accruals	$	2,350	$	1,388
Depreciation for tax in excess of book expense	4,677		5,887
Right-of-use Asset	2,892		—
All other	225		293
Total deferred tax liability	10,144		7,568
Net deferred tax liability	$	1,186	$	999

At December 31, 2019, we have federal, state, and foreign net operating loss carryforwards/carrybacks equal to approximately $14.8 million, $1.2 million, and $2.2 million, respectively. In those foreign jurisdictions and states in which net operating losses are subject to an expiration period, our loss carryforwards, if not utilized, will expire from 2020 to 2037. Utilization of the net operating loss and credit carryforwards may be subject to a significant annual limitation due to ownership changes that have occurred previously or could occur in the future provided by Section 382 of the Internal Revenue Code of 1986, as amended.

The valuation allowance during the year ended December 31, 2019 remained constant. The decrease in the valuation allowance during the year ended December 31, 2018 was $1.7 million and the decrease in the

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valuation allowance during the year ended December 31, 2017 was $29.8 million. The change in the valuation allowance during 2018 primarily relates to the reduction of the deferred tax assets as a result of income generated in our U.S. corporate subsidiaries. The change in the valuation allowance during 2017 primarily relates to the decrease in the federal statutory tax rate from 35% to 21%. We believe that it is more likely than not we will not realize all the tax benefits of the deferred tax assets within the allowable carryforward period. Therefore, an appropriate valuation allowance has been provided.

ASC 740 provides guidance on measurement and recognition in accounting for income tax uncertainties and provides related guidance on derecognition, classification, disclosure, interest, and penalties. As of December 31, 2019 and 2018, the Partnership had no material unrecognized tax benefits (as defined in ASC 740-10). We do not expect to incur interest charges or penalties related to our tax positions, but if such charges or penalties are incurred, our policy is to account for interest charges as interest expense and penalties as tax expense in the consolidated statements of operations.

NOTE 12 — EARNINGS PER COMMON UNIT

The computations of earnings per common unit are based on the weighted average number of common units outstanding during the applicable full-year period. Basic earnings per common unit is determined by dividing net income (loss) allocated to the common units after deducting the amount allocated to our General Partner (including distributions to our General Partner on its incentive distribution rights), by the weighted average number of outstanding common units during the period.

When computing earnings per common unit under the two-class method in periods when distributions are greater than earnings, the amount of the distributions is deducted from net income (loss) and the excess of distributions over earnings is allocated between the General Partner and common units based on how our partnership agreement allocates net losses.

When earnings are greater than distributions, we determine cash distributions based on available cash and determine the actual incentive distributions allocable to our General Partner based on actual distributions. When computing earnings per common unit, the amount of the assumed incentive distribution rights, if any, is deducted from net income and allocated to our General Partner for the period to which the calculation relates. The remaining amount of net income, after deducting the assumed incentive distribution rights, is allocated between the General Partner and common units based on how our Partnership Agreement allocates net earnings.

The following is a reconciliation of the weighted average number of common units outstanding to the number of common units used in the computations of net income per common unit.



	Year Ended December 31,
	2019	2018	2017
	Common Units	Common Units	Common Units
Number of weighted average units outstanding	47,006,543	41,552,804	35,035,428
Unit awards outstanding	—	—	—
Average diluted units outstanding	47,006,543	41,552,804	35,035,428

Diluted earnings per unit are computed using the treasury stock method, which considers the potential future issuance of limited partner common units. Unvested phantom units are not included in basic earnings per common unit, as they are not considered to be participating securities, but are included in the calculation of diluted earnings per common unit. As of December 31, 2019, 2018, and 2017 approximately 131,576, 29,276, and 90,594 incremental units, respectively, were excluded from the calculation of diluted units because the impact was anti-dilutive. Following the issuance of the Preferred Units, diluted earnings per common unit was computed using the "if converted" method, whereby the amount of net income (loss) and the number of common units issuable are each adjusted as if the Preferred Units had been converted as of the date of issuance or as of the beginning of the period. The number of common units that may be issued upon future conversion of the Preferred Units was excluded from the calculation of diluted common units, as the impact would be antidilutive due to the net loss recorded during the years ended December 31, 2019, 2018, and 2017. All remaining outstanding Preferred Units were redeemed for cash on August 8, 2019.

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NOTE 13 — SEGMENTS

ASC 280, "Segment Reporting”, defines the characteristics of an operating segment as (i) being engaged in business activity from which it may earn revenues and incur expenses, (ii) being reviewed by the company's chief operating decision maker ("CODM") to make decisions about resources to be allocated and to assess its performance, and (iii) having discrete financial information. Although management of our General Partner reviews our products and services to analyze the nature of our revenue, other financial information, such as certain costs and expenses, and net income are not captured or analyzed by these items. Therefore, discrete financial information is not available by product line and our CODM does not make resource allocation decisions or assess the performance of the business based on these items, but rather in the aggregate. Based on this, our General Partner believes that we operate in one business segment.

NOTE 14 — GEOGRAPHIC INFORMATION

We are domiciled in the United States of America, with operations in Latin America, Canada, and to a lesser extent, in other countries located in Europe and the Asia-Pacific region. We attribute revenue to the countries based on the location of customers. Long-lived assets consist primarily of compressor packages and are attributed to the countries based on the physical location of the compressor packages at a given year-end. Information by geographic area is as follows:



	Year Ended December 31,
	2019		2018		2017
	(In Thousands)
Revenues from external customers:
U.S.	$	437,396	$	400,986	$	265,311
Latin America	30,724		27,889		23,493
Canada	4,430		4,365		3,678
Other	4,031		5,423		3,084
Total	$	476,581	$	438,663	$	295,566
Identifiable assets:
U.S.	$	761,177	$	773,476	$	691,588
Latin America	55,498		47,891		45,170
Canada	4,732		4,156		4,278
Other	1,427		1,221		1,896
Total identifiable assets	$	822,834	$	826,744	$	742,932

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NOTE 15 — SUPPLEMENTAL GUARANTOR FINANCIAL INFORMATION

The $295.9 million and $350.0 million in aggregate principal amounts outstanding of the 7.25% Senior Notes and 7.50% Senior Secured Notes, respectively, as of December 31, 2019 are fully and unconditionally guaranteed, subject to certain customary release provisions, on a joint and several senior unsecured and secured basis, by the following domestic 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 condensed consolidating financial information pursuant to Rule 3-10 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 7.25% Senior Notes or the 7.50% Senior Secured 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.

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Condensed Consolidating Balance Sheet

December 31, 2019

(In Thousands)



	Issuers		Guarantor Subsidiaries		Other Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets	$	—	$	97,360	$	29,933	$	—		$	127,293
Property, plant, and equipment, net	—		611,778		30,589		—			642,367
Investments in subsidiaries	180,033		27,287		—		(207,320		)	—
Operating lease right-of-use assets	—		20,577		429		—			21,006
Intangible and other assets, net	—		28,334		3,246		—			31,580
Intercompany receivables	519,182		—		—		(519,182		)	—
Total non-current assets	699,215		687,976		34,264		(726,502		)	694,953
Total assets	$	699,215	$	785,336	$	64,197	$	(726,502	)	$	822,246

LIABILITIES AND PARTNERS' CAPITAL
Other current liabilities	$	14,607	$	80,595	$	4,721	$	—		$	99,923
Amounts payable to affiliate	—		5,096		2,608		—			7,704
Long-term debt	635,617		2,621		—		—			638,238
Operating lease liabilities	—		13,509		313		—			13,822
Intercompany payables	—		490,807		28,375		(519,182		)	—
Long-term affiliate payable and other liabilities	—		12,675		893		—			13,568
Total liabilities	650,224		605,303		36,910		(519,182		)	773,255
Total partners' capital	48,991		180,033		27,287		(207,320		)	48,991
Total liabilities and partners' capital	$	699,215	$	785,336	$	64,197	$	(726,502	)	$	822,246

Condensed Consolidating Balance Sheet

December 31, 2018

(In Thousands)



	Issuers		Guarantor Subsidiaries		Other Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets	$	—	$	128,084	$	23,663	$	—		$	151,747
Property, plant, and equipment, net	—		614,982		26,337		—			641,319
Investments in subsidiaries	146,852		21,330		—		(168,182		)	—
Intangible and other assets, net	—		31,874		1,804		—			33,678
Intercompany receivables	599,145		—		—		(599,145		)	—
Total non-current assets	745,997		668,186		28,141		(767,327		)	674,997
Total assets	$	745,997	$	796,270	$	51,804	$	(767,327	)	$	826,744

LIABILITIES AND PARTNERS' CAPITAL
Current liabilities	$	14,681	$	72,985	$	3,170	$	—		$	90,836
Amounts payable to affiliate	—		—		3,517		—			3,517
Long-term debt	633,013		—		—		—			633,013
Series A Preferred Units	30,900		—		—		—			30,900
Intercompany payables	—		576,242		22,903		(599,145		)	—
Other long-term liabilities	—		191		884		—			1,075
Total liabilities	678,594		649,418		30,474		(599,145		)	759,341
Total partners' capital	67,403		146,852		21,330		(168,182		)	67,403
Total liabilities and partners' capital	$	745,997	$	796,270	$	51,804	$	(767,327	)	$	826,744

F-30

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)

December 31, 2019

(In Thousands)



	Issuers			Guarantor Subsidiaries			Other Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	451,064		$	35,153		$	(9,636	)	$	476,581
Cost of revenues (excluding depreciation and amortization expense)	—			303,205			23,930			(9,636		)	317,499
Depreciation and amortization	—			72,523			4,140			—			76,663
Impairment and other charges	—			3,160			—			—			3,160
Insurance recoveries	—			(555		)	—			—			(555		)
Selling, general, and administrative expense	1,062			39,874			2,164			—			43,100
Interest expense, net	51,550			1,825			—			—			53,375
Series A Preferred FV Adjustment expense	1,470			—			—			—			1,470
Other expense, net	1,468			427			(2,406		)	—			(511		)
Equity in net (income) loss of subsidiaries	(34,577		)	(5,844		)	—			40,421			—
Income (loss) before income tax provision	(20,973		)	36,449			7,325			(40,421		)	(17,620		)
Provision for income taxes	—			1,872			1,481			—			3,353
Net income (loss)	(20,973		)	34,577			5,844			(40,421		)	(20,973		)
Other comprehensive income (loss)	513			513			—			(513		)	513
Comprehensive income (loss)	$	(20,460	)	$	35,090		$	5,844		$	(40,934	)	$	(20,460	)

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)

December 31, 2018

(In Thousands)



	Issuers			Guarantor Subsidiaries			Other Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	416,846		$	32,594		$	(10,777	)	$	438,663
Cost of revenues (excluding depreciation and amortization expense)	—			297,295			21,879			(10,777		)	308,397
Depreciation and amortization	—			67,003			3,497			—			70,500
Impairments and other charges	—			681			—			—			681
Selling, general, and administrative expense	639			36,810			2,151			—			39,600
Interest expense, net	49,512			3,073			—			—			52,585
Series A Preferred FV Adjustment	(838		)	—			—			—			(838		)
Other expense, net	—			3,989			(1,888		)	—			2,101
Equity in net (income) loss of subsidiaries	(12,335		)	(5,781		)	—			18,116			—
Income (loss) before income tax provision	(36,978		)	13,776			6,955			(18,116		)	(34,363		)
Provision for income taxes	—			1,441			1,174			—			2,615
Net income (loss)	(36,978		)	12,335			5,781			(18,116		)	(36,978		)
Other comprehensive income (loss)	(3,597		)	(3,597		)	—			3,597			(3,597		)
Comprehensive income (loss)	$	(40,575	)	$	8,738		$	5,781		$	(14,519	)	$	(40,575	)

F-31

Condensed Consolidating Statement of Operations and Comprehensive Income (Loss)

December 31, 2017

(In Thousands)



	Issuers			Guarantor Subsidiaries			Other Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	273,649		$	28,175		$	(6,258	)	$	295,566
Cost of revenues (excluding depreciation and amortization expense)	—			181,121			18,635			(6,258		)	193,498
Depreciation and amortization	—			65,920			3,220			—			69,140
Insurance recoveries	—			(2,352		)	—			—			(2,352		)
Selling, general, and administrative expense	1,314			30,504			1,620			—			33,438
Interest expense, net	31,402			11,733			—			—			43,135
Series A Preferred FV Adjustment	(3,402		)	—			—			—			(3,402		)
Other expense, net	—			2,147			(2,363		)	—			(216		)
Equity in net (income) loss of subsidiaries	11,145			(5,112		)	—			(6,033		)	—
Income (loss) before income tax provision	(40,459		)	(10,312		)	7,063			6,033			(37,675		)
Provision for income taxes	—			833			1,951			—			2,784
Net income (loss)	(40,459		)	(11,145		)	5,112			6,033			(40,459		)
Other comprehensive income (loss)	(1,078		)	(1,078		)	—			1,078			(1,078		)
Comprehensive income (loss)	$	(41,537	)	$	(12,223	)	$	5,112		$	7,111		$	(41,537	)

F-32

Condensed Consolidating Statement of Cash Flows

December 31, 2019

(In Thousands)



	Issuers			Guarantor Subsidiaries			Other Subsidiaries			Eliminations		Consolidated
Net cash provided by operating activities	$	—		$	62,842		$	4,854		$	—	$	67,696
Investing activities:
Purchases of property, plant, and equipment, net	—			(71,534		)	(4,264		)	—		(75,798		)
Proceeds from sale of property, plant, and equipment, net	—			11,025			—			—		11,025
Insurance recoveries associated with damaged equipment	—			555			—			—		555
Net cash used in investing activities	—			(59,954		)	(4,264		)	—		(64,218		)
Financing activities:
Proceeds from long-term debt	—			45,000			—			—		45,000
Payments of long-term debt	—			(41,567		)	—			—		(41,567		)
Cash redemptions of Preferred Units	(31,913		)				—			—		(31,913		)
Distributions	(1,907		)	—			—			—		(1,907		)
Intercompany contribution (distribution)	35,185			(35,185		)	—			—		—
Advances from affiliate	—			14,782			—			—		14,782
Other financing activities	(1,365		)	—			—			—		(1,365		)
Net cash used in financing activities	—			(16,970		)	—			—		(16,970		)
Effect of exchange rate changes on cash	—			—			4			—		4
Increase (decrease) in cash and cash equivalents	—			(14,082		)	594			—		(13,488		)
Cash and cash equivalents at beginning of period	—			14,148			1,710			—		15,858
Cash and cash equivalents at end of period	$	—		$	66		$	2,304		$	—	$	2,370

F-33

Condensed Consolidating Statement of Cash Flows

December 31, 2018

(In Thousands)



	Issuers			Guarantor Subsidiaries			Other Subsidiaries			Eliminations		Consolidated
Net cash provided by operating activities	$	—		$	26,753		$	3,368		$	—	$	30,121
Investing activities:
Purchases of property, plant, and equipment, net	—			(99,020		)	(4,981		)	—		(104,001		)
Proceeds from sale of property, plant, and equipment, net	—			512			—			—		512
Advances and other investing activities	—			(1		)	—			—		(1		)
Net cash used in investing activities	—			(98,509		)	(4,981		)	—		(103,490		)
Financing activities:
Proceeds from long-term debt	343,800			36,200			—			—		380,000
Payments of long-term debt	—			(258,000		)	—			—		(258,000		)
Distributions	(31,294		)	—			—			—		(31,294		)
Intercompany contribution (distribution)	(303,507		)	303,507			—			—		—
Financing costs and other	(8,999		)	—			—			—		(8,999		)
Net cash provided by financing activities	—			81,707			—			—		81,707
Effect of exchange rate changes on cash	—			—			(81		)	—		(81		)
Increase (decrease) in cash and cash equivalents	—			9,951			(1,694		)	—		8,257
Cash and cash equivalents at beginning of period	—			4,197			3,404			—		7,601
Cash and cash equivalents at end of period	$	—		$	14,148		$	1,710		$	—	$	15,858

F-34

Condensed Consolidating Statement of Cash Flows

December 31, 2017

(In Thousands)



	Issuers			Guarantor Subsidiaries			Other Subsidiaries			Eliminations		Consolidated
Net cash provided by (used in) operating activities	$	—		$	44,456		$	(5,388	)	$	—	$	39,068
Investing activities:
Purchases of property, plant, and equipment, net	—			(28,326		)	373			—		(27,953		)
Proceeds from sale of property, plant, and equipment, net	—			2,827								2,827
Insurance recoveries associated with damaged equipment	—			2,352			—			—		2,352
Advances and other investing activities				21			—					21
Net cash provided by (used in) investing activities	—			(23,126		)	373			—		(22,753		)
Financing activities:
Proceeds from long-term debt	—			80,900			—			—		80,900
Payments of long-term debt	—			(74,900		)	—			—		(74,900		)
Distributions	(33,068		)	—			—			—		(33,068		)
Intercompany contribution (distribution)	33,187			(33,187		)	—			—		—
Financing costs and other	(119		)	(2,147		)	—			—		(2,266		)
Net cash used in financing activities	—			(29,334		)	—			—		(29,334		)
Effect of exchange rate changes on cash	—			—			(177		)	—		(177		)
Increase (decrease) in cash and cash equivalents	—			(8,004		)	(5,192		)	—		(13,196		)
Cash and cash equivalents at beginning of period	—			12,201			8,596			—		20,797
Cash and cash equivalents at end of period	$	—		$	4,197		$	3,404		$	—	$	7,601

NOTE 16 — SUBSEQUENT EVENTS

On January 20, 2020, the board of directors of 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 distribution was paid on February 14, 2020, to the holders of common units of record as of the close of business February 1, 2020.

F-35