UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON D.C. 20549

FORM 10-K

(MARK ONE)

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

FOR THE FISCAL YEAR ENDEDDECEMBER 31, 2017

OR

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

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	(I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION)	IDENTIFICATION NO.)
24955 INTERSTATE 45 NORTH
THE WOODLANDS, TEXAS	77380
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)	(ZIP CODE)
REGISTRANT’S TELEPHONE NUMBER, INCLUDING AREA CODE: (281) 364-2244

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THEACT:
COMMON UNITS REPRESENTING LIMITED PARTNERSHIP INTERESTS	NASDAQ GLOBAL MARKET
(TITLE OF CLASS)	(NAME OF EXCHANGE ON WHICH REGISTERED)
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE

INDICATE BY CHECK MARK IF THE REGISTRANT IS A WELL-KNOWN SEASONED ISSUER (AS DEFINED IN RULE 405 OF THE SECURITIES ACT).

YES [  ]   NO [ X ]

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 [ X ]

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 [ X ]   NO [   ]

INDICATE BY CHECK MARK WHETHER THE REGISTRANT HAS SUBMITTED ELECTRONICALLY AND POSTED ON ITS CORPORATE WEB SITE, IF ANY, EVERY INTERACTIVE DATA FILE REQUIRED TO BE SUBMITTED AND POSTED PURSUANT TO RULE 405 OF REGULATION S-T DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS REQUIRED TO SUBMIT AND POST SUCH FILES).

YES  [ X ]    NO [   ]

INDICATE BY CHECK MARK IF DISCLOSURE OF DELINQUENT FILERS PURSUANT TO ITEM 405 OF REGULATION S-K IS NOT CONTAINED HEREIN, AND WILL NOT BE CONTAINED, TO THE BEST OF REGISTRANT’S KNOWLEDGE, IN DEFINITIVE PROXY OR INFORMATION STATEMENTS INCORPORATED BY REFERENCE IN PART III OF THIS FORM 10-K OR ANY AMENDMENT TO THIS FORM 10-K. [  ]

INDICATE BY CHECK MARK WHETHER THE REGISTRANT IS A LARGE ACCELERATED FILER, AN ACCELERATED FILER, A NON-ACCELERATED FILER, OR 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. (CHECK ONE):

LARGE ACCELERATED FILER [  ]	ACCELERATED FILER [ X ]	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 EXCHANGE ACT).

YES [   ]  NO [ X ] 

THE AGGREGATE MARKET VALUE OF COMMON UNITS HELD BY NON-AFFILIATES OF THE REGISTRANT WAS $98,683,993 AS OF JUNE 30, 2017, THE LAST BUSINESS DAY OF THE REGISTRANT’S MOST RECENTLY COMPLETED SECOND FISCAL QUARTER.

THE NUMBER OF COMMON UNITS OUTSTANDING AS OF February 28, 2018 WAS 37,618,734 UNITS.

DOCUMENTS INCORPORATED BY REFERENCE- NONE

TABLE OF CONTENTS

	Part I
Item 1.	Business	1
Item 1A.	Risk Factors	9
Item 1B.	Unresolved Staff Comments	31
Item 2.	Properties	31
Item 3.	Legal Proceedings	31
Item 4.	Mine Safety Disclosures	31
	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	32
Item 6.	Selected Financial Data	33
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operation	34
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	52
Item 8.	Financial Statements and Supplementary Data	54
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	54
Item 9A.	Controls and Procedures	54
Item 9B.	Other Information	54
	Part III
Item 10.	Directors, Executive Officers, and Corporate Governance	55
Item 11.	Executive Compensation	60
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	80
Item 13.	Certain Relationships and Related Transactions, and Director Independence	82
Item 14.	Principal Accounting Fees and Services	84
	Part IV
Item 15.	Exhibits, Financial Statement Schedules	85
Item 16.	Form 10-K Summary	90

(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 supply, demand, and prices of crude oil and natural gas;

• our ability to continue to make cash distributions at the current quarterly rate after the establishment of reserves, payment of debt service and other contractual obligations;

• our ability to comply with the financial covenants in our credit agreement and the indenture for our senior notes and the consequences of any failure to comply with such financial covenants;

• our existing debt levels and our flexibility to obtain additional financing;

• 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;

• the availability of adequate sources of capital to us;

• our operational performance;

• risks related to our foreign operations;

• information technology risks including the risk from cyberattack;

• 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 (formerly named Compressco Partners, L.P.) 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 are a Delaware limited partnership formed in October 2008. Our corporate headquarters are located at 24955 Interstate 45 North, The Woodlands, Texas, 77380. Our phone number is 281-364-2244, and our website is accessed at www.csicompressco.com. Our common units are traded on the NASDAQ Exchange under the symbol “CCLP.”

Our Corporate Governance Guidelines, Code of Conduct, Financial Code of Ethics, and Audit Committee Charter, as well as our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports are all available, free of charge, on our website at www.csicompressco.com as soon as practicable after we file the reports with the SEC. Information contained on or connected to our website is not, and shall not be deemed to be, a part of this Annual Report on Form 10-K or incorporated into any other filings with the SEC. The documents referenced above are available in print at no cost to any unitholder who requests them from our Corporate Secretary.

About CSI Compressco LP

We are a provider of compression services and equipment for natural gas and oil production, gathering, transportation, processing, and storage. We sell standard and custom-designed compressor packages and oilfield fluid pump systems, 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 foreign countries, including Mexico, Canada, and Argentina. We design and fabricate a majority of the compressor packages that we use to provide compression services and that we sell to customers.

We are one of the largest service providers of natural gas compression services in the United States, utilizing our fleet of compressor packages that employs a full spectrum of low-, medium-, and high-horsepower engines. Low-horsepower compressor packages enhance production for dry gas wells and liquid-loaded gas wells by deliquifying wells, lowering wellhead pressure, and increasing gas velocity. Our low-horsepower compressor packages are also utilized in connection with oil and liquids production and in vapor recovery and casing gas system applications. Low- to medium-horsepower compressor packages are typically utilized in wellhead and natural gas gathering systems and other applications primarily in connection with natural gas and oil production. Our high-horsepower compressor package offerings are typically utilized in natural gas production, natural gas gathering, centralized compression facilities, and midstream applications.

Our equipment sales business includes the fabrication and sale of standard compressor packages, custom-designed compressor packages, and oilfield fluid pump systems designed and fabricated primarily at our facility in Midland, Texas. We design and fabricate natural gas reciprocating and rotary screw compressor packages up to 8,000 horsepower for sale to our customers. 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 pump systems can be utilized in multiple applications including oil and liquids production, transfer, and pipeline transmission, as well as water injection and disposal and other systems.

Our aftermarket business provides a wide range of services to support the needs of customers who own compression equipment as well as the sale of compressor package parts and components manufactured by third-party suppliers. 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.

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Our long-term growth strategy includes expanding our existing businesses - through internal growth and acquisitions - both in the U.S. and in select foreign countries.

Our operations are organized into a single business segment. See "Note L - 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 M – 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. and Compressor Systems, Inc. ("CSI"), which are also wholly owned subsidiaries of ours, conduct 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 indirect and direct 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, 2017, common units held by the public represent approximately a 60% ownership interest in us.

Products and Services

We are a provider of compression services and equipment for natural gas and oil production, gathering, 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 wellhead, (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 standard compressor packages, custom-designed compressor packages, and oilfield fluid pump systems. We also provide aftermarket compression services and sell compressor package parts and components manufactured by third-party suppliers.

Compression Services

We utilize our fleet of compressor packages to provide a variety of compression services to our customers to meet their specific requirements. Our fleet includes approximately 5,800 compressor packages that provide approximately 1.1 million in aggregate horsepower, employing a wide spectrum of low-, medium-, and high-horsepower engines. We fabricate our compressor packages primarily at our fabrication facility in Midland, Texas. The horsepower of our natural gas compressor package fleet as of December 31, 2017 is summarized in the following table:

Range of Horsepower Per Package	Number of Packages	Aggregate Horsepower	% of Aggregate Horsepower
0 - 100	3,842	180,156	16.7	%
101 - 800	1,590	444,520	41.1	%
Over 800	341	457,243	42.3	%
Total	5,773	1,081,919	100.0	%

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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-horsepowerpackages 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 (101-800 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 800 horsepower and equipped with interstage cooling.

High-Horsepower (Over 800 Horsepower) Compression Services. Our high-horsepower compressor packages are primarily utilized in midstream applications including natural gas gathering and centralized compression facilities. They move natural gas from individual wells or a group of wells to boost the pressure while being moved 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 movement of natural gas from gathering systems to storage facilities or the end user. These compressor packages feature primarily two- and three-stage compressors powered by natural gas engines over 800 horsepower and equipped with interstage cooling.

Other Related Services.In certain Latin America markets, we provide well monitoring and sand separation services in connection with our primary low-horsepower 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 will 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 can also range from six months to twenty-four month initial terms as well. After the initial terms on our medium and high horsepower compression service contracts, typically customers will 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. A portion of our compression service business is not conducted under service contracts, but rather are rental contracts that are similar in substance to our service contracts.

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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, we remotely monitor, in real time, on most equipment, whether our services are being continuously provided at 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.

We also fabricate and sell oilfield fluid pump systems through our wholly owned Pump Systems International, Inc. (“PSI”) subsidiary. The pump systems are fabricated at our facility in Midland, Texas or by third-party fabricators and they are sold primarily in South American, Asian and Middle Eastern markets.

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, engineer, and fabricate a wide spectrum of natural gas reciprocating and rotary screw compressor packages up to 8,000 horsepower, including both standard field compression equipment meeting industry standards and specialty 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 and 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 and market high-quality gas compressor packages that have a superior reputation in the industry as indicated 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 and pump systems are obtained from third-party suppliers. These components represent a significant portion of the cost of the compressor packages and pump systems. Some of the components used in the assembly of our compressor packages and pump systems 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, natural gas and oil in the various domestic and international markets in which we operate. Beginning in 2014 and continuing throughout most of 2016, reduced prices of natural gas and oil led to declines in our customers' capital expenditure levels in the domestic and international markets in which we operate. The decline in activity in the natural gas and oil exploration and production industry resulted in reduced demand for our products and services compared to early

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2014 levels. With the increase in oil and gas pricing that began in the second half of 2016 and has continued in 2017 and early 2018, we are seeing strong indicators of improving demand for our products and services.

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 foreign regions. While most of our domestic services are performed throughout Texas, the San Juan Basin, the Rocky Mountain region, and the Mid-Continent region of the United States, we also have a presence in other U.S. producing regions. We continue to seek opportunities to further expand our operations into other regions in the U.S. and elsewhere in the world.

 Our service contracts are generally terminable uponthirtydays’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 most significant customer for the year ended December 31, 2017 was ConocoPhillips, which accounted for approximately 11% of our consolidated revenues for the year. Other major customers include, BP America, PDC Energy, Cimarex Energy, Southwestern Energy, Anadarko, XTO Energy, and Targa Resources, none of which individually accounted for more than 10% of our consolidated revenues for the year ended December 31, 2017. The loss of any of these 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 adopt more aggressive pricing policies. Primarycompetition 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 on providing production enhancement value to the customer. Competition for our mid- and high-horsepower compression services business comes primarily from large national and multinational companies that may have greater financial resources than ours. Such competitors include ArchRock, AXIP Energy Services, CDM Resource Management, Exterran, J-W Power, 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 who we compete with for compression services, as well as AG Equipment Company, Enerflex, SEC Energy Products & Services, and others. Our competition in the custom-designed market usually 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 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 increases in the value that resultsfrom 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 utilize various marketing strategies to promote our services and compressor package and pump system 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 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.

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Backlog

Our equipment and parts sales business consists of the fabrication and sale of standard compressor packages, custom-designed compressor packages, and pump systems. Our custom-designed packages are typically greater in size and complexity 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, 2017, our equipment sales backlog was $47.5 million, compared to $21.6 million as of December 31, 2016, most of which is expected to be recognized in the year ended December 31, 2018, based on title passing to the customer, the customer assuming the risks of ownership, reasonable assurance of collectability, and delivery occurring as directed by our customer. In addition, subsequent to December 31, 2017, we received an order from a single customer for approximately $66.7 million of new compressor equipment, the largest single order in our history, and as a result our new equipment sales backlog has increased to approximately $116.8 million. This backlog consists of firm customer orders for which a purchase or work order has been received, satisfactory credit or financing arrangements exist, and delivery has been scheduled. This 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.

Employees

As of December 31, 2017,our general partner and certain of our subsidiarieshadapproximately 635 full-timeemployeeswho provideservices 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 a collective bargaining agreement. The employees of TETRA who provide services to us in Argentina and Mexico are subject to numerous collective labor 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 and in the development and handling of certain products and equipment produced or used at our plants, well locations, and worksites. Because of these risks, there can be no assurance that significant costs and liabilities will not be incurred in the future. Changes in environmental and health and safety regulations could subject us to more rigorous standards. We cannot predict the extent to which our operations may be affected by future regulatory 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 and comparable state laws, and regulations thereunder, which regulate air emissions;

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• 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 also 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 Clean Air Act 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. 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. 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. We are not currently aware of material impacts to our operations associated with these rules.

The EPA has determined that greenhouse gases 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 greenhouse gases, 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 greenhouse gas emissions from certain sources includingonshore and offshore oil and natural gas production facilities and onshore oil and gas processing, transmission, storage, and distribution facilities. Reporting of greenhouse gas emissions from such facilities is required on an annual basis. The EPA’s rules relating to emissions of greenhouse gases from large stationary sources of emissions are currently subject to a number of legal challenges, but the federal courts have thus far declined to issue any injunctions to prevent the EPA or state environmental agencies from implementing the rules. Further, Congress has considered, and almost one-half of the states have adopted, legislation that seeks to control or reduce emissions of greenhouse gases 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 necessary.

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, and 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.

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We believe that we have properly disposed of all historical waste streams and 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.

Our compressor packages may be subject to additional regulatory requirements under the Clean Air Act. For example, regulations under the National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) provisions of the Clean Air Act 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 New Source Performance Standards and NESHAPS for natural gas and natural gas liquids production, processing and transportation activities. These rules establish specific requirements associated with emissions from compressors and controllers at natural gas gathering and boosting stations.

We design and fabricate 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 the environment, health and safety, 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. 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

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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 any 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.

Wedepend on domesticand international demandfor and production of natural gas and oil, 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, natural gas and oil in the various domestic and international markets in which we operate. Natural gas and oil production may be affected by, among other factors, prices for such commodities, weather, and availability of alternative energy sources.

The reduction in natural gas and oil prices that began in 2014 and continued through 2015 and 2016 resulted in declining demand for certain of our products and services compared to 2014 levels, which reduced our cash available for distribution. In April 2017, our general partner announced a reduction of approximately 50% in the level of cash distributions on our common units beginning with the quarter ended March 31, 2017. U.S. natural gas prices during 2017 have been fairly consistent, as Henry Hub prices hovered close to $3.00 per million British thermal units ("MMBtu") during most of the year. However, during 2017 prices were much more volatile, including the lowest in nearly 20 years, with Henry Hub prices ranging from a low of $1.49 per million British thermal units (“MMBtu”) in March 2016 to a high of $3.80 per MMBtu in December 2016. The Henry Hub price for natural gas as of February 26, 2018 was $2.44 per MMBtu. Although crude oil prices were also volatile early in 2016, with West Texas Intermediate oil prices ranging from a nearly 13-year low of $26.19 per barrel in February 2016 to a high of $54.01 per barrel in December 2016, prices steadily increased to their strongest level in over two years during 2017 and early 2018. As a result, the sector is regaining a sense of optimism, however if oil and natural gasprices in 2018 decline, this may further negatively affect the operating cash flows andexploration and developmentactivities andplans of many of our customersand continue to have a negative impact onthe demand for our compression products and services.

We may not have sufficient cash from operations following the establishment of cash reserves and payment ofdebt service and other contractual obligations, fees and expenses, including cost reimbursements to our general partner, to enable us to make cash distributions to our common unitholders at the current quarterly distribution rate.

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. Demand for our products and services by our customers increased during 2017, and certain wage reductions and workweek reductions implemented during 2016 were reinstated during 2017. However, we continue to review operating and capital expenditure cost levels in order to optimize our levels of cash available for distributions. On January 22, 2018, ourgeneral partnerdeclared a cash distribution attributable to the quarter ended December 31, 2017, of $0.1875 per outstanding common unit, consistent with the prior quarter. In order to make cash distributions at this current distribution rate of $0.1875 per common unit per quarter, or $0.75 per

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common unit per year, we will require available cash of approximately $7.3 million per quarter, or $29.2 million per year, based on the number of common units outstanding as of March 1, 2018. As a result of the issuance of the Preferred Units during 2016, and as Preferred Units continue to convert into common units, more distributable cash will be required to maintain the current distribution rate per common unit. We may not have sufficient available cash each quarter to enable us to make cash distributions at the current quarterly distribution rate under our cash distribution policy, or any distribution at all. The amount of cash we can distribute to our common unitholders principally depends upon the amount of cash we generate from our operations, which fluctuatesfrom quarter-to-quarter based on, among other things, the risks described in this section.

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 our quarterly distributions will be negatively affected.

Failure to comply with the financial ratios in our Credit Agreement could result in defaults under our Credit Agreement and result in decreased credit availability and reduced distributions.

Our Credit Agreement provides us with an asset-based revolving credit facility with a borrowing capacity of up to $315 million, subject to borrowing base requirements (as amended, the “Credit Agreement”). As of December 31, 2017, our consolidated balance sheet includes $512.2 million carrying value of long-term debt consisting of (i) $224.0 million carrying value under the Credit Agreement and (ii) $288.2 million carrying value of 7.25% Senior Notes issued pursuant to an Indenture dated as of August 4, 2014 with U.S. Bank National Association, as trustee (the "Indenture"). Debt service costs related to our outstanding long-term debt represents a significant use of our operating cash flow and could increase our vulnerability to general adverse economic and industry conditions. Payment of our debt service obligations reduces cash available for distribution to our common unitholders. Any breach of, or our inability to borrow under, our Credit Agreement, could impact our ability to fund distributions (if we elected to do so), among other adverse impacts.

On May 5, 2017, we entered into an amendment (the "Fifth Amendment") to our Credit Agreement that modified certain financial covenants in the Credit Agreement, providing that (i) the consolidated total leverage ratio may not exceed (a) 5.95 to 1 as of March 31, 2017; (b) 6.75 to 1 as of June 30, 2017 and September 30, 2017; (c) 6.50 to 1 as of December 31, 2017 and March 31, 2018; (d) 6.25 to 1 as of June 30, 2018 and September 30, 2018; (e) 6.00 to 1 as of December 31, 2018; and (e) 5.75 to 1 as of March 31, 2019 and thereafter; and (ii) the consolidated secured leverage ratio may not exceed 3.25 to 1 as of the end of any fiscal quarter. The consolidated interest coverage ratio was not amended by the Fifth Amendment. In addition, the Fifth Amendment (i) increased the applicable margin by 0.25% in the event the consolidated total leverage ratio exceeds 6.00 to 1, resulting in a range for the applicable margin between 2.00% and 3.50% per annum for LIBOR-based loans and 1.00 to 2.50% per annum for base-rate loans, according to the consolidated total leverage ratio, and (ii) modified the appraisal delivery requirement from an annual requirement to a semi-annual requirement. The Fifth Amendment also included additional revisions that provide flexibility for the issuance of preferred securities.

Continued access to our Credit Agreement is dependent upon our compliance with financial ratio covenants as well as the borrowing base and other provisions set forth in the Credit Agreement. Our Credit Agreement contains additional restrictive provisions ("cash dominion provisions") that are imposed if an event of default has occurred and is continuing or "excess availability" falls below $30.0 million. Our Credit Agreement and the 7.25% Senior Notes also include covenants that restrict our ability to take certain actions or engage in certain transactions.

Our Credit Agreement provides that we may make distributions to holders of our common units, but only if there is no default under the Credit Agreement and we maintain excess availability of $30.0 million. Our ability to comply with the covenants and restrictions contained in our Credit Agreement may be affected by events beyond our control, including prevailing economic, financial, and industry conditions. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. A failure to comply with the provisions of our Credit Agreement could result in an event of default. Upon an event of default, unless waived, the lenders under our Credit Agreement would have all remedies available to secured lenders and could elect to terminate their commitments, cease making further loans, require cash collateralization of letters of credit, cause their loans to become due and payable in full, institute foreclosure proceedings against us or our subsidiaries’ assets, and force us and our subsidiaries into bankruptcy or liquidation. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and the holders of our common units could experience a partial or total loss of their investment. An event of default under our Credit Agreement could also constitute an event of default under our 7.25% Senior Notes.

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We are in compliance with all covenants of our Credit Agreement as of December 31, 2017. Our continuing ability to comply with covenants depends largely upon our ability to generate adequate cash flow. We have reviewed our financial forecasts as of March 1, 2018 which considers the recent amendments to our Credit Agreement. Based on this review and the current market conditions as of March 1, 2018, we believe that we will have adequate liquidity, earnings, and operating cash flows to fund our operations and debt obligations and maintain compliance with our Credit Agreement debt covenants through March 1, 2019. However, there can be no assurance that we will remain in compliance with one or more of our covenants of our Credit Agreement in the future.

Our debt levels may limit our flexibility in obtaining additional financing and in pursuing other business opportunities.

As of December 31, 2017, we had approximately $224.0 million outstanding under our Credit Agreement and $295.9 million aggregate principal amount outstanding under our 7.25% Senior Notes. As of February 28, 2018, the amount outstanding under our Credit Agreement had increased to approximately $245.0 million out of a maximum borrowing capacity of $315.0 million under our Credit Agreement.

Increases in our indebtednessincrease our total interest expense, which in turn reduces our cash available for distribution. Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. 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 distributions, reducing or delaying our business activities, acquisitions, investments and/or capital expenditures, 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.

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 28.9% of our 2017 revenues. Our services and products are provided to these customers pursuant to equipment sales or short-term contract compression services agreements, many of which are cancellable with 30-days' notice. The loss of all or even a portion of the services we provide to these customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations, financial condition, and our ability to make cash distributions to our unitholders.

The credit and risk profile of 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 their control of us, their performance of administrative functions for us, our close operational links, and our contractual relationships. Furthermore, the trading price of our common units may be adversely affected by financial or operational difficulties or excessive debt levels at TETRA. In addition, if TETRA’s ownership of our general partner is pledged to TETRA’s lenders, 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 “evergreen” contracts that 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.

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We are exposed to interest rate risk with regard to our indebtedness.

Our Credit Agreement provides for floating rate borrowings that bear interest at an agreed upon percentage rate spread above LIBOR or a base rate. As of February 28, 2018, we had approximately $245.0 million of borrowings outstanding, including $8.5 million of letters of credit and performance bonds. Accordingly, our cash flows and results of operations are subject to interest rate risk exposure associated with the level of variable rate borrowings outstanding. We currently are not a party to an interest rate swap contract or other derivative instrument designed to hedge our exposure to interest rate fluctuation risk. If interest rates increase, our debt service obligations on variable rate indebtedness would increase (even if the amount borrowed remained the same). A 1.0% increase in interest rates on the borrowings outstanding under our Credit Agreement would cost us approximately $2.3 million in additional annual interest expense.

We face competition that may cause us to lose market share and harm our financial performance.

Our business is highly competitive. We face competition from a variety of large and small companies, including national and multinational companies with greater financial resources than we have. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. Our competitors could substantially increase the resources they devote to the development and marketing of competitive equipment or services, develop more efficient equipment, or decrease the price at which they offer their equipment services or sell their equipment. Any of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition, and ability to make cash distributions 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 compressor packages and pump systems. We obtain some of the components used in our compressor packages and pump systems 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 sources and the partial or complete loss of certain of these sources 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 and pump systems 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 flow levels from the sale of compressor packages and pump systems are inconsistent.

A significant portion of our revenues is derived from the sales of compressor packages and pump systems. During 2017, we reported revenues of $49.5 million from the sale of compressor packages. As of December 31, 2017, we had a compressor package and pump system sales order backlog of $47.5 million, which compared to $21.6 million as of December 31, 2016. Demand to purchase our compressor packages and pump systems is also 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 and pump systems to decrease.

Our future growth and success will depend upon a number of factors, some of which we cannot control.

Our long-term growth strategy includes both internal growth and growth through acquisitions. Our future internal growth and success will depend upon a number of factors that are outside of our control. These factors include our ability to:

• attract new customers;

• maintain our existing customers and maintain or expand the level of services we provide to them; and

• recruit,train, and retainqualified field servicesand otherpersonnel.

Failure in any of these areascould adversely affect our ability to execute our internal growth strategy.

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Our ability to grow in the future may be dependent on our ability to access external expansion capital.

We distribute to our common unitholders all of our available cash after paying expenses and establishing desired reserves. As of December 31, 2017, our total cash balance was $7.6 million. If our cash balances are insufficient to fund future growth opportunities, we plan to rely primarily upon external financing sources, including borrowings under our revolving credit facility and the issuance of debt and equity securities, to fund such growth. To the extent we are unable to efficiently finance growth externally, our cash distribution policy will significantly impair our ability to grow. To the extent we issue additional partnership units in connection with our growth, the payment of distributions on those additional partnership units may increase the risk that we will be unable to maintain or increase our per-unit distribution. There are no limitations in our partnership agreement or our Credit Agreement on our ability to issue additional common units.

We may be unable to grow successfully through future acquisitions and we may not be able to achieve the expected benefits of and integrate the businesses we do acquire effectively, which may impact our operations and limit our ability to increase distributions to our common unitholders.

From time to time, we may choose to make business acquisitions to pursue market opportunities, increase our existing capabilities, and expand into new areas of operations. We may not be able to identify attractive acquisition opportunities or successfully acquire identified targets. If oil and natural gas prices worsen or do not improve, we may not achieve all of the expected benefits of or be successful in fully integrating any future acquisitions into our existing operations, which may result in unforeseen operational difficulties or diminished financial performance or require a disproportionate amount ofattention fromourgeneral partner’spersonnel. Even if we are successful in fully integrating any future acquisitions into our existing operations, we may not derive the benefits, such as operational or administrative synergies, that we expect from such acquisitions, which may result in the commitment of our capital resources without the expected returns on such capital. Furthermore, competition for acquisition opportunities may escalate, increasing our cost of making acquisitions or causing us to refrain from making acquisitions. Our inability to make acquisitions or to achieve the expected results of and integrate successfully future acquisitions into our existing operations may impact our operations and limit our ability to increase distributions to our common unitholders.

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 includes 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.

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We have policies and procedures to maintain our compliance with the FCPA, OFAC sanctions, export controls, and similar laws and regulations. While we do not believe that CSI was in violation of any of the aforementioned laws or regulations, including with respect to its historical sales to customers in Mexico and the Republic of the Union of Myanmar (also referred to as Myanmar or Burma), it is possible that we could discover such violations in the process of our integration. 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, or discover that CSI has violated, 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.

Escalating 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 recentyears, 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, particularly in late 2013, early 2014, and late 2015. 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.

As a result of our operations in Argentina, consolidated revenues and operating cash flow generated in Argentina have increased over the past three years. As of December 31, 2017, approximately $53,000 of our consolidated cash balance is located in bank accounts in Argentina, and 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 to manage our operations and make decisions on our behalf. Our ability to provide quality compression services depends upon our general partner’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 growthstrategy. 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.

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The employees conducting our operationsin 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 operationsin Mexicoare currently subjectto collective labor agreements. Thesecollective 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.

TETRA and its affiliates are not limited in their ability to compete with us, which could cause conflicts of interest and limit our ability to acquire additional assets or businesses, which in turn could adversely affect our results of operations and cash available for distribution to our common unitholders.

Neither our partnership agreement nor the Omnibus Agreement between TETRA and us prohibits TETRA and its affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. TETRA currently provides some services for PEMEX in Mexico in competition with us and could choose to further compete with us for additional services for PEMEX in Mexico. In addition, TETRA and its affiliates may acquire compression-based services businesses or assets in the future, without any obligation to offer us the opportunity to purchase any of that business or those assets. As a result, competition from TETRA could adversely affect our results of operations and cash available for distribution.

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 weakenedsignificantly, 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.generally accepted accounting principles ("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.

Asa 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. In addition, for our operations in Canada, where the Canadian dollar is the functional currency under GAAP, all U.S. dollar-denominated monetary assets and liabilities, such as cash and cash equivalents, accounts receivable, restricted cash, accounts payable, long-term debt and capital lease obligations, are revalued and reported based on the prevailing exchange rate at the end of the reporting period. This revaluation may cause us to report significant foreign currency exchange gains and losses in certain periods.

Further changes in theeconomic environment could result in further significant impairments of certain of our long-lived assets.

In years subsequent to 2014, including early 2017, lower oil and natural gas commodity prices resulted in a decreased demand for certain of our products and services. Demand for compression services and for sales of compressor equipment decreased significantly, although recently we are seeing signs of increased demand, particularly for mid- and high-horsepower compression services and equipment. Decreased commodity prices had, and may continue to have, a negative impact on oil and gas drilling and capital expenditure activity, which affects

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the demand for a portion of our products and services. During 2015 and 2016, primarily as a result of the significant decreases in oil and natural gas prices during these periods, we recorded certain consolidated long-lived asset impairments, including goodwill impairments, of approximately $253.8 million. Further changes in theeconomic environment could result in decreased demand for our products and services, which could impact the expected utilization rates of our compressor package fleet. Under generally accepted accounting principles, 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 additional impairments, resulting in decreased earnings.

Anticipated benefits from our system software development project may not be fully realizable.

During 2016, we initiated a system software development project designed to improve operating and administrative efficiencies and allow us to further reduce costs. The new software system was launched in August 2017 and is intended to align the administrative and operations systems of our entire organization and is designed to integrate the operations of CSI with our existing system environment. The total cost of this software system development project was $12.6 million. There is a risk that this software development project will not accomplish all of its desired efficiencies due to software limitations, operational complexities, cost and timing constraints, and other factors.

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.

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 U.S. Environmental Protection Agency (the “EPA”) has adopted regulations under the Clean Air Act 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 New Source Performance Standards as well as emission standards to address hazardous air pollutants. Certain CSI compressors 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 the business, additional regulations

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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 “greenhouse gases” 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 determined that greenhouse gases ("GHGs")present an endangerment to public health and the environment,because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the Clean Air Act ("CAA"). Such EPA rulesregulate GHG emissions under the CAA and requirea reduction in emissions of GHGs from motor vehiclesandfrom certain large stationary sources. The EPA rules also require so-called “green” completions at hydraulically fractured natural gas wells beginning in 2015. In addition, the EPArequirestheannual reportingof GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries,as well asfromcertain oil and gas production facilities.

In addition, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global greenhouse gas 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. To the extent that the United States and other countries implement the Paris Agreement or impose 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, ourfacilitiesand 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 ourproducts 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.

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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 (“SDWA”) Underground Injection Control (“UIC”) program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities; published final rules under the federal CAA in 2012 and published additional final regulations in June 2016 governing methane and volatile organic compound (“VOC”) performance standards, including standards for the capture of air emissions released during for the oil and natural gas hydraulic fracturing industry; published in June 2016 an effluent limitations guidelines final rule prohibiting the discharge of waste water from shale natural-gas extraction operations before discharging to a treatment plant; and in 2014 published an Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the U.S. Bureau of Land Management ("BLM") published a final rule in March 2015 that established new or more stringent standards for performing hydraulic fracturing on federal and Indian lands. However, in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule, the BLM appealed the decision to the U.S. Circuit Court of Appeals for the Tenth Circuit in July 2016, the appellate court issued a ruling in September 2017 to vacate the Wyoming trial court decision and dismiss the lawsuit challenging the 2015 rule in response to the BLM’s issuance of a proposed rulemaking to rescind the 2015 rule and, in December 2017, the BLM published a final rule rescinding the March 2015 rule. In January 2018, litigation challenging the BLM’s rescission of the 2015 rule was brought in federal court, but, in June 2016, a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule. That decision was appealed by the BLM to the U.S. Circuit Court of Appeals for the Tenth Circuit in 2016, but, in March 2017, the BLM filed a request with the Tenth Circuit to put the appeal on hold pending rescission of the 2015 final rule.

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, where the drilling program is expected to operate, 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 in areas where the drilling program operates, including, for example, on federal and American Indian lands, the partnership 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. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under some circumstances. “Water cycle” describes the use of water in hydraulic fracturing, from water withdrawals to the making of hydraulic fracturing fluids, through the mixing and injection of hydraulic fracturing fluids in oil and natural gas production wells, to the collection and disposal or reuse of produced water.

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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.

Regulatory initiatives relating to the protection of endangered or threatened species in the United States, in other countries where we operate, could have an adverse impact on our and our customers’ ability to expand operations.

In the United States, the Endangered Species Act (the “ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”). To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where we or our customers operate, both our and our customers’ abilities to conduct or expand operations and construct facilities could be limited or be forced to incur material additional costs.

The designation of previously unidentified endangered or threatened species could indirectly cause us to incur additional costs, cause our or our customers’ operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. In addition, as a result of a settlement approved by the United States for the District of Columbia in 2011, the U.S. Fish and Wildlife Service is required to make a determination of listing of numerous species as endangered or threatened under the Endangered Species Act prior to the completion of the agency’s 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where we or our customers might conduct operations could result in limitations or prohibitions on our operations and could adversely impact our business.

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 uncontrolledflows 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. 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 justifiable. If we were to incur substantial liability and such damages were not covered by insurance or were in excess of policy limits, or if we were to incur liability at a time when we 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, andEnvironmentalAffairsRegulations” 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 disclosed a material weakness in our internal control over financial reporting as of December 31, 2015, and if we have other material weaknesses or significant deficiencies in our internal control over financial reporting our business may be adversely affected.

As of December 31, 2015, management identified certain deficiencies in our internal control over financial reporting relating to accounting for the recognition of aftermarket services revenues. A material weakness is a deficiency, or combination of deficiencies, that result in a reasonable possibility that a material misstatement of a company's annual or interim financial statements will not be prevented or detected on a timely basis. Although this material weakness was remediated during 2016, a future material weakness in our internal control over financial reporting could adversely impact our ability to provide timely and accurate information. If additional material weaknesses or significant deficiencies in our internal control occur in the future, we may not be able to timely or accurately report our results of operations or maintain effective disclosure controls and procedures. If we are unable to report financial information timely or accurately, or to maintain effective disclosure controls and procedures, we could be subject to, among other things, regulatory or enforcement actions, securities litigation, debt rating agency

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downgrades or rating withdrawals, any one of which could adversely affect the valuation of our common units and our business prospects.

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.

Furthermore, these information technology systems may be vulnerable to security breaches beyond our control, including those involving cyberattacks using viruses, worms or other destructive software, process breakdowns, phishing or other malicious activities, or any combination of the foregoing. Such breaches could result in unauthorized access to information including customer, supplier, employee, or other company confidential data. We do not carry insurance against these risks, although our general partner 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 have experienced, and expect to continue to experience, cybersecurity threats and incidents, none of which has been material to us to date. However, a successful breach or attack could have a material negative impact on our operations or business reputation and subject us to consequences such as litigation and direct costs associated with incident response.

Risks Inherent in an Investment in Us

The Series A Convertible Preferred Units issued inAugust 2016andSeptember 2016are senior in right of distributions, liquidation and voting to the common units, and will result in the issuance of additional partnership common units in the future, resulting in dilution of our existing common unitholders’ ownership interests, and such dilution is potentially unlimited.

Our partnership agreement does not limit the number of additional partnership common units that we may issue at any time without the approval of our common unitholders. In addition, subject to the provisions of the Series A Preferred Unit Purchase Agreements, we may issue an unlimited number of partnership units that are senior to the common units in right of distribution, liquidation, or voting. On August 8, 2016, we issued an aggregate of 4,374,454 of the Preferred Units for a cash purchase price of $11.43 per Preferred Unit (the “Issue Price”), resulting in total net proceeds, after deducting certain offering expenses, of $49.8 million. Additionally, on September 20, 2016, we issued an aggregate of 2,624,672 of Preferred Units for a cash purchase price of $11.43 per Preferred Unit, resulting in total net proceeds, after deducting certain offering expenses, of $29.0 million.

Pursuant to the Series A Convertible Unit Purchase Agreement dated August 8, 2016, our general partner executed the Second Amended and Restated Agreement of Limited Partnership of the Partnership (the “Amended and Restated Partnership Agreement”) to, among other things, authorize and establish the rights and preferences of the Preferred Units. The Preferred Units are a class of equity security that ranks senior to all classes or series of our equity securities with respect to distribution rights and rights upon liquidation. The holders of Preferred Units (each, a “Preferred Unitholder”) receive quarterly distributions in kind in additional Preferred Units, equal to an annual rate of 11.00% of the Issue Price ($1.2573 per unit annualized), subject to certain adjustments, including adjustments related to any future issuances of common units below a set price, and any quarterly distributions on our common units in excess of $0.3775 per common unit. In the event we fail to pay in full any quarterly distribution in additional Preferred Units, then until such failure is cured we are prohibited from making any distributions on our common units. Beginning on March 8, 2017 and on the first Trading Day (as defined in the Amended and Restated Partnership Agreement) of each calendar month thereafter for a total of thirty months (each, a “Conversion Date”), the Preferred Units convert into common units representing limited partner interests in the partnership in an amount equal to, with respect to each Preferred Unitholder, the number of Preferred Units held by such Preferred Unitholder

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divided by the number of Conversion Dates remaining. On June 7, 2017, as permitted under the Amended and Restated Partnership Agreement, we elected to defer the monthly conversion of Preferred Units for each of the Conversion Dates during the three month period beginning July 2017. As a result, no Preferred Units were converted into common units during the three month period ended September 30, 2017, and future monthly conversions were increased beginning in October 2017. During 2017, conversions of the Preferred Units resulted in the issuance of 3.7 million common units. We anticipate that the number of common units that will be issued upon conversions of the Preferred Units during 2018 will increase, as monthly conversions are expected during the full year of 2018 and due to the three month deferral of conversions during 2017. We may, at our option, pay cash, or a combination of cash and common units, to the Preferred Unitholders instead of issuing common units on any Conversion Date, subject to certain restrictions as described in the Amended and Restated Partnership Agreement and the Credit Agreement.

The issuance by us of the Preferred Units, and the common units issued upon conversion thereof, 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 relative voting power of our previously existing common unitholders will be diminished; and

• the market price of the common units may decline.

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 and future cash distributions to our common unitholders.As a result, our general partner relies primarily upon external financing sources, including commercial bank borrowings and the issuance of 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.

OnJanuary 22, 2018, ourgeneral partnerdeclared a cash distribution attributable to the quarter endedDecember 31, 2017 of $0.1875 per common unit. This distribution equates to a distribution of $0.75 per outstanding common unit, on an annualized basis. This cash distribution was paid on February 14, 2018 to all common unitholders of record as of the close of business on February 1, 2018. 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. 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:

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• 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

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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

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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 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 1, 2018, our general partner and its affiliates, owns 40% 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.

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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 1, 2018, our general partner and its affiliates own an aggregate of 40% of our common units.

Our common unitholders’ liability may not be limited if a court finds that common unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to our general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. Our common unitholders could be liable for any and all of our obligations as if they were a general partner if:

• a court or government agency determined that we were conducting business in a state but had not complied with that particular state’s partnership statute; or

• our common unitholders’ right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other actions under our partnership agreement constitutes “control” of our business.

Our common unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, our common unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our common unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners because of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended.

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by affiliates of TETRA). As of March 1, 2018, our general partner and its affiliates own an aggregate of 40% of our common units.

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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, we believe that we satisfy the qualifying income requirement. 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, which is currently a maximum of 35%, decreasing to 21% beginning in 2018, 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, including our CSI subsidiary. 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 increased 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 federal income tax laws that would affect publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we relay for our treatment as a partnership for U.S. federal income tax purposes.

Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for

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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 of 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.

In addition, on January 24, 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Code (the "Final Regulations") were published in the Federal Register. The Final Regulations are effective s of January 19, 2017, and apply to taxable yes beginning on or after January 19, 2017. We do not believe the Final Regulations affect our ability to be treated as a partnership for U.S. federal income tax purposes.

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 10.2%of our consolidated revenues for the year ended December 31, 2017,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 reducing 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.

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

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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.

Legislation applicable to partnership tax years beginning after 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 federal income tax audit. Under these new rules, unless we are eligible to (and do) elect to issue revised information statements to our partners with respect to an audited and adjusted partnership tax return, the IRS 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.

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 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.

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 their tax basis in that common unit, 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 thoseunits, 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. If this limitation were to apply with respect to a taxable year, it 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.

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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, 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.

The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a Non-U.S. unitholder’s sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interests in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges. It is not clear if or when such regulations or other guidance will be issued. Non-U.S. unitholders should consult a tax advisor before investing in our common units.

We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Due to a number of factors, including our inability to match transferors and transferees of common units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns.

We prorate our items of income, gain, loss, and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge aspects of our proration method and could change the allocation of items of income, gain, loss, and deduction among our unitholders.

We prorate our items of income, gain, loss, and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. 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.

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Taxable income from our non-U.S. businesses is not eligible for the 20% deduction for qualified publicly traded partnership income.

Pursuant to the Tax Cuts and Jobs Acts, 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 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, 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.

Unitholders may be subject to tax in one or more non-U.S. jurisdictions, including Canada, Mexico, Argentina, and Australia, as a result of owning our common units if, under the laws of any such country, we are considered to be carrying on business there. If unitholders are subject to tax in any such country, they may be required to file a tax return with, and pay taxes to, that country based on their allocable share of our income. We

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may be required to reduce distributions to unitholders on account of any withholding obligations imposed upon us by that country 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.

The recently passed comprehensive U.S. federal tax reform bill could adversely affect our business and financial condition.

On December 22, 2017, President Trump signed into law the Tax Cuts and Jobs Act (the “Act”), which significantly reforms the Code. The Act, among other things, contains significant changes to business taxation, including a permanent reduction of the corporate income tax rate, a partial limitation on the deductibility of business interest expense, limitation of the deduction for certain net operating losses to 80% of current year taxable income, an indefinite carryforward of certain net operating losses, immediate deductions for certain new investments instead of deductions for depreciation expense over time, a “transition” tax with respect to certain non-U.S. earnings, other additional new taxes with respect to non-U.S. earnings and payments made or accrued to non-U.S. entities, and the modification or repeal of many business deductions and credits. We continue to examine the impact of the Act, and as its overall impact is uncertain, we note that the Act could adversely affect our business and financial condition

It is the responsibility of each unitholder to file all U.S. federal, state, and local tax returns and non-U.S. tax returns.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

As of December 31, 2017, we owned a fabrication facility in Midland, Texas, a facility in Oklahoma City, Oklahoma, and additional service facilities in North Dakota, Oklahoma, Texas, and Utah. We lease 37 additional service facilities in Alabama, California, Colorado, Louisiana, New Mexico, Ohio, Oklahoma, Texas, 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 TETRA’s facilities in 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 compressor fleet. All obligations under our bank revolving credit facility are secured by a first-lien security interest in substantially all of our assets, including our equipment fleet and 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.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Repurchases of Equity Securities.

Price Range of Common Unitsand Cash Distributions

Our commonunits aretraded on theNASDAQ Global Market ("NASDAQ")under the symbol “CCLP.” As ofMarch 1, 2018, there were 35holders of record of the commonunits. The following table sets forth the high and low sale prices of the commonunits and cash distributions to common unitholdersfor each calendar quarterduring thetwo years ended December 31, 2017, as reported by theNASDAQ.

	High		Low		Cash Distribution per Common Unit(1)
2016
First Quarter	$	11.81	$	3.74	$	0.3775
Second Quarter	10.00		5.17		0.3775
Third Quarter	10.84		7.39		0.3775
Fourth Quarter	11.66		8.63		0.3775
2017
First Quarter	$	13.54	$	8.52	$	0.1875
Second Quarter	10.15		4.12		0.1875
Third Quarter	5.52		4.19		0.1875
Fourth Quarter	5.99		4.51		0.1875

(1) Represents cash distributions attributable to the quarter and paid in the following calendar quarter.

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. For the fourth quarter of 2017, we paid a distribution of $0.1875 per common unit, or $0.7500 on an annualized basis. As a

32

result, no payments are due under our incentive distribution rights to our general partner in connection with this quarterly distribution. (See discussion of incentive distribution rights below.) There is no guarantee that we will continue to pay the current quarterly distribution on the common units. 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 2017 totaled $0.7500 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 - Bank Credit Facility” for a discussion of provisions included in our revolving credit facility that restrict our ability to make distributions.

General Partner Interest and Incentive Distribution Rights. Initially, our general partner is 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 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 approximately 2.0% general partner interest.

Our general partner also currently 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.

Series A Convertible Preferred Units. We are required to make quarterly distributions to our Preferred Unitholders. The holders of Preferred Units are entitled to receive quarterly distributions in kind in additional Preferred Units, equal to an annual rate of 11.00% of the issue price ($1.2573 per unit annualized), subject to certain adjustments related to any future issuances of common units below a set price and any quarterly distributions on our common units in excess of $0.3775 per common unit. In the event we fail to pay in full any quarterly distribution in additional Preferred Units, then until such failure is cured we are prohibited from making any distributions on our common units.

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, 2017	—		N/A	N/A
Nov 1 – Nov 30, 2017	–	–	N/A	N/A
Dec 1 – Dec 31, 2017	–	–	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, 2017.

Item 6. Selected Financial Data.

The following tables set forth our selected consolidated financial data for the years ended December 31, 2017,2016,2015, 2014, and 2013. 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

33

of our future financial condition or results of operations. During 2016 and 2015, we recorded significant impairments of long-lived assets and goodwill. On August 4, 2014, pursuant to a stock purchase agreement dated July 20, 2014, one of our subsidiaries acquired all of the outstanding capital stock of CSI for $825.0 million cash, a portion of which was financed through the issuance of additional common units and through the issuance of long-term debt. For periods after August 4, 2014, our results of operations include the operations of CSI.

	Year Ended December 31,
	2017			2016			2015			2014		2013
	(In Thousands, Except Per Unit Amounts)
Income Statement Data
Revenues	$	295,566		$	311,363		$	457,641		$	282,647	$	121,301
Cost of revenues	193,498			191,260			290,660			174,667		68,116
Depreciation and amortization expense	69,140			72,123			81,838			40,880		14,349
Impairments of long-lived assets	—			10,223			11,797			278		293
Insurance recoveries	(2,352		)	—			—			—		—
Selling, general, and administrative expenses	33,438			36,222			43,479			32,100		17,467
Goodwill impairment	—			92,334			139,444			—		—
Interest expense, net	43,135			38,055			34,964			14,240		617
Series A Preferred fair value adjustment	(3,402		)	5,036			—			—		—
Other expense, net	(216		)	2,383			2,190			10,396		634
Income (loss) before income tax provision	(37,675		)	(136,273		)	(146,731		)	10,086		19,825
Net income (loss)	$	(40,459	)	$	(138,138	)	$	(146,630	)	$	11,258	$	17,567
Net income (loss) per common unit, basic	$	(1.13	)	$	(4.07	)	$	(4.36	)	$	0.47	$	1.11
Weighted average common units outstanding, basic	35,035,428			33,262,376			33,169,413			18,928,640		9,230,876
Net income (loss) per common unit, diluted	$	(1.13	)	$	(4.07	)	$	(4.36	)	$	0.47	$	1.10
Weighted average common units outstanding, diluted	35,035,428			33,262,376			33,169,413			18,928,640		9,305,066
Cash distributions declared per common unit	$	0.75		$	1.51		$	1.98		$	1.80	$	1.71

	December 31,
	2017		2016		2015		2014		2013
	(In Thousands)
Balance Sheet Data
Working capital	$	38,141	$	52,090	$	59,300	$	91,215	$	34,151
Total assets	742,932		786,140		966,627		1,217,051		224,107
Long-term debt	512,176		504,090		566,658		523,351		28,957
Partners' capital	95,027		143,249		332,158		550,281		173,716

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.

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.

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Business Overview

With an overall increase in commodity prices during 2017 compared to the prior year and increases in demand for natural gas, there were continuing increases in demand for compression service during 2017. This increased demand resulted in increases to our compression fleet utilization rate to the highest levels since 2015, as our overall horsepower ("HP") utilization rate as of December 31, 2017 increased to 83.2% as of December 31, 2017 compared to 76.4% as of December 31, 2016. Our over-800 HP compressor fleet has performed at a higher utilization rate than our low HP and our 101-800 HP compressor fleet, and our over-800 HP fleet exceeded 92.3% utilization for the first time since late 2015. The utilization rate for the 101-800 HP compressor fleet reached 81.2% for the first time since early 2015. Contract rates and pricing for our compression services increased modestly, particularly in the second half of 2017, with demand and pricing levels for high and mid horsepower equipment increasing faster than for our low horsepower offerings. Despite these increases in demand and modest price increases on contract rates and pricing, the overall customer pricing decreases and concessions from the market downturn from 2015 to 2016 continued to negatively impact revenues during 2017 as the compression and related services revenue during 2017 decreased 8.4% compared to 2016. Although customer contract pricing began to improve during the last half of 2017, the impact from previous contract pricing concessions is likely to continue into 2018 until those contracts expire. We expect continuing increases in utilization rates in 2018, particularly in our low and mid horsepower offerings and gradual increases in contract rates from renewals to contribute to increases in 2018 compression and related services revenue. In addition, we anticipate adding high horsepower compression units to our compression fleet during 2018, which is also projected to increase our compression and related services revenue going forward, subject to our ability to fund the related growth capital expenditures.

Delayed compression projects and reduced capital expenditure levels of our customers' compression projects continued from 2016 into the first half of 2017, and resulted in an overall decrease in equipment sales revenues of 7.2% during 2017 compared to the prior year. The decrease was also attributed to changes in customer demand from used units to new units during 2017, as the number of used units sold in 2017 was less than 2016. Partially offsetting these decreases, the second half of 2017 experienced higher oil commodity price levels and increases in natural gas demand and consumption forecasts that guided more of our customers to undertake planned infrastructure projects that were previously delayed and also resulted in the expansion of our customers’ capital expenditure budgets. The increased customer requirements for additional equipment and compressor packages in the second half of 2017 resulted in a sizeable increase in our new equipment sales backlog at December 31, 2017 of $47.5 million compared to $21.6 million as of December 31, 2016. In addition, subsequent to December 31, 2017, we received an order from a single customer for approximately $67 million of new compressor equipment, the largest single order in our history, and as a result our new equipment sales backlog has increased to approximately $117 million. Much of the new equipment sales backlog is associated with customer gas gathering projects to meet rising US gas exports and power sector gas demand. Additionally, with rising demand during 2017, our customers increased their maintenance capex activities and deployed compression units that were previously idle resulting in an increase to our aftermarket sales revenue of 21.0% during 2017 compared to the prior year.

The overall increase in the market demand for natural gas is projected to continue into future periods, which is expected to have a positive impact on our future revenues and margins. We have continued to focus on maintaining a low cost structure that includes strong discipline over operating expenses. In August 2017, we launched a new enterprise resource planning ("ERP") software system that has enhanced our sales, operations and back office functions to streamline our business practices, resulting in enhanced customer services and expected to result in lower operating and administrative costs going forward. We continue to manage headcount and spending levels carefully, but have reinstated wages and benefits to the levels prior to the early 2016 wages and benefit reductions. We plan to fund our capital expenditure needs through operating cash flows, borrowings under our Credit Agreement, and potentially other sources, if necessary.

While we anticipate increased future demand for our products and services, we anticipate an extended period of recovery before our revenues and operating cash flows return to pre-2015 levels. We continue to focus on liquidity and our ability to maintain compliance with financial covenants under our Credit Agreement and indenture for our senior notes. We plan to continue to conserve cash in order to fund growth capital expenditures in advance of expected additional increases in demand for compression services and equipment. In May 2017, we entered into the Fifth Amendment of the Credit Agreement that, among other things, favorably amended certain financial covenants. In addition, beginning with the March 8, 2017 initial conversion of our Series A Convertible Preferred Units (the "Preferred Units"), and following a suspension of such conversions during the third quarter of 2017, we have begun to reduce the number of Preferred Units outstanding through the issuance of common units. For further

35

discussion of the Preferred Units, see “Liquidity and Capital Resources - Cash Flows - Financing Activities - Series A Convertible Preferred Units" section below. These steps have enhanced our liquidity position and improved our ability to maintain compliance with Credit Agreement and senior notes covenants in the event current market conditions persist or worsen. Additional steps may be taken in the future. The scheduled maturities of our long-term debt are August 2019 for our Credit Agreement and August 2022 for our 7.25% Senior Notes.

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 andallows 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. 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 wagesand benefitsfor 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, 2017, is provided within the results of operations sections below.

Adjusted EBITDA.We view Adjusted EBITDA as one of our primary management tools, and we trackiton a monthly basis, both in dollars and as a percentage of revenues(typically compared to the prior month,prior yearperiod,and to budget). We define Adjusted EBITDA as earnings before interest, taxes, depreciation and amortization, and before certain non-cash charges consisting of impairments, bad debt expense attributable to bankruptcy of customer, equity compensation, non-cash costs of compressors sold, fair value adjustments of our Preferred Units, gain on extinguishment of debt, administrative expenses under the Omnibus Agreement paid in equity using common units, and excluding acquisition and transaction costs and severance. This definition conforms closely to the definition used in the financial covenant provisions in our Credit Agreement. Adjusted EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, including investors, to:

• assess our ability to generate available cash sufficient to make distributions to our common unitholders andgeneralpartner;

• 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 our competitors;

• determine our ability to incur and service debt and fund capital expenditures; and

• monitor the financial performance measures used in our Credit Agreement financial covenants.

     The following tablereconciles net income (loss) to Adjusted EBITDA for the periods indicated:

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	Year Ended December 31,
	2017			2016			2015
	(In Thousands)
Net income (loss)	$	(40,459	)	$	(138,138	)	$	(146,630	)
Provision (benefit) for income taxes	2,784			1,865			(101		)
Depreciation and amortization	69,140			72,123			81,838
Impairments of long-lived assets	—			10,223			11,797
Goodwill impairment	—			92,334			139,444
Bad debt expense attributable to bankruptcy of customer	—			728			—
Interest expense, net	43,135			38,055			34,964
Equity compensation	1,219			3,028			2,164
Acquisition costs	—			—			208
Series A Preferred transaction costs	37			3,131			—
Series A Preferred fair value adjustments	(3,402		)	5,036			—
Gain on extinguishment of debt	—			(1,405		)	—
Omnibus expense paid in equity	1,746			1,576			—
Severance	63			562			772
Non-cash cost of compressors sold	8,505			6,772			3,441
Software implementation	974			—			—
Adjusted EBITDA	$	83,742		$	95,890		$	127,897

The following table reconciles cash flow from operating activities to Adjusted EBITDA:

	Year Ended December 31,
	2017			2016			2015
	(In Thousands)
Cash flow from operating activities	39,068			61,444			101,893
Changes in current assets and current liabilities	(1,357		)	(6,508		)	(9,962		)
Deferred income taxes	(757		)	(30		)	605
Other non-cash charges	(4,391		)	(4,752		)	(3,923		)
Interest expense, net	43,135			38,055			34,964
Series A Preferred paid in kind distributions	(8,380		)	(3,094		)	—
Insurance recoveries	2,352			—			—
Provision (benefit) for income taxes	2,784			1,865			(101		)
Acquisition costs	—			—			208
Omnibus expense paid in equity	1,746			1,576			—
Severance	63			562			772
Non-cash cost of compressors sold	8,505			6,772			3,441
Software implementation	974			—			—
Adjusted EBITDA	$	83,742		$	95,890		$	127,897

Free Cash Flow. We define Free Cash Flow as net 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.

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	Year Ended December 31,
	2017			2016			2015
	(In Thousands)
Cash from operations, net	$	39,068		$	61,444		$	101,893
Capital expenditures, net of sales proceeds	(25,126		)	(10,659		)	(95,272		)
Free cash flow	$	13,942		$	50,785		$	6,621

Adjusted EBITDA and free cash flow are financial measures that are not in accordance with U.S. generally accepted accounting principles (a "non-GAAP financial measure") 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. generally accepted accounting principles ("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 aswe do. Management compensates for the limitations of Adjusted EBITDA and Free Cash Flow as an analytical tool by reviewing the comparable 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 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 theamount of horsepower of compressor packages used to provide services as of a particular date, divided bytheamount of horsepower of compressor packages in our services fleetas ofsuchdate. Management primarily uses this metrictodetermine our future need for additional compressor packages and to measure marketing effectiveness.

Thefollowing table sets forth the total horsepower in our compression fleet, our total horsepower in service, and our horsepower utilization rate as of the dates shown.

	December 31,
	2017		2016		2015
Horsepower
Total horsepower in fleet	1,081,919		1,114,312		1,127,540
Total horsepower in service	900,638		851,733		924,961
Total horsepower utilization rate	83.2	%	76.4	%	82.0	%

The following table sets forth our horsepower utilization rates by each horsepower class of our compressor fleet as of the dates shown.

	December 31,
	2017		2016		2015
Horsepower utilization rate by class
Low horsepower (0-100)	65.4	%	62.5	%	73.7	%
Mid-horsepower (101-800)	81.2	%	70.6	%	77.2	%
High-horsepower (801 and over)	92.3	%	87.5	%	89.9	%

Net Increases/Decreases in Compression Fleet Horsepower.We measure the net increase (or decrease) in our compression fleet horsepower during a given period of time 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 of time 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.

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New Equipment Sales Backlog. Our equipment sales business includes the fabrication and sale of standard compressor packages, custom-designed compressor packages, and oilfield fluid pump systems designed and fabricated primarily at our facility in Midland, Texas. The equipment is fabricated to customer and 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. As of December 31, 2017, our new equipment sales backlog was $47.5 million, the majority of which is expected to be recognized during 2018, based on title passing to the customer, the customer assuming the risks of ownership, reasonable assurance of collectability, and delivery occurring as directed by our customer. In addition, subsequent to December 31, 2017, we received an order from a single customer for approximately $67 million of new compressor equipment, the largest single order in our history, and as a result our new equipment sales backlog has increased to approximately $117 million. 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 delivery has been scheduled. 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.Weprepared these financial statements in conformity with United States generally accepted accounting principles. In preparing our consolidatedfinancial statements,wemakeassumptions, 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.Webase these estimates on historical experience, available information, and various other assumptions thatwebelieve are reasonable under the circumstances.Weperiodically 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 policies reflect the most significant judgments and estimates used in the preparation of our financial statements.

Series A Preferred Units

Because the Preferred Units may be settled using a variable number of common units, the fair value of the Preferred Units is classified as a long-term liability on our consolidated balance sheet in accordance with Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 480 "Distinguishing Liabilities and Equity." The fair value of the Preferred Units as of December 31, 2017 was $70.3 million. Changes in the fair value during each quarterly period, if any, are charged to earnings in the accompanying consolidated statements of operations. To calculate the estimated fair value of our Preferred Units, we utilize market information related to debt instruments, the trading price of our common units, and lattice modeling techniques. Because the Preferred Units are convertible into our common units at the option of the holder, the fair value of the Preferred Units will generally increase or decrease with the trading price of our common units, and this increase/decrease in Preferred Unit fair value will be charged/credited to earnings. Because of the volatility of market factors inherent in the estimation of the fair value of the Preferred Units, including the trading price of our common units, the volatility of our earnings may increase while the Preferred Units are outstanding. During the year ended December 31, 2017, the estimated fair value of the Preferred Units decreased to $70.3 million, resulting in $3.4 million credited to earnings in the accompanying consolidated statements of operations.

Impairment of Long-Lived Assets

We conduct a determination of impairment of long-lived assets periodically 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

39

impairment charges. Historically, our business has not experienced significant impairments of its long-lived compressor 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, 2016, we recorded $10.2 million of impairments of long-lived assets. During the year ended December 31, 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,									Period-to-Period Change
Consolidated Results of Operations	2017			2016			2015			2017 vs. 2016			2016 vs. 2015
	(In Thousands)
Revenues:
Compression and related services	$	205,774		$	224,736		$	287,680		$	(18,962	)	$	(62,944	)
Aftermarket services	40,287			33,303			46,921			6,984			(13,618		)
Equipment sales	49,505			53,324			123,040			(3,819		)	(69,716		)
Total revenues	295,566			311,363			457,641			(15,797		)	(146,278		)
Cost of revenues:
Cost of compression and related services	116,956			117,154			142,327			(198		)	(25,173		)
Cost of aftermarket services	32,256			25,362			39,232			6,894			(13,870		)
Cost of equipment sales	44,286			48,744			109,101			(4,458		)	(60,357		)
Total cost of revenues	193,498			191,260			290,660			2,238			(99,400		)
Depreciation and amortization	69,140			72,123			81,838			(2,983		)	(9,715		)
Impairments of long-lived assets	—			10,223			11,797			(10,223		)	(1,574		)
Insurance recoveries	(2,352		)	—			—			(2,352		)	—
Selling, general, and administrative expense	33,438			36,222			43,479			(2,784		)	(7,257		)
Goodwill impairment	—			92,334			139,444			(92,334		)	(47,110		)
Interest expense, net	43,135			38,055			34,964			5,080			3,091
Series A Preferred fair value adjustment	(3,402		)	5,036			—			(8,438		)	5,036
Other expense, net	(216		)	2,383			2,190			(2,599		)	193
Income (loss) before income taxes	(37,675		)	(136,273		)	(146,731		)	98,598			10,458
Provision (benefit) for income taxes	2,784			1,865			(101		)	919			1,966
Net income (loss)	$	(40,459	)	$	(138,138	)	$	(146,630	)	$	97,679		$	8,492

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	Percentage of Total Revenues
	Year Ended December 31,						Period-to-Period Change
Consolidated Results of Operations	2017		2016		2015		2017 vs. 2016		2016 vs. 2015
Revenues:
Compression and related services	69.6	%	72.2	%	62.9	%	(8.4	)%	(21.9	)%
Aftermarket services	13.6	%	10.7	%	10.3	%	21.0	%	(29.0	)%
Equipment sales	16.7	%	17.1	%	26.9	%	(7.2	)%	(56.7	)%
Total revenues	100.0	%	100.0	%	100.0	%	(5.1	)%	(32.0	)%
Cost of revenues:
Cost of compression and related services	39.6	%	37.6	%	31.1	%	(0.2	)%	(17.7	)%
Cost of aftermarket services	10.9	%	8.1	%	8.6	%	27.2	%	(35.4	)%
Cost of equipment sales	15.0	%	15.7	%	23.8	%	(9.1	)%	(55.3	)%
Total cost of revenues	65.5	%	61.4	%	63.5	%	1.2	%	(34.2	)%
Depreciation and amortization	23.4	%	23.2	%	17.9	%	(4.1	)%	(11.9	)%
Impairments of long-lived assets	—	%	3.3	%	2.6	%	(100.0	)%	(13.3	)%
Insurance recoveries	(0.8	)%	—	%	—	%	100.0	%	100.0	%
Selling, general, and administrative expense	11.3	%	11.6	%	9.5	%	(7.7	)%	(16.7	)%
Goodwill impairment	—	%	29.7	%	30.5	%	(100.0	)%	(33.8	)%
Interest expense, net	14.6	%	12.2	%	7.6	%	13.3	%	8.8	%
Series A Preferred fair value adjustment	(1.2	)%	1.6	%	—	%	(167.6	)%	100.0	%
Other expense, net	(0.1	)%	0.8	%	0.5	%	(109.1	)%	8.8	%
Income (loss) before income taxes	(12.7	)%	(43.8	)%	(32.1	)%	(72.4	)%	(7.1	)%
Net income (loss)	(13.7	)%	(44.4	)%	(32.0	)%	(70.7	)%	(5.8	)%

2017 Compared to 2016

Revenues

Compression and related services revenues decreased by $19.0 million during 2017 compared to the prior year primarily due to the continued impact of contract pricing concessions provided as a result of the market downturn from 2015 to 2016, in which those contracts carried over into 2017. Overall, increases in commodity prices compared to the prior year and growth in demand for natural gas and compression service offering positively affected our compression fleet utilization rates during 2017. Utilization of our medium-horsepower (101-800 HP) and high-horsepower (over 800 HP) compressor fleet, which is used in natural gas gathering and transmission application, has increased as of December 31, 2017 compared to the prior year, and has reached utilization rates not achieved since 2015. We have seen our overall compressor fleet horsepower utilization rate increase sequentially for the past five consecutive quarters. As a result of overall improving demand for compression services, we have begun growth capital projects to increase certain horsepower categories of our compressor fleet. Aftermarket services revenues increased$7.0 million during 2017 compared to the prior year, reflecting a focus on providing an improved sales coverage on midstream customers, resulting in increased parts and overhaul services sales. We have also seen an increased sales backlog for aftermarket projects as well as increased requests for quotes and awards of aftermarket projects resulting from the increased utilization and previously delayed expenditures on customer-owned compression equipment.

Equipment sales revenues decreased$3.8 million during 2017 compared to the prior year. This decrease is primarily due to the decreased number of used unit sales compared to the prior year. Our backlog associated with new equipment sales increased significantly during 2017, as new equipment sales orders have greatly exceeded the decreased equipment sales during the prior year. New equipment sales backlog was $47.5 million as of December 31, 2017 compared to $21.6 million as of December 31, 2016, an indication that demand for equipment sales has improved. 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. In comparison, our revenues from compression and related services and aftermarket services are typically more consistent and predictable.

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Cost of revenues

Despite the more significant decrease in compression and related services revenue, the decrease in the associated cost of compression and related services revenue, compared to the prior year, was marginal because of increases in make ready costs in fleet roll outs as utilization increased. The cost of compression and related services as a percentage of compression and related services revenues was 56.8% during 2017, compared to 52.1% from the prior year primarily as a result of decreased revenues caused by customer price decreases. Cost of aftermarket services increased compared to the prior year, consistent with the increased activity and parts sales levels.

Cost of equipment sales revenues decreased in accordance with the decrease in associated revenues. Costs of equipment sales as a percentage of revenues also decreased due to lower cost of used equipment sales for 2017 compared to the prior year period.

Depreciation and amortization

Depreciation and amortization expense primarily consists of the depreciation of compressor packages in our service fleet. In addition,itincludes the depreciation of other operating equipment and facilities and the amortization of intangibles. Depreciation and amortization expense decreased$3.0 million compared to the prior year due to long-lived asset disposals that reduced the amount of our assets subject to depreciation and as a result of a decrease in the amortization expense. The amortization expense decrease is a result of certain intangible asset impairment charges incurred during 2016 that reduced the amount of our assets subject to amortization.

Long-lived asset impairments

During 2017, we recorded no impairments of long-lived assets. During 2016, we recorded total long-lived asset impairment charges of $10.2 million primarily reflecting the decreased fair value for certain intangible assets as a result of decreased expected future cash flows to support their carrying value. In addition, certain compressor packages were impaired as a result of units that were damaged or destroyed by fires during 2016.

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 administrativeexpenses decreased during 2017 compared to the prior year. This decrease is largely due to decreased professional services fees of $1.0 million, decreased bad debt expense of $0.7 million, decreased employee expenses, including wages, incentives, benefits, and other employee related expenses of $0.5 million and decreased other general expenses of $0.3 million. Selling, general and administrative expense as a percentage of revenues remained consistent with the prior year period, as decreased administrative expenses were largely offset by the decrease in revenues compared to the prior year.

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Goodwill impairment

During the first three months of 2016, low oil and natural gas commodity prices resulted in decreased demand for certain of our products and services. Specifically, demand for low-horsepower wellhead compression services and for sales of compressor equipment decreased significantly and as of March 31, 2016 was expected to continue to be decreased for the foreseeable future. In addition, the price per common unit as of March 31, 2016 decreased compared to December 31, 2015. Accordingly, our fair value, as reflected by our market capitalization and other indicators, was less than our carrying value as of March 31, 2016. When such triggering events have occurred, ASC 350-20 "Goodwill" requires that a test of goodwill impairment be performed consistent with the year-end annual testing requirement. As part of the test of goodwill impairment at quarter end, we estimated our fair value, and determined, based on this estimated value, that impairment of all of our remaining goodwill was necessary, primarily due to the market factors discussed above. Accordingly, during the three month period ended March 31, 2016, $92.4 million was charged to goodwill impairment expense. As a result, we have no remaining goodwill as of December 31, 2016 and 2017.

Interest expense, net

Interest expense increased during 2017 compared to the prior year due to increased expense associated with the paid in kind distributions that accrue and are paid to the holders of the Preferred Units. The Preferred Units were issued during the third quarter of 2016. (See "Note E - Series A Convertible Preferred Units" in the Notes to Consolidated Financial Statements in this Annual Report for a further discussion of the Preferred Units.) Interest expense, net, during the current and prior year periods includes $3.7 million and $4.4 million, respectively, of finance cost amortization and other non-cash charges.

Series A Preferred fair value adjustment

Series A Preferred fair value adjustment was $3.4 million credited to earnings during 2017 compared to $5.0 million charged to earnings during the prior year. The fair value of the Preferred Units is classified as a long-term liability on our consolidated balance sheet in accordance with ASC 480 "Distinguishing Liabilities and Equity" and changes in the fair value during each quarterly period, if any, are charged or credited to earnings. As of December 31, 2017, the fair value of the Preferred Units was $70.3 million. Changes in the fair value of the Preferred Units may generate additional volatility to our earnings going forward.

Other expense, net

Other expense, net, was $(0.2) million income during 2017, compared to $2.4 million expense during the prior year. This decrease in other expense was due to $2.1 million of offering costs for the Preferred Units that were charged in the prior year and $1.6 million of decreased foreign currency losses. These decreases were largely offset by $1.4 million of decreased gains related to the early extinguishment of debt in the prior year and $0.7 million of increased income from insurance proceeds related to damaged compressors.

Income before taxes, provision (benefit) for income taxes, and net income

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.

On December 22, 2017, H.R.1, “An Act to Provide the Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018” (the “Act”) (previously known as “The Tax Cuts and Jobs Act”) was signed into law making significant changes to the Internal Revenue Code. Changes include, but are not limited to, a corporate tax rate decrease from 35% to 21% effective for tax years beginning after December 31, 2017, the transition of U.S international taxation from a worldwide tax system to a territorial system, and a one-time transition tax on the mandatory deemed repatriation of cumulative foreign earnings as of December 31, 2017. We have calculated our best estimate of the impact of the Act in our year end income tax provision in accordance with our understanding of the Act and guidance available as of the date of this filing. See "Note G - Income Taxes" contained in the consolidated financial statements for the effect on our 2017 tax provision.

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Despite the significant pre-tax loss for the year ended December 31, 2017, we recorded a provision for income tax, primarily attributable to taxes in certain foreign jurisdictions and Texas gross margin taxes. Our effective tax rate for the year ended December 31, 2017 was negative 7.4% primarily due to losses generated in entities for which no related tax benefit has been recorded. The losses generated by these entities do not result in tax benefits due to offsetting valuation allowances being recorded against their net deferred tax assets. 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. 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.

2016 Compared to 2015

Revenues

Compression and related services revenues decreased by $62.9 million during 2016 compared to the prior

year primarily due to the overall reduced demand for our compression services fleet. Decreases in oil and natural

gas prices compared to 2015 adversely impacted the demand and pricing for below-100 horsepower

production enhancement compression and related services applications, including for liquids-rich resource plays

and vapor recovery applications. In addition, the continued downturn in commodity prices resulted in the

reduction of the utilization and pricing of our medium-horsepower (101-800 HP) and high- horsepower (over 800

HP) compression and related services applications, which include natural gas gathering and transmission

applications. However, increasing natural gas prices during the end of 2016 and beginning of 2017 resulted in

some improvement in demand for some of our services compared to earlier in 2016. Reductions in customer

operating expenditures translated to less demand for aftermarket services as well, thus contributing to a $13.6 million decrease in these revenues compared to the prior year.

In addition to the decrease in consolidated compression and related services and aftermarket services

revenues, there was a decrease of $69.7 million in revenues from the sales of equipment during 2016, compared to

the prior year. This decrease is primarily due to a lower number of customer projects compared to the prior year,

particularly projects requiring high-horsepower compressor packages. During 2016, the decrease in equipment

sales revenue was partially offset by the sale of $8.8 million of used compressor packages that were previously in

service, particularly during the fourth quarter of 2016. These sales of used compressor packages will result in the

reduction of compression service revenues from these packages going forward. 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. In comparison, our revenues from compression and

related services and aftermarket services are typically more consistent and predictable.

Cost of revenues

The decrease in the cost of compression and related services revenue during 2016 compared to the prior

year was primarily due to the decreases in the associated compression and related services revenues that resulted

from the overall market decline compared to the prior year, and due to the impact of cost reduction efforts. The cost

of compression and related services as a percentage of compression and related services revenues was 52.1%

during 2016, compared to 49.5% from the prior year. This increase in cost of compression and related services as a

percentage of related revenues is a result of service revenue price decreases out pacing the cost reduction efforts.

Cost of equipment sales revenues decreased in accordance with the decrease in associated revenues.

Despite the cost reduction efforts, the costs of equipment sales as a percentage of revenues increased compared

to 2015 largely due to the absorption of additional period costs during 2016 compared to the prior year.

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 decreased $9.7 million during 2016 compared to the prior year. Amortization expense decreased $6.8 million and depreciation expense decreased $2.9 million as a result of long-lived asset disposals and certain long-lived asset impairment charges incurred during the fourth quarter of 2015 and the first quarter of 2016 that reduced the amount of assets subject to amortization and depreciation.

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Long-lived asset impairments

During 2016 and 2015, we recorded total long-lived asset impairment charges of $10.2 million and $11.8 million, respectively, reflecting the decreased fair value for certain assets as a result of decreased utilization and

decreased expected future cash flows to support their carrying value. In addition, certain compressor packages

were impaired as a result of units that were damaged or destroyed by fires during 2016. Such fire damage is

covered pursuant to operations insurance policies, and such claims are currently pending. Assets that were partially

impaired included certain of our intangible assets.

Selling, general, and administrative expense

Selling, general and administrative expenses decreased during 2016 compared to the prior year. This

decrease is largely due to a $6.1 million reduction in employee expenses, including salaries, incentives, benefits,

and other employee related expenses, as a result of salary, workweek, and headcount reduction efforts. In addition,

professional fees decreased by $0.8 million, office, tax, and insurance expense decreased by $1.3 million, and

allocated costs from TETRA pursuant to our Omnibus Agreement decreased by $0.3 million. In addition,

approximately $0.5 million of administrative costs were capitalized as part of our system software development

project. These decreases were partially offset by $2.0 million of increased bad debt, repair and maintenance, and

other general expenses. Selling, general and administrative expense as a percentage of revenues increased during

2016 compared to the prior year, reflecting the decrease in revenues compared to the prior year.

Goodwill impairment

Following the fourth quarter of 2015, we performed an annual test of goodwill impairment in accordance

with the ASC 350-20

"Goodwill". The continuing decline in oil and natural gas commodity prices has had, and is expected to continue to

have, a negative impact on industry drilling and capital expenditure activity, which has affected and is expected to

continue to affect the future demand for certain of our products and services. Specifically, demand for our low horsepower wellhead compression services and for sales of compressor equipment has decreased significantly and is expected to continue to be decreased for the foreseeable future. The prior decrease in demand and the expected decreased future demand, along with the decrease in our common unit price, has also caused a reduction in our overall fair value. As part of the test of goodwill impairment, we estimated our fair value, and determined, based on this estimated value, that impairment of our goodwill was necessary, primarily due to the market factors discussed above. Accordingly, during the fourth quarter of 2015, we recorded an impairment charge associated with our goodwill.

The continued decrease in demand along with the approximately 46.3% decrease in our common unit price

as of March 31, 2016 compared to December 31, 2015, caused a further reduction in our overall fair value since

December 31, 2015. When such triggering events occur, ASC 350-20 requires that a test of goodwill impairment be

performed consistent with the annual testing requirement that is required at year-end. As part of the test of goodwill

impairment at March 31, 2016, we estimated our fair value, and determined, based on this estimated value, that

impairment of our goodwill was necessary, primarily due to the market factors discussed above. Accordingly, during

the first quarter of 2016, we recorded a full impairment charge associated with our remaining goodwill.

Interest expense, net

Interest expense increased during 2016 compared to the prior year due to increased expense associated

with the Preferred Units due to the impact of paid in kind distributions that accrue and are paid to the holders of Preferred Units. (See "Note E - Series A Convertible Preferred Units" in the Notes to Consolidated Financial Statements in this Annual Report for a further discussion of the Preferred Units.) Interest expense during 2016 and 2015 includes $4.4 million and $3.3 million, respectively, of finance cost amortization and other non-cash charges related to the amendments of our credit agreement. Increased interest expense in future periods as a result of paid in kind distributions on the Preferred Units is expected to be partially offset by the impact of our repurchase of $54.1 million principal amount of our 7.25% Senior Notes during September and October 2016.

Series A Preferred fair value adjustment

Series A Preferred fair value adjustment was $5.0 million during 2016. The fair value of the Preferred Units

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is classified as a long-term liability on our consolidated balance sheet in accordance with ASC 480 "Distinguishing

Liabilities and Equity" and changes in the fair value during each quarterly period, if any, are charged to earnings. As

of December 31, 2016, the fair value of the Preferred Units was $88.1 million, which resulted in a non-cash charge

of $5.0 million during the portion of 2016 that the Preferred Units were outstanding. Changes in the fair value of the

Preferred Units may generate additional volatility to our earnings going forward.

Other expense, net

Other expense, net, was $2.4 million during 2016, compared to $2.2 million during the prior year. This

increase was due to $2.1 million of offering costs for the Preferred Units that were charged to Other Expense, net,

during 2016. This charge was partially offset by $1.4 million of gain on the early extinguishment of $54.1 million

principal amount of 7.25% Senior Notes during September and October 2016. In addition, foreign currency

translation expense decreased $0.4 million during 2016 compared to the prior year.

Income before taxes, provision (benefit) for income taxes, and net income

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.

Despite the significant pre-tax loss for the year ended December 31, 2016, we recorded a provision for

income tax, primarily attributable to taxes in certain foreign jurisdictionsand Texas gross margin taxes. Our effective

tax rate for the year ended December 31, 2016 was negative 1.4% primarily due to losses generated in entities for

which no related tax benefit has been recorded. The losses generated by these entities do not result in tax benefits

due to offsetting valuation allowances being recorded against their net deferred tax assets. 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. 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.

Further, the effective tax rate is negatively impacted by the nondeductible portion of our goodwill impairments during

the year ended December 31, 2016.

Liquidity and Capital Resources

Our primary cash requirements are for distributions, working capital requirements, normal operating expenses, and capital expenditures. Oursourcesof funds areour existing cash balances, cash generated from our operations, long-term and short-term borrowings, issuances of debt and equity securities, and leases, which we believe will be sufficient to meet our working capital and growth requirements during the remainder of 2018. Continued competitive market environments have resulted in ongoing challenges in each of our domestic and international business regions. Commodity prices that impact our business have increased compared to 2016 and as result of those increases, we expect that demand for our products and services will continue to grow during 2018 and, assuming the increased prices continue, for the foreseeable future. While we are still managing the effects from prior period reduced demand and subsequent pricing concessions, we remain committed to a long-term growth strategy. Our near-term focus is to continue to preserve and enhance liquidity through strategic operating and financial measures.

Our cash flows from operating activities decreased during 2017, when compared to the prior year, by $22.4 million, primarily as a result of decreased earnings. Cash flows used in investing activities for the year ended December 31, 2017, increased $12.1 million when compared to 2016, reflecting the enhancement of the compressor and equipment fleet and for a system software development project. Cash flows used in financing activities was $29.3 million for 2017, as compared to cash flows used in financing activities of $39.9 million in the prior year, primarily as a result of increased debt borrowings, net, during 2017 and due to decreased cash distributions. A summary of our sources and uses of cash during the three year period ended December 31, 2017, is as follows:

46

	Year Ended December 31,
	2017			2016			2015
Operating activities	$	39,068		$	61,444		$	101,893
Investing activities	(22,753		)	(10,681		)	(95,341		)
Financing activities	(29,334		)	(39,890		)	(28,360		)

We are in compliance with all covenants of our Credit Agreement as of December 31, 2017. We have reviewed our financial forecasts as of March 1, 2018 and for the subsequent twelve month period, which consider the impact of the May 2017 Fifth Amendment to our Credit Agreement, and the current level of distributions to our common unitholders. Based on this review and the current market conditions as of March 1, 2018, we believe that we will have adequate liquidity, earnings, and operating cash flows to fund our operations and debt obligations and maintain compliance with debt covenants through March 1,2019. We expect to fund any future acquisitions and capital expenditures with cash flow generated from our operations, funds available under our Credit Agreement which we expect to extend or replace during 2018, and funds received from the issuance of additional debt and equity securities. However, we are subject to business and operational risks that could materially adversely affect our cash flows.Pleaseread "Item 1A Risk Factors" included in this Annual Report.

Future growth in our operations, both internationally and in the U.S., may requireongoingsignificant capital expenditureinvestment. The level of future growth capital expenditures depends on forecasted demand for compression services. If the forecasted demand for compression services during 2018 increases or decreases, the amount of planned expenditures on growth and expansion will be adjusted accordingly, subject to availability of funds. We anticipate that our total gross capital expenditures (excluding asset disposals and associated proceeds) in 2018 will range from $55.0 million to $75.0 million, including $15.0 million to $20.0 million of estimated maintenance capital expenditures. During the current and upcoming period of increasing natural gas demand, we are reviewing all capital expenditure plans carefully in an effort to conserve cash and fund our liquidity needs. The deferral of capital projects could affect our ability to compete in the future.

Our capital expenditure program consists of both expansion capital expenditures and maintenance capital expenditures. Expansion capital expenditures consist of expenditures for acquisitions or capital improvements that increase our capacity, either by fabricating new compressor packages to expand our compression services fleet, purchasing support equipment or other assets, or through the upgrading of existing compressor packages to increase their capabilities. Expansion capital expenditures generally result in our ability to generate increased revenues. Maintenance capital expenditures consist of expenditures to maintain our compressor package fleet and support equipment without increasing its capacity. Maintenance capital expenditures are intended to maintain or sustain the current level of operating capacity and includes the replacement of existing assets and obsolete assets. Routine repair and maintenance is charged to expense as incurred. A large portion of our capital expenditures during 2017 is associated with an ERP system software development project designed to improve operating and administrative efficiencies. This software development project was completed in August 2017, and we believe will allow us to further reduce costs going forward.

On January 22, 2018, our general partner declared a cash distribution attributable to the quarter ended December 31, 2017of $0.1875 per common unit. This distribution equates to a distribution of $0.75 per outstanding common unit on an annualized basis. Also on January 22, 2018, our general partner approved the paid in kind distribution of 172,210 Preferred Units attributable to the quarter ended December 31, 2017 in accordance with the provisions of our partnership agreement, as amended. These distributions were paid on February 14, 2018, to the holders of common units and Preferred Units, respectively, of record as of the close of business February 1, 2018.

Cash Flows

Operating Activities

Net cash from operating activities decreased by $22.4 million during the year ended December 31, 2017 to $39.1 million compared to $61.4 million in2016. Cash provided from operating activities decreased during 2017 primarily as a result of decreased operating revenues and profitability and due to working capital needs. 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 demand for compression and related services has improved and the level of new equipment sales backlog as of December 31, 2017 has significantly increased compared to December

47

31, 2016. As a result, we expect future revenues and operating cash flows to be increased going forward compared to 2017.

Cash provided from our foreign operations is subject to various uncertainties, including the volatility associated with interruptions caused by customerbudgetary decisions, uncertainties regarding the renewal of our existing customer contracts, and other changes in contract arrangements,security concerns,the timing of collection of our receivables, and the repatriation of cash generated by our operations.

Investing Activities

Capital expenditures duringthe year ended December 31, 2017, increased by $14.5 million compared to 2016 primarily to maintain the capacity of the compressor and equipment fleet and for a system software development project. The new ERP software system was launched in August 2017 and is expected to enhance customer service and result in lower operating and administrative costs going forward. As a result of overall improving demand for compression services during the second half of 2017, we began growth capital projects to increase certain horsepower categories of our compressor fleet. Maintenance capital expenditures also increased during the second half of 2017. Total capital expenditures, net of disposals and proceeds, during 2017 of $25.1 million include $21.0 million of maintenance capital expenditures and are net of $8.5 million of non-cash cost of compression units sold. The level of growth capital expenditures depends on forecasted demand for compression services. If the forecasted demand for compression services during 2018 increases or decreases, the amount of planned expenditures on growth and expansion will be adjusted, subject to the availability of funds, accordingly. We continue to review all capital expenditure plans carefully in an effort to conserve cash and fund our liquidity needs.

Financing Activities

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash, as defined in our Partnership Agreement, to our common unitholders of record on the applicable record date and to our general partner. In addition, our partnership agreement, as amended in August 2016, requires that, within 45 days after the end of each quarter, we make a distribution to holders of our Preferred Units of additional paid in kind Preferred Units equal to 2.75% of the Issue Price (11% of $11.43 per Preferred Unit on an annualized basis). For theyearendedDecember 31, 2017, we distributed cash distributions of approximately $33.1 million to our common unitholders and general partner. On January 22, 2018, our general partner declared a cash distribution attributable to the quarter ended December 31, 2017 of $0.1875 per common unit. This distribution equates to a distribution of $0.75 per outstanding common unit on an annualized basis. We anticipate that we will utilize available cash to fund growth capital expenditures in advance of expected increased demand for compression services. Also on January 22, 2018, our general partner approved the paid-in-kind distribution of 172,210 Preferred Units attributable to the quarter ended December 31, 2017. These distributions were paid on February 14, 2018 to each of the holders of our common units, and to the holders of the Preferred Units as a group, respectively, of record as of the close of business on February 1, 2018.

Our sources of funds for liquidity needs are existing cash balances, cash generated from our operations, and long-term and short-term borrowings.

Series A Convertible Preferred Units

On August 8, 2016 and September 20, 2016, we entered into Series A Preferred Unit Purchase Agreements (collectively the “Unit Purchase Agreements”) with certain purchasers with regard to our issuance and sale in private placements (the "Initial Private Placement" and "Subsequent Private Placement," respectively) of an aggregate of 6,999,126 Preferred Units for a cash purchase price of $11.43 per Preferred Unit (the “Issue Price”), resulting in total net proceeds, after deducting certain offering expenses, of approximately $77.3 million. One of the purchasers in the Initial Private Placement was TETRA, which purchased 874,891 of the Preferred Units at the aggregate Issue Price of $10.0 million. Proceeds from the Initial Private Placement and Subsequent Private Placement were used to pay additional offering expenses and reduce outstanding indebtedness under our Credit Agreement and our 7.25% Senior Notes.

In connection with the closing of the Initial Private Placement, our general partner executed a Second Amended and Restated Agreement of Limited Partnership (the “Amended and Restated Partnership Agreement”) to, among other things, authorize and establish the rights and preferences of the Preferred Units. The Preferred Units are a new class of equity security that will rank senior to all classes or series of equity securities of the

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Partnership with respect to distribution rights and rights upon liquidation. The holders of Preferred Units (each, a “Preferred Unitholder”) will receive quarterly distributions, which will be paid in kind in additional Preferred Units, equal to an annual rate of 11.00% of the Issue Price (or $1.2573 per Preferred Unit annualized), subject to certain adjustments. The rights of the Preferred Units include certain anti-dilution adjustments, including adjustments for economic dilution resulting from the issuance of common units in the future below a set price. 

Ratable portions of the Preferred Units have been, and will continue to be, converted into common units on the eighth day of each month over a period of thirty months that began in March 2017 (each, a “Conversion Date”), subject to certain provisions of the Amended and Restated Partnership Agreement that may delay or accelerate all or a portion of such monthly conversions. On each Conversion Date, a portion of the Preferred Units convert into common units representing limited partner interests in the Partnership in an amount equal to, with respect to each Preferred Unitholder, the number of Preferred Units held by such Preferred Unitholder divided by the number of Conversion Dates remaining, subject to adjustment described in the Amended and Restated Partnership Agreement, with the conversion price (the "Conversion Price") determined by the trading prices of the common units over the prior month, among other factors, and as otherwise impacted by the existence of certain conditions related to the common units. On June, 7, 2017, as permitted under the Amended and Restated Partnership Agreement, we elected to defer the monthly conversion of Preferred Units for each of the Conversion Dates during the three month period beginning July 8, 2017. As a result, no Preferred Units were converted into common units during the three month period ended September 30, 2017, and future monthly conversions increased beginning in October 2017. During 2017, conversions of the Preferred Units resulted in the issuance of 3.7 million common units. We anticipate that the number of common units that will be issued upon conversions of the Preferred Units during 2018 will increase compared to 2017, due to the three month deferral of conversions during 2017 and the expectation that monthly conversions will occur during the full year of 2018. Based on the number of Preferred Units outstanding as of December 31, 2017, the maximum aggregate number of common units that could be required to be issued pursuant to the conversion provisions of the Preferred Units is approximately 34.1 million common units; however, the Partnership may, at its option, pay cash, or a combination of cash and common units, to the Preferred Unitholders instead of issuing common units on any Conversion Date, subject to certain restrictions as described in the Amended and Restated Partnership Agreement and the Credit Agreement. Including the impact of paid in kind distributions of Preferred Units and the conversions of Preferred Units into common units, the total number of Preferred Units outstanding as of December 31, 2017 was 5,975,200.

Because the Preferred Units may be settled using a variable number of common units, the fair value of the Preferred Units is classified as a long-term liability on our consolidated balance sheet in accordance with ASC 480 "Distinguishing Liabilities and Equity." The fair value of the Preferred Units as of December 31, 2017 was $70.3 million. Changes in the fair value during each quarterly period, if any, are charged or credited to earnings in the accompanying consolidated statements of operations. Charges or credits to earnings for changes in the fair value of the Preferred Units, along with the interest expense for the accrual and payment of paid-in-kind distributions associated with the Preferred Units, are non-cash charges or credits associated with the Preferred Units.

In addition, the Unit Purchase Agreements include certain provisions regarding change of control, transfer of Preferred Units, indemnities, and other matters described in detail in the Unit Purchase Agreements. The Unit Purchase Agreements contain customary representations, warranties and covenants.

Bank Credit Facilities

Our Credit Agreement is available to provide our working capital needs, letters of credit, and for general partnership purposes, including capital expenditures and potential future expansions or acquisitions. So long as we are not in default, and maintain excess availability of $30.0 million, our Credit Agreement can also be used to fund our quarterly distributions at the option of our board of directors of our general partner (provided, that after giving effect to such distributions, we will be in compliance with the financial covenants). Borrowings under the Credit Agreement are subject to the satisfaction of customary conditions, including the absence of a default.

On May 5, 2017, we entered into the Fifth Amendment to our Credit Agreement that,

among other changes, modified certain financial covenants in the Credit Agreement. In connection with the Fifth

Amendment, the board of directors of our general partner adopted resolutions limiting the cash distributions

payable on our common units to no more than $0.1875 per common unit for the quarterly period ended June 30,

2017. The Fifth Amendment also included additional revisions that provide flexibility for the issuance of preferred

securities.

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As of February 28, 2018, we have a balance outstanding under our Credit Agreement of $245.0 million, and $8.5 million letters of credit, leaving availability under the Credit Agreement of $61.5 million. Our Credit Agreement matures August 2019. Our Credit Agreement, as amended, includes a maximum credit commitment of $315.0 million, and included within such amount is availability for letters of credit (with a sublimit of $20.0 million) and swingline loans (with a sublimit of $60.0 million). The Credit Agreement is an asset-based facility. Availability under the Credit Agreement is subject to a borrowing base calculation based on components of accounts receivable, inventory, and equipment as well as subject to compliance with covenants and other provisions in the Credit Agreement that may limit borrowings. Borrowings under our Credit Agreement bear interest at a rate per annum equal to, at our option, either (a) LIBOR (adjusted to reflect any required bank reserves) plus a leverage based margin that ranges between 2.00% and 3.25% per annum or (b) a base rate plus a leverage-based margin that ranges between 1.00% and 2.25% per annum, in each case according to the applicable consolidated leverage ratio. We pay a commitment fee ranging from 0.375% to 0.50% per annum on the unused portion of the facility. Under our Credit Agreement, as amended, we and our CSI Compressco Sub, Inc. subsidiary are named as the borrowers and all obligations under our Credit Agreement are guaranteed by all of our existing and future, direct and indirect, domestic restricted subsidiaries (other than domestic subsidiaries that are wholly owned by foreign subsidiaries) and secured by substantially all of our assets and the assets of our domestic subsidiaries.

Our Credit Agreement, as amended, requires us to maintain (i) a minimum consolidated interest coverage ratio (defined ratio of consolidated earnings before interest, taxes, depreciation, and amortization (EBITDA) to consolidated interest charges) of (a) 2.25 to 1 as of the fiscal quarters ended September 30, 2016 through June 30, 2018; (b) 2.50 to 1 as of September 30, 2018 and December 31, 2018; and (c) 2.75 to 1 as of March 31, 2019 and thereafter, (ii) a maximum consolidated total leverage ratio (ratio of consolidated total indebtedness to consolidated EBITDA ) of (a) 5.95 to 1 as of March 31, 2017; (b) 6.75 to 1 as of June 30, 2017 and September 30, 2017; (c) 6.50 to 1 as of December 31, 2017 and March 31, 2018; (d) 6.25 to 1 as of June 30, 2018 and September 30, 2018; (e) 6.00 to 1 as of December 31, 2018; and (f) 5.75 to 1 as of March 31, 2019 and thereafter, and (iii) a maximum consolidated secured leverage ratio (consolidated secured indebtedness to consolidated EBITDA) of 3.25 to 1 as of the end of any fiscal quarter, calculated on a trailing four quarters basis. At December 31, 2017, our consolidated total leverage ratio was 6.48 to 1, our consolidated secured leverage ratio was 2.89 to 1, and our consolidated interest coverage ratio was 2.55 to 1. In addition, our Credit Agreement includes customary covenants that, among other things, limit our ability to incur additional debt, incur, or permit certain liens to exist, or make certain loans, investments, acquisitions, or other restricted payments. In addition, the Credit Agreement requires that, among other conditions, we use designated consolidated cash and cash equivalent balances in excess of $35.0 million to prepay the loans; allows the prepayment or purchase of indebtedness with proceeds from the issuances of equity securities or in exchange for the issuances of equity securities; and restricts the amount of our permitted capital expenditures in the ordinary course of business during each fiscal year to $50.0 million in 2017 and 2018, and $75.0 million in 2019. Deterioration of these financial ratios could result in a default under our Credit Agreement that, if not remedied, could result in termination of the Credit Agreement and acceleration of any outstanding balances. Any such default could also result in a cross-default under our 7.25% Senior Notes. The consolidated total leverage ratio and the consolidated secured leverage ratio, as both are calculated under our Credit Agreement, exclude the long-term liability for our Preferred Units in the determination of total indebtedness.

Our Credit Agreement includes other customary covenants that, among other things, limit our ability to incur additional debt, incur, or permit certain liens to exist, or make certain loans, investments, acquisitions, or other restricted payments. In addition, the Credit Agreement requires that, among other conditions, we use designated consolidated cash and cash equivalent balances in excess of $35.0 million to prepay the loans; allows the prepayment or purchase of indebtedness with proceeds from the issuances of equity securities or in exchange for the issuances of equity securities; and restricts the amount of our permitted capital expenditures in the ordinary course of business during each fiscal year ranging from $50.0 million in 2018 to $75.0 million in 2019.

The consolidated total leverage ratio and the consolidated secured leverage ratio, as both are calculated

under the Credit Agreement, exclude the long-term liability for the Preferred Units, among other items, in the

determination of total indebtedness.

We are in compliance with all covenants of our Credit Agreement, as amended, as of December 31, 2017.

We have reviewed our financial forecasts as of March 1, 2018 and for the subsequent twelve month period, which consider the impact of the Fifth Amendment to our Credit Agreement, and the current level of distributions to our common unitholders. Based on this review and the current market conditions as of March 1, 2018, we believe that despite the current industry environment and activity levels, we will have adequate liquidity, earnings, and operating

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cash flows to fund our operations and debt obligations and maintain compliance with debt covenants through March 1, 2019.

All obligations under the Credit Agreement and the guarantees of those obligations are secured, subject to certain exceptions, by a first lien security interest in substantially all of our assets and the assets of our existing and future domestic subsidiaries, and all of the capital stock of our existing and future subsidiaries (limited in the case of foreign subsidiaries, to 65% of the voting stock of first tier foreign subsidiaries).

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 the Issuers, the "Obligors"). The 7.25% Senior Notes and the subsidiary guarantees thereof (together, the "Securities") were issued pursuant to an indenture described below. As of December 31, 2017, $295.9 million in aggregate principal amount of the 7.25% Senior Notes are outstanding.

The Obligors issued the Securities pursuant to the Indenture dated as of August 4, 2014 (the "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 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 Indenture. The 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 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 and conditions of the Indenture as of December 31, 2017.

Off Balance Sheet Arrangements

As ofDecember 31, 2017, 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.

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. During 2017, there were no material changes outside of the ordinary course of business in the specified contractual obligations.

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The table below summarizes our contractual cash obligations as of December 31, 2017:

	Payments Due
	Total		2018		2019		2020		2021		2022		Thereafter
	(In Thousands)
Long-term debt	$	523,930	$	—	$	228,000	$	—	$	—	$	295,930	$	—
Interest on debt	118,363		32,762		28,926		21,253		21,253		14,169		—
Operating leases	6,025		2,567		1,450		1,169		821		18		—
Total contractual cash obligations(1)	$	648,318	$	35,329	$	258,376	$	22,422	$	22,074	$	310,117	$	—

⁽¹⁾  Amounts exclude other long-term liabilities reflected in our Consolidated Balance Sheet that do not have known cash payment streams. These excluded amounts include approximately$70.3 million carrying value of liabilities related to the Preferred Units. The Preferred Units are expected to be serviced and satisfied with non-cash paid in kind distributions and conversions to common units. See "Note E - Series A Convertible Preferred Units," in the Notes to Consolidated Financial Statements for further discussion.

Recently Issued Accounting Pronouncements

For a discussion of new accounting pronouncements that may affect our consolidated financial statements, see "Note B - 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.

Commodity PriceRisk

Market risk is the risk of loss arising from adverse changes in market rates and prices. We do not take title to any natural gas or oil in connection with our services and, accordingly, have no direct exposure to fluctuating commodity prices. While we have a significant number of customers who have retained our services through periods of high and low commodity prices, we generally experience less growth and more customer attrition during periods of significantly high or low commodity prices. For a discussion of our indirect exposure to fluctuating commodity prices, please read “Risk Factors —Certain Business Risks.”We depend on domestic and international demand for and production of natural gas and oil 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 revenues and cash available for distribution to our common unitholders to decrease in the future. We do notcurrently hedge, and do notintend to hedge, our indirect exposure to fluctuating commodity prices.

Interest Rate Risk

We have exposure to changes in interest rates on our indebtedness associated with our Credit Agreement.On December 31, 2017,we had a total of $224.0 million outstanding under our Credit Agreement.As interest charged on our Credit Agreement is based on a variablerate, we are exposed under the Credit Agreement to floating interest rate risk on outstanding borrowings. Any increase or decrease in the prevailing interest rate will impact our interest expense during periods of indebtedness under our credit facility.

The following table sets forth as of December 31, 2017, our principal cash flows for our long-term debt obligations (which bear a variable rate of interest) and weighted average effective interest rate by their expected maturity dates. We are not a party to an interest rate swap contract or other derivative instrument designed to hedge our exposure to interest rate fluctuation risk.

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	Expected Maturity Date																	Fair Market Value
	2018		2019			2020		2021		2022			Thereafter		Total
As of December 31, 2017
Long-term debt:
U.S. dollar variable rate (in 000s)	$	—	$	228,000		$	—	$	—	$	—		$	—	$	228,000		$	228,000
Weighted average interest rate	—		5.00		%	—		—		—			—		—			—
U.S. dollar fixed rate (in 000s)	—		—			—		—		295,930			—		295,930			279,700
Interest rate (fixed)	—		—			—		—		7.25		%	—		7.25		%	—

Exchange Rate Risk

We have exposure to changes in foreign exchange rates associated with our operations in Latin America and Canada. Most of our billings under our contracts with PEMEX and other customers in Mexico are denominated in U.S. dollars; however, a large portion of our expenses and costs under those contracts are incurred in Mexican pesos, and we retain cash balances denominated in Mexican pesos. As such, we are exposed to fluctuations in the value of the Mexican peso against the U.S. dollar. Before considering the impact of any derivative contracts, a hypothetical increase or decrease in the U.S. dollar-Mexican peso foreign exchange rate of 2.0% would have a $267,000 impact on our net income for the year ended December 31, 2017.

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, 2017, we had the following foreign currency derivative contract outstanding relating to a portion of our foreign operations:

	US Dollar Notional Amount		Traded Exchange Rate	Settlement Date
	(In Thousands)
Forward sale Mexican peso	$	6,067	19.28	1/18/2018

Under this program, we may enter into similar derivative contracts from time to time. Although contracts pursuant to this program will serve as an economic hedge 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 this derivative instrument during a period will be included in the determination of earnings for that period.

The fair value of foreign currency derivative instruments are based on quoted market values as reported to us by our counterparty (a Level 2 fair value measurement). The fair value of our foreign currency derivative instruments as of December 31, 2017, is as follows:

Foreign currency derivative instruments	Balance Sheet	Fair Value at
	Location	December 31, 2017
		(In Thousands)
Forward sale contracts	Current assets	$	130
	Current liabilities	(10		)
Total		$	120

None of the foreign currency derivative contracts contain credit risk related contingent features that would require us to post assets or collateral for contracts that are classified as liabilities. During the period ended December 31, 2017 we recognized approximately $38,000 of net gains associated with our foreign currency derivative program, and such amount is included in other income in the accompanying consolidated statement of operations.

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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, 2017.

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). 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, 2017, 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, 2017.

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.

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, 2017. 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 fiscal quarter ended December 31, 2017, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information.

None.

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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., a wholly owned subsidiary of TETRA, and we do not hold annual unitholder meetings for the election of our Board. 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 seven 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 Board’s directors hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been appointed. Our executive officers 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
Stuart M. Brightman	61	Chairman of the Board of Directors
Paul D. Coombs	62	Independent Director
D. Frank Harrison	70	Independent Director
James R. Larson	68	Independent Director
Brady M. Murphy	58	Director
Owen Serjeant	57	President and Director
William D. Sullivan	60	Independent Director
Elijio V. Serrano	60	Chief Financial Officer
Ronald J. Foster	61	Senior Vice President and Chief Marketing Officer
C. Brad Benge	58	Vice President of Operations
Levent Caglar	42	Vice President North America Sales, Compression Services
Miguel Luna	47	Vice President of Engineered Products Sales & International Operations
Michael E. Moscoso	52	Vice President - Finance

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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.

Stuart M. Brightman has served as a director of our general partner's Board since October 31, 2008, and as Chairman of its Board since May 2014. He also served as President of our general partner during an interim period from August 2017 until November 2017. Mr. Brightman has served as TETRA’s chief executive officer and a member of its board of directors since May 2009 and served as TETRA’s president from May 2009 until February 2018. He served as TETRA’s executive vice president and chief operating officer from April 2005 through May 2009. From April 2004 to April 2005, Mr. Brightman was self-employed. Mr. Brightman served as president of the Dresser Flow Control division of Dresser, Inc. from April 2002 until April 2004. Dresser Flow Control, which manufactures and sells valves, actuators, and other equipment and provides related technology and services for the oil and gas industry, had revenues in excess of $400 million in 2004. From November 1998 to April 2002, Mr. Brightman was president of the Americas Operation of the Dresser Valve Division of Dresser, Inc. He served in other capacities during the earlier portion of his career with Dresser, from 1993 to 1998. From 1982 to 1993, Mr. Brightman served in several financial and operational positions with Cameron Iron Works and its successor, Cooper Oil Tools. Mr. Brightman currently serves on the board of directors and as a member of the compensation and nominating and governance committees of C&J Services, Inc., a public company subject to the reporting requirements of the Exchange Act. Mr. Brightman received his B.S. degree from the University of Pennsylvania and his Master of Business Administration degree from the Wharton School of Business.

Mr. Brightman has more than 30 years of experience in manufacturing and services businesses related to the oil and gas industry. He has experience in corporate finance and in the management of capital intensive operations. Mr. Brightman’s service as TETRA’s global chief executive officer also provides our Board with an in-depth source of knowledge regarding our operations, our executive management team, and the effectiveness of our compensation programs.

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.

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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 is a current member of the American Institute of Certified Public Accountants, Financial Executives International, and the Tax Executives Institute. Mr. Larson also serves on the Board of Directors of EV Management, LLC, the general partner of EV Energy GP, L.P., which is the general partner of EV Energy Partners, L.P., a Houston-based publicly traded limited partnership engaged in acquiring, producing, and developing oil and gas properties. He received his B.B.A. 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.

BradyM. Murphy has served as a director of our general partner’s Board since February 22, 2018. Mr. Murphy has also served as the President and Chief Operating Officer of TETRA since February 12, 2018. 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 Haliburton Company and its affiliated companies for 34 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.

Owen Serjeant has served as President and a director of our general partner's Board since November 2017. Mr. Serjeant served as Group Vice President - Global Operational Support of Schlumberger Limited, a publicly traded company subject to the reporting requirements of the Securities Exchange Act of 1934, from April 2016 to November 2017. From July 1999 until April 2016, Mr. Serjeant served in various senior operations management roles with increasing responsibility, including most recently as Corporate Vice President - Global Operational Excellence and Group Vice President - Compression Systems Division, at Cameron International Corporation, a publicly traded company prior to its acquisition by Schlumberger in April 2016. Mr. Serjeant began his career with Cooper Energy Services and served in a variety of operations, engineering, marketing, and sales roles from 1981 to 1999. He earned his BSc degree in Mechanical Engineering from Aston University, United Kingdom, and his MBA degree from Henley Management College, United Kingdom.

Mr. Serjeant has significant senior management and operations experience, including in the natural gas compression industry, and provides our general partner's Board with an in-depth knowledge regarding our customers, operations, business strategies, and the markets and geographies in which we operate. Mr. Serjeant’s management experience and leadership skills are highly valuable in assessing our business strategies and accompanying risks.

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

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chairman of the board of directors of SM Energy Company, a publicly traded exploration and production company. Mr. Sullivan is also a director and serves on the audit, nominating and corporate governance and conflicts, and compensation committees of Legacy Reserves GP, LLC, the general partner of Legacy Reserves, LP, a publicly traded limited partnership holding oil and gas producing assets. 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, a publicly traded limited partnership. From 1981 through August 2003, Mr. Sullivan was employed in various capacities by Anadarko Petroleum Corporation, 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.

Mr. Sullivan has significant management experience in mid-stream 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. 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, a global project management, engineering and construction management company, 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.), a provider of enterprise software solutions to the oil and gas industry. From October 1999 through February 2006, Mr. Serrano served as chief financial officer of EGL, Inc., a publicly-traded transportation and logistics 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 by Schlumberger Ltd., including as vice president and general manager of the western hemisphere operations of Schlumberger’s Geco-Prakla seismic division (from 1997 to 1999), as group controller for the global operations of the Geco-Prakla seismic division (from 1996 to 1997), and from 1992 to 1996, as controller of various geographical units of the Geco-Prakla seismic division. 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.

C. Brad Benge has served as Vice President of Operations of our general partner since August 2014. Mr. Benge served as vice president of compression services of CSI from September 2010 through July 2014. From September 2009 to September 2010, Mr. Benge served as vice president of Eastern region compression services of CSI. Mr. Benge joined CSI in February 2008 and served as project manager until September 2009. From 1984 to 2007, Mr. Benge served in multiple roles at Exterran including; vice president of operations, multiple mergers and acquisitions positions and various supervisory positions. Mr. Benge began his career in 1979 as a natural gas compressor and engine mechanic for Halliburton in Central Texas. Mr. Benge has more than 35 years of industry experience, and he attended Tarleton State University.

Levent Caglar has served as Vice President North America Sales, Compression Services of our general partner since December 2017 and as Vice President of Fleet Management from August 2015 to December 2017. Mr. Caglar joined CSI in 2001 as an International Application Engineer and served in a variety of roles including

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Lean Six-Sigma Black Belt, Asset Manager, and Director of Rental Fleet Management Services through July 2015. Most recently he served as the company’s Director of Asset Management. Mr. Caglar holds a Bachelor of Science in Industrial Engineering from Galatasaray University, Istanbul, Turkey and a Master of Business Administration from The University of Texas at Dallas He is also an active member in the Gas Compressor Association as well as Petroleum Equipment and Service Association (PESA) Emerging Leaders Committee.

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.

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.

Board Meetings and Committees

During 2017, the Board held ten meetings. The standing committees of the Board during 2017 consisted of an Audit Committee and a Conflicts Committee. During 2017, the Audit Committee held four meetings, and the Conflicts Committee held three 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

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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 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.

Section 16(a) Beneficial Ownership Reporting Compliance

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, 2017, all Section 16(a) filing requirements applicable to our executive officers, directors, and 10% holders were complied with in a timely manner, except for the following filing: Form 4 reporting a common unit purchase by Levent Caglar (1 transaction) filed on September 27, 2017.

Item 11. Executive Compensation.

Compensation Discussion and Analysis

Our general partner is an indirect, wholly owned subsidiary of TETRA and has sole responsibility for conducting our business and managing our operations. All of our executive officers and other personnel necessary for the operation of our business are employed or compensated by our general partner, our subsidiaries, or TETRA and its subsidiaries. We may refer to such individuals as “our employees” in this Compensation Discussion and Analysis.

This Compensation Discussion and Analysis (“CD&A”) is designed to provide an understanding of our compensation philosophy and objectives and insight into the process by which our specific compensation practices are established. This CD&A is focused on the total compensation of the President and other officers of our general partner named in the Summary Compensation Table (collectively, the “Named Executive Officers” or “NEOs”) and other officers of our general partner designated as our senior managers (together with our NEOs, “Senior Management”). The Compensation Committee of TETRA’s Board of Directors (the “Compensation Committee”) is responsible for the oversight of compensation programs that apply to a broad base of our employees, and for specific compensation decisions that relate to our NEOs who are employed by our general partner. Mr. Brightman, who serves as the Chief Executive Officer of TETRA and the Chairman of the Board of Directors of our general partner, also served as our President from August 1, 2017 through November 20, 2017. Mr. Serrano, who serves as the Senior Vice President and Chief Financial Officer of TETRA, also serves as our Chief Financial Officer. Neither Mr. Brightman nor Mr. Serrano is presently, nor were either of them previously, an employee of our general partner. Mr. Brightman and Mr. Serrano’s primary business responsibilities are for TETRA and they devote less than a majority of their business time to our general partner and us. Accordingly, the Compensation Committee, acting in its capacity as such for TETRA, is responsible for establishing the compensation of Messrs. Brightman and Serrano, and we have no control over their compensation. We have not formed, and do not intend to form, a compensation committee, and for the immediate future the Board intends to continue to delegate oversight of certain aspects of our compensation programs to the Compensation Committee.

Our relationship with our general partner and TETRA relating to the personnel who operate our business is governed by the Omnibus Agreement dated June 20, 2011 and amended on June 20, 2014, among us, our general partner and TETRA (as amended, the “Omnibus Agreement”). Under the terms of the Omnibus Agreement, we reimburse our general partner and TETRA for certain expenses incurred on our behalf, including a portion of the compensation of employees of our general partner and TETRA who perform services on our behalf.

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The compensation expense allocated to us in 2017 with respect to each of our NEOs, other than Messrs. Brightman and Serrano, was 100% of their total compensation, since each of our NEOs, other than Messrs. Brightman and Serrano, devote virtually all of their business time to our operations. Under our Omnibus Agreement, certain corporate and administrative departments of TETRA allocate a percentage of their costs to us for reimbursement for services provided by them on our behalf. While the departments of Messrs. Brightman and Serrano make such an allocation under the Omnibus Agreement, no portion of such expenses is specifically based on their time and there is no reimbursement by us specifically for the cost of their services. Accordingly, the compensation disclosed herein for our NEOs other than Messrs. Brightman and Serrano reflects all of the compensation expense that is payable by us under the Omnibus Agreement with regard to such individuals. None of the cash compensation or other benefits made available to Messrs. Brightman and Serrano by TETRA were based on the specific services provided to us. Please read the section titled “Item 13. Certain Relationships and Related Transactions, and Director Independence” below for additional information regarding our reimbursement of expenses.

Executive Summary

We are a provider of compression services and equipment for natural gas and oil production, gathering, transportation, processing, and storage. We sell standard and custom-designed compressor packages and oilfield fluid pump systems, 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 foreign countries, including Mexico, Canada, and Argentina.

As a result of our relationship with TETRA, the compensation of our NEOs is structured in a manner similar to TETRA’s compensation of its executive officers. In addition, the compensation policies and practices of our general partner are similar to those of TETRA. Our compensation practices for fiscal year 2017 were strongly influenced by the unprecedented decline in oil and natural gas prices that began in June 2014 and continued through 2015 and most of 2016. The Compensation Committee gave significant weight to our 2017 results and expected activity levels in 2018 in its consideration of our executive compensation.

The following CD&A addresses our compensation practices, philosophies and objectives as they relate to our NEOs and other members of our Senior Management who are employed by our general partner. Because TETRA makes all decisions regarding the compensation for Messrs. Brightman and Serrano, those decisions are not discussed in this CD&A and unless specified to the contrary below, references in the following CD&A to “NEOs,” “executive officers,” or “Senior Management” do not include Messrs. Brightman and Serrano. The total compensation paid by TETRA to Messrs. Brightman and Serrano in 2017 will be disclosed in TETRA’s Proxy Statement for its Annual Meeting of Stockholders to be held on May 4, 2018.

Impact of the Industry Downturn on Compensation

The unprecedented and lengthy downturn experienced by the oil and gas service industry beginning in 2014 required us to take certain cost reduction actions during 2015 and 2016 that had a significant impact on several elements of Senior Management compensation. As we moved through 2017 and began to see signs of a recovery for the industry, we were able to effectively return most elements of Senior Management compensation to pre-downturn (2014) levels. In the latter half of 2017 and entering 2018, we are cognizant of the fact that our Senior Management compensation will require adjustment during 2018 in order to retain talent in the recovering market, which is characterized by a highly competitive labor market, particularly in certain geographic areas in which we operate.

• Reinstatement of Base Pay. As part of our cost reduction efforts during the downturn, in May of 2016 the Compensation Committee approved 10% reductions in the base salaries of each of our NEOs employed by us at that time. The base salaries of each of our NEOs who were subject to the reduction were reinstated in April of 2017.

• Reinstatement of Company Match under 401(K) Plan. As part of our cost reduction efforts, in May of 2016 TETRA suspended making matching contributions under the 401(K) Plan, which impacted all of our NEOs who were participants in the plan at that time. The matching contribution was reinstated for all participants in our 401(K) Plan, including our NEOs, in August of 2017.

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• Payout of 2017 Annual Cash Incentive Awards. Based on our actual 2017 performance compared to performance measures established by the Compensation Committee for our 2017 annual cash incentive awards, portions of such awards granted to certain of our NEOs were determined to be earned. The earned amounts of such annual incentive awards are expected to be paid to our NEOs on or about March 9, 2018.

Overall Compensation Structure

We seek to structure a balance between achieving positive short-term annual results and ensuring long-term viability and success by providing both annual and long-term incentive opportunities. The following graphic illustrates the components of the total compensation opportunities available to members of our Senior Management:

Key Compensation Practices and Policies

We have implemented and continue to maintain compensation practices and policies that we believe contribute to good governance.

What We Do

What We Don’t Do

þ Use performance measure to align pay with performance þ The compensation consultant is retained directly by the Compensation Committee and does not provide any services to management þ Every member of the Compensation Committee is independent as defined in the listing standards of the NYSE and NASDAQ þ We have adopted procedures for grants of equity awards that provide guidelines under which annual and other equity awards may be granted

ý Our insider trading policy prohibits transactions involving short sales, the buying or selling of puts calls or other derivative instruments, and transactions involving certain forms of hedging or monetization ý Provide tax gross-ups or executive perquisites ý Allow single-trigger severance or change of control agreements

Overview of Compensation Philosophy and Objectives

In order to recruit and retain highly qualified and competent individuals as Senior Management, we strive to maintain a compensation program that is competitive in the labor markets in which we operate. Our guiding philosophy is to maintain an executive compensation program that will attract, retain, motivate, and reward highly qualified and talented individuals to enable us to perform better than our competitors. The following are our key objectives in setting the compensation programs for our Senior Management:

• design competitive total compensation programs that enhance our ability to attract and retain knowledgeable and experienced Senior Management;

• motivate our Senior Management to deliver outstanding financial performance and meet or exceed general and specific business, operational, and individual performance objectives;

• establish salary and annual cash incentive compensation levels that reflect competitive market practices in relevant markets and are generally within the median range for the relevant peer group;

• provide long-term incentive compensation opportunities that are consistent with our overall compensation philosophy; 

• provide a significant percentage of total compensation that is “at risk,” or “variable,” based on predetermined performance measures and objectives; and

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• ensure that a significant portion of the total compensation package is determined by equity value, thus assuring an alignment of Senior Management with our unitholders.

Focus on Performance-Based Pay

In establishing target compensation levels, the Compensation Committee places a significant portion of our NEOs’ compensation “at-risk” through the use of variable compensation, much of which is performance-based. Variable pay includes the following:

• Annual Incentives - performance-based cash incentives for achievement of specified performance objectives on an annual basis.

• Performance-Based Unit Awards - performance-based equity incentives that are earned only if specified long-term performance objectives are achieved.

• Time-Based Unit Awards - time-based equity compensation, the long-term value of which depends on the market price for CCLP’s common units.

Roles and Process

Role of the Compensation Committee.Our Board has appointed the CompensationCommittee to discharge many of its responsibilities relating to the compensation of our executive officers. With regard to certain actions that must be taken directly by our Board, the Compensation Committee provides recommendations to the Board that are consistent with our compensation philosophy, programs, and objectives, which are largely a reflection of TETRA’s compensation philosophy, programs, and objectives.

The Compensation Committee has the authority to retain compensation consultants, outside counsel, or other advisers to assist the committee in the discharge of its duties. In any given year, the Compensation Committee bases its decision on whether to retain a compensation consultant on factors including prevailing market conditions, regulatory changes governing executive compensation, and the quality of any other relevant data that may be available. If a compensation consultant is engaged with respect to our compensation programs, the Chairman of the Compensation Committee maintains a direct line of communication with the consultant and arranges meetings with the consultant that may include other members of the committee and/or our President, TETRA’s CEO and certain members of TETRA’s senior management, including TETRA's President and Chief Operating Officer ("COO"). The Compensation Committee, and/or its Chairman, also periodically meets with the compensation consultant independently of management. Through this communication with the Chairman of the Compensation Committee, the consultant reports to, and acts at the discretion of, the Compensation Committee.

Role of Compensation Consultant.During 2016, the Compensation Committee retained the services of Pearl Meyer & Partners ("Pearl Meyer"), an independent provider of compensation consulting services, to assist the Compensation Committee in its review of our compensation programs. As part of the engagement, Pearl Meyer provided the Compensation Committee with an evaluation of industry trends and executive compensation issues in August of 2016 that indicated that most companies in our industry had, by that time, frozen or reduced executive base salaries.

Before engaging Pearl Meyer, the Compensation Committee confirmed that Pearl Meyer does not provide other services to us, to our general partner, or to TETRA; has procedures in place to prevent conflicts of interest; and, does not have a business or personal relationship with any of the executive officers of our general partner, any of TETRA’s executive officers, or any member of the Compensation Committee. The individual consultants involved in the engagement do not own our limited partner units, nor do they own TETRA’s common stock. The Compensation Committee discussed these considerations and concluded that there were no conflicts of interest with respect to the consulting services provided by Pearl Meyer.

Role of our President.Our President makes recommendations to the Compensation Committee with regard to salary adjustments and the annual and long-term incentives to be provided to our Senior Management, excluding himself. TETRA's COO and CEO make recommendations to the Compensation Committee with regard to salary adjustments and the annual and long-term incentives to be provided to our President. Based upon his judgment and experience and in consultation with TETRA’s COO and CEO, taking into consideration available industry-based compensation surveys and other compensation data and analysis, including data provided by the Compensation Committee’s consultant, if one is retained for that year, our President annually reviews with the Compensation Committee specific compensation recommendations for Senior Management. In preparation for

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these evaluations, the Compensation Committee reviews an annual compensation report that presents current annual base salaries, annual incentive targets, annual incentives earned and the values of outstanding equity-based and other long-term compensation, to provide the Compensation Committee with a detailed picture of how the various components of total compensation paid or to be paid to each member of Senior Management, including our President, aggregate in the current year.

In its review of the annual compensation report and its consideration of whether changes in compensation recommended by the President and TETRA's COO and CEO are in line with our overall compensation philosophy, current competitive market conditions, and current economic conditions, the Compensation Committee considers performance evaluations of and compensation recommendations for each member of Senior Management as well as its own performance evaluations of Senior Management, and, if a compensation consultant is retained for that year, the analysis and report of the compensation consultant. The Compensation Committee reviews the annual compensation report among themselves and with our President and TETRA’s CEO and approves any prospective changes in compensation for Senior Management other than our President. The Compensation Committee, in an executive session that includes TETRA’s CEO, establishes the compensation for our President.

Compensation Elements

We strongly believe that Senior Management should be compensated with a package that includes, at a minimum, the following three elements:

• salary and industry standard benefits,

• performance-based annual incentive compensation, and

• equity-based long-term incentive compensation.

A significant portion of the total prospective compensation paid to each member of Senior Management should be tied to measurable financial and operational objectives. These objectives may include absolute performance and performance relative to a peer group. During periods when performance meets or exceeds established objectives, Senior Management should be paid at or above the levels targeted for such objectives. When objectives are not met, incentive award payments, if any, should be less than levels targeted for such objectives. The Compensation Committee seeks to structure a balance between achieving strong short-term annual results and ensuring long-term viability and success. To reinforce the importance of this balance, we provide each member of Senior Management with both short-term and long-term incentives. Currently, short-term incentive opportunities for Senior Management are in the form of annual cash incentives that are based on both objective performance criteria and subjective criteria. Long-term incentives generally include equity awards that typically vest over multiple years and performance-based equity awards that vest at the end of a three-year period based on the level of attainment of established performance objectives. While the mix of salary, annual cash incentives, and long-term incentives earned by Senior Management can vary from year-to-year depending on individual performance and on our overall performance, the Compensation Committee believes that long-term incentives, the potential future value of which is heavily contingent on our long-term success, should constitute a significant portion of total compensation in any one year.

Salary.We believe that a competitive salary program and industry standard benefits are important factors in our ability to attract and retain talented Senior Management employees. The Compensation Committee typically reviews relevant compensation data and analysis provided by its compensation consultant, if one is retained for that year, or by management if no compensation consultant is engaged, to ensure that our salary program is competitive. In this respect, the Compensation Committee uses the survey data and compensation paid by peer companies as a market check on the salaries and other elements of compensation it establishes. The Compensation Committee reviews the salaries of all members of our Senior Management at least annually. Base salaries may be adjusted for performance, which may be individual or company-wide performance, expansion of duties, and changes in market salary levels. In considering salary adjustments each year, the Compensation Committee gives weight to the foregoing factors, with particular emphasis on corporate performance goals, our President’s analysis and TETRA's COO's and CEO's analysis of each individual’s performance, and their specific compensation recommendations. However, the Compensation Committee does not rely on formulas and considers all factors when considering salary adjustments.

With the exception of Mr. Serjeant who was first hired by us in November of 2017 and was not subject to the salary reduction program, salary reductions that were implemented during 2016 reducing the base salaries of our NEOs by 10% were still in effect as we entered 2017. On April 1, 2017, the base salary of each of our NEOs

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who was subject to the 2016 reduction was reinstated. The table below sets forth the base salaries that were in effect for our NEOs as of December 31, 2017. Mr. Knox, our former President, and Mr. Coffie, our former Chief Financial Officer, were no longer employed by us as of year end.

Name	Title	Base Salary as of December 31, 2017
Owen Serjeant	President	$	410,000
Ronald J. Foster	Sr. Vice President & Chief Marketing Officer	325,000
C. Brad Benge	Vice President of Operations	240,000
Levent Caglar	Vice President North America Sales, Compression Services	249,000
Timothy A. Knox	Former President	n/a
Derek C. Coffie	Former Chief Financial Officer	n/a

Annual Performance-Based Cash Incentives.Our NEOs and other key employees are eligible to receive annual performance-based cash incentive awards pursuant to TETRA’s Cash Incentive Compensation Plan. The Cash Incentive Compensation Plan was adopted by TETRA’s Board of Directors toprovide greater focus on TETRA’s strategic business objectives, further its compensation philosophy, emphasize pay-for-performance, and provide competitive compensation opportunities.

Each member of our Senior Management is provided with an annual, performance-based incentive opportunity, calculated as a percentage of base salary. For each award opportunity, a threshold, target, stretch, and over achievement performance objective is established for each applicable performance measure and the amount of the award payment that may be received is based on the level of achievement of such performance objectives, subject to the discretion of the Compensation Committee.

As part of its December 2016 review of the compensation of our NEOs, the Compensation Committee reviewed a preliminary estimate of the aggregate amount of annual cash incentive compensation to be awarded under TETRA’s Cash Incentive Compensation Plan based on 2016 performance, and discussed the overall effectiveness of the plan in furthering our compensation philosophy. In its consideration of changes for the 2017 plan year, the Compensation Committee gave significant weight to the impact of the prolonged downturn on our industry, and elected not to make changes to the award opportunities available to our NEOs for the 2017 plan year.

The following table sets forth the award opportunities for the 2017 plan year, shown as a percentage of base salary for certain of our NEOs under the Cash Incentive Compensation Plan. Mr. Serjeant, who was not employed by us until November of 2017, did not receive an award opportunity for the 2017 performance period. Mr. Knox, our former President, and Mr. Coffie, our former Chief Financial Officer, were no longer employed by us as of year end 2017.

2017 Award Opportunities - Annual Cash Incentive Compensation Plan
	Threshold		Target		Stretch		Over Achievement
Owen Serjeant	—	%	—	%	—	%	—	%
Ronald J. Foster	14	%	45	%	23	%	90	%
C. Brad Benge	11	%	35	%	18	%	70	%
Levent Caglar	11	%	35	%	18	%	70	%
Timothy A. Knox	18	%	60	%	30	%	120	%
Derek C. Coffie	11	%	35	%	18	%	70	%

The Compensation Committee may establish both financial and non-financial performance measures each year. As part of our ongoing efforts to build a robust culture of performance and a customer-centric environment, each performance measure under the 2017 plan was aligned to one of our four CØRE categories:

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Ÿ Customers Ÿ Drive to ZERØ Ÿ Returns Ÿ Employees

Under the Cash Incentive Compensation Plan for 2017, actual results for the Adjusted EBITDA performance measure must reach a minimum threshold level of 80% of the established target performance objective for any payments to be earned; below that level of performance, no amount may be paid for any performance measure other than Individual Performance Objectives (IPOs). In addition, if actual results for the Adjusted EBITDA performance measure did not exceed 100% of the target performance objective, no other performance measure could be earned above the target level, regardless of actual results. A threshold payment level of 30% corresponds to the threshold performance level of 70 - 80% of each established performance objective (with the exception of performance measures in the Drive to Zero category, for which no payment is earned for results below the target performance level); for actual results that fall between threshold and target, straight line interpolation is used to determine the earned amount of the award. The following table shows each performance measure for our NEOs, the CØRE strategy to which it aligns, the target performance objective under our 2017 annual incentive plan, our 2017 results, the percentage of the target performance objective attained, and the resulting percentage of the award deemed to have been earned based on 2017 results and the performance criteria discussed above.

	Strategy	Performance Measure	Target Performance Objective	Result of 2017 Performance Period	% of Target Attained(1)	% of Target Earned(1)
CUSTOMERS	Develop new business, retain customers and manage price to protectmarket share	New AMS Parts & Business	$4.0 million	$7.8 million	196.1%	100.0%
		New Unit Sales	$47.8 million	$38.4 million	80.3%	54.1%
		Fleet Utilization	83.7% by year-end	83.2%	99.4%	95.8%
DRIVE to ZERØ	Change behaviors, identify hazards, and manage risks to Drive to Zero incidents	TRIR(2)	0.93	1.76	0.0%	0.0%
		CVIR(2)	0.56	0.48	114.3%	100%
		BBO Participation(2)	75%	91%	121.3%	100%
RETURNS	Identify synergies, optimize costs and leverage to safeguard profitability	Adjusted EBITDA	$93.8 million	$81.1 million	86.5%	52.7%
		Distributable Cash Flow	$54.0 million	$31.8 million	58.5%	0.0%
EMPLOYEES	Train, retain, and recognize high value employees to improve performance	Retention	90% of high value employees	100% retention	100.0%	100.0%
		Performance Review	Annual Review	100.0% completion	100.0%	100.0%
		Training	1 training completed per qtr, per employee	Better than 90% of employees completed each quarterly training	100.0%	100.0%

(1) Performance measures that were attained above the target (100%) performance level were capped at target payout under the performance criteria described above. For performance measures attained below the target (100%) performance level, straight line interpolation was used to determine the percentage of target earned.

(2) Total Recordable Incident Rate, Chargeable Vehicle Incident Rate, and Behavioral Based Observation Participation

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The relative weight of specific performance measures varies based on each participant's responsibilities; however, for each NEO, performance measures in the Returns category comprise 60 - 70% of the total target annual incentive, reflecting our NEOs’ significant focus on generating strong financial returns. Individual performance objectives (“IPOs”) for each NEO are aligned to the CØRE strategies and were approved by the Compensation Committee in February of 2017. The following tables show the weight of each performance measure, the percentage of the award deemed to have been earned based on 2017 results and the performance criteria discussed above, and the amount of the award opportunity earned related to each performance measure. Messrs. Knox and Coffie, who were no longer employed by us at year end, did not receive award payments.

	Target Amount of Award Opportunity		Weight of Metric	% of Target Earned	Weighted % Earned	Amount of Award Earned
Ronald J. Foster	$	146,250
Distributable Cash Flow			50.0%	—%	—%	$	—
Adjusted EBITDA			20.0%	52.7%	10.6%	$	15,503
Fleet Utilization			3.3%	95.8%	3.2%	$	4,651
New Unit Sales			3.3%	54.1%	1.8%	$	2,618
New AMS Parts & Business			3.3%	100.0%	3.3%	$	4,826
TRIR			1.7%	—%	—%	$	—
CVIR			1.7%	100.0%	1.7%	$	2,442
BBO Participation			1.7%	100.0%	1.7%	$	2,442
High Value Retention			1.7%	100.0%	1.7%	$	2,442
Training			1.7%	100.0%	1.7%	$	2,442
Performance Review			1.7%	100.0%	1.7%	$	2,442
IPOs			10.0%	90.0%	9.0%	$	13,163
			100.0%			$	52,972

	Target Amount of Award Opportunity		Weight of Metric	% of Target Earned	Weighted % Earned	Amount of Award Earned
C. Brad Benge	$	84,000
Distributable Cash Flow			45.0%	—%	—%	$	—
Adjusted EBITDA			15.0%	52.7%	7.9%	$	6,644
Fleet Utilization			3.3%	95.8%	3.2%	$	2,671
New Unit Sales			3.3%	54.1%	1.8%	$	1,512
New AMS Parts & Business			3.3%	100.0%	3.3%	$	2,797
TRIR			3.3%	—%	—%	$	—
CVIR			3.3%	100.0%	3.3%	$	2,797
BBO Participation			3.3%	100.0%	3.3%	$	2,797
High Value Retention			1.7%	100.0%	1.7%	$	1,403
Training			1.7%	100.0%	1.7%	$	1,403
Performance Review			1.7%	100.0%	1.7%	$	1,403
IPOs			15.0%	90.0%	13.5%	$	11,340
			100.0%			$	34,768

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	Target Amount of Award Opportunity		Weight of Metric	% of Target Earned	Weighted % Earned	Amount of Award Earned
Levent Caglar	$	87,150
Distributable Cash Flow			45.0%	—%	—%	$	—
Adjusted EBITDA			15.0%	52.7%	7.9%	$	6,894
Fleet Utilization			3.3%	95.8%	3.2%	$	2,771
New Unit Sales			3.3%	54.1%	1.8%	$	1,569
New AMS Parts & Business			3.3%	100.0%	3.3%	$	2,902
TRIR			3.3%	—%	—%	$	—
CVIR			3.3%	100.0%	3.3%	$	2,902
BBO Participation			3.3%	100.0%	3.3%	$	2,902
High Value Retention			1.7%	100.0%	1.7%	$	1,455
Training			1.7%	100.0%	1.7%	$	1,455
Performance Review			1.7%	100.0%	1.7%	$	1,455
IPOs			15.0%	90.0%	13.5%	$	11,765
			100.0%			$	36,071

Long-Term Incentive Awards.Equity incentives consisting primarily of awards of phantom units and performance phantom units comprise a significant portion of our NEOs’ total compensation package. The Compensation Committee seeks to strike a balance between achieving short-term annual results and ensuring strong long-term success through its use of equity awards, which are geared toward longer-term performance as they generally, though not always, vest ratably over a three-year period, and their values are materially affected by market price appreciation of the underlying security. We believe that tying a significant portion of the compensation of our Senior Management team directly to our unitholders’ returns is an important aspect of our total compensation plan.

The following table summarizes the elements of our long-term incentive ("LTI") program and their alignment with our compensation principles:

Component of LTI Program	Terms	Alignment with Compensation Principles
Performance Phantom Units (50% of LTI mix)	Ÿ 3-year performance period Ÿ Target award amounts denominated in units Ÿ Payout range is 0% to 200% of target award Ÿ Performance determined by pre-established 3-year financial metric approved by the Compensation Committee and the Board of our general partner	Ÿ Long-term, performance-based phantom units work in conjunction with annual awards of time-based units to provide us with increased retention value and reward participants for both improved financial results and improvement in the market price for our units.
Time-Based Phantom Units (50% of LTI mix)	Ÿ Units vest in equal installments over 3-year period, subject to continued service	Ÿ Time-based phantom units are a key element in aligning our Senior Management's interests with those of our unitholders.

2017 LTI Awards

While the Compensation Committee does consider the general compensation practices of other companies in the oil and gas services industry in establishing equity incentive compensation opportunities, it does not specifically benchmark the value of equity awards relative to any survey, peer group, or other compensation data. The Compensation Committee does, however, annually review the equity compensation practices of other companies in our industry in order to gain a general impression of the proportionate share of equity award value in the total compensation packages they offer.

The following table sets forth the number of time-based phantom units and/or performance-based phantom units awarded to our NEOs, other than Mr. Serjeant, in February 2017, and the time-based phantom units awarded to Mr. Serjeant as an inducement to his employment with us in November 2017. The aggregate grant date fair value of these awards was determined in accordance with FASB ASC Topic 718.

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	Number of Time-Based Phantom Units	Number of Performance-Based Phantom Units	Aggregate Grant Date Fair Value Of Unit Awards
Owen Serjeant	94,697	—	$	500,000
Ronald J. Foster	2,804	2,804	$	60,342
C. Brad Benge	7,010	7,010	$	150,855
Levent Caglar	5,608	5,608	$	120,684
Timothy A. Knox	21,029	21,029	$	452,544
Derek C. Coffie	4,206	4,206	$	90,513

Three-Year Performance Phantom Unit Awards Granted in 2015. In May 2015, our Board approved awards of performance-based phantom units with tandem distribution equivalent rights ("DERs") to certain officers as of such date, including Mr. Foster. The performance-based phantom unit awards covered the performance period of January 1, 2015 through December 31, 2017 and under such awards, up to 200% of the "Target" number of phantom units granted under the award could be earned based on our three-year cumulative distributable cash flow ("DCF") per outstanding unit for the performance period ending December 31, 2017, relative to the following performance objectives established by our Board:

3-Year Cumulative DCF per Outstanding Unit	Percentage of Phantom Units Earned
Less than $6.78	—%
$6.78	50%
$7.98 (Target)	100%
$10.37	150%
> $11.97 (Maximum)	200%

For DCF per outstanding unit amounts that fell between any of the performance objectives set forth above, straight line interpolation was to be used to determine the specific number of phantom units earned. In February of 2018, our Board determined that the required threshold performance objective for the three-year cumulative DCF per outstanding unit performance measure had not been met, and based on such determination, none of the units awarded had been earned.

CEO Pay Ratio

Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, require disclosure regarding the relationship of the annual compensation of our employees and the annual compensation of our Chief Executive Officer. As discussed in the "About CSI Compressco LP" and "Employees" sections under Part I, Item 1 of this Form 10-K, we have no employees. Nonetheless, in an effort to comply with this requirement, the pay ratio provided below has been calculated as the total 2017 annual compensation for Mr. Serjeant, divided by the total annual compensation of the median employee providing services to us pursuant to the Omnibus Agreement.

We used a consistently applied compensation measure to identify the median of the annual total compensation of all the employees of our general partner, and to determine the annual total compensation of the President of our general partner, Mr. Serjeant. To make them comparable, salaries for newly hired employees who had worked less than a year (including the salary of Mr. Serjeant), were annualized, and the target annual bonus amount was applied to their total compensation measure. For 2017:

Ÿ Median employee total annual compensation	$79,664
Ÿ Mr. Serjeant's total annual compensation	$1,297,000
Ÿ Ratio of President to median employee compensation	16.3 to 1

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To identify the median of the annual total compensation of all employees of our general partner and the median employee's total compensation, we took the following steps:

• We determined that our employee population as of December 31, 2017, consisted of approximately 632 full- and part-time employees located in the U.S. and Canada (we do not have temporary or seasonal workers).

• We selected December 31, 2017 as our identification date for determining our median employee because it enabled us to make such identification in a reasonably efficient and economic manner.

• For our employees located in Canada and paid in Canadian currency, we converted each such employee's total annual compensation as of December 31, 2017 to U.S. dollars; however, we did not make any cost of living adjustments with respect to either Canadian or U.S. employees.

Tax Deductibility of Compensation

With respect to the deduction limitations under Section 162(m) ofthe Code, we are a limited partnership and do not meet the definition of a “corporation” under Section 162(m). Nonetheless, the taxable compensation paid to each of the NEOs in 2017 was less than the Section 162(m) threshold of $1,000,000.

Retirement, Health and Welfare Benefits

Our employees, as employees of a TETRA affiliate, are eligible to participate in a variety of health and welfare and retirement programs. TETRA is the sponsor of each of these benefit programs.Members of our Senior Management are generally eligible for the same benefit programs on the same basis as the broad-base 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.Due to our relationship with TETRA, 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 6% of a participant’s annual compensation that is contributed to the 401(k) Plan; however, in connection with other cost reduction efforts, the matching contribution was suspended from May of 2016 through August of 2017. All employees (other than nonresident aliens) who have reached the age of eighteen and have completed six months of service with us are eligible to participate in the 401(k) Plan.

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 2017.

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. Messrs. Knox (during the time in 2017 when we was our President), Foster, Benge, and Caglar receive car allowances or are entitled to the use of a company-owned vehicle, as is the case for all of our sales and field service personnel. In September of 2016, Mr. Knox began receiving a monthly housing allowance that was to be paid for one year (until September 2017) to assist in his transition to The Woodlands facility. During 2017, except for Mr. Knox's temporary

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housing allowance and the car allowances (or the use of a company-owned car) for Messrs. Knox, Foster, Benge, and Caglar, 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

Effective August 4, 2014, in connection with the acquisition of CSI, we entered into Employment Agreements with Messrs. Knox, Foster, and Benge. Each of these Employment Agreements expired during 2017 and is no longer in effect. We also entered into a Change of Control Agreement with Mr. Knox that has been terminated and is no longer in effect. Separately, we have entered into Change of Control Agreements with Messrs. Serjeant and Foster that are further described below.

Double Trigger Change of Control Agreements

We have entered into change of control agreements (the “COC Agreements”) with Messrs. Serjeant and Foster. The COC Agreements have an initial two-year term, with automatic one-year extensions on the second anniversary of the effective date and every anniversary date thereafter, unless a cancellation notice is given at least 90 days prior to the expiration of the then applicable term. Under the COC Agreements, we have an obligation to provide certain benefits to each applicable NEO 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 COC Agreements includes the termination of the NEO's employment with us other than for Cause (as that term is defined in the COC Agreement) or termination by the NEO for Good Reason (as that term is defined in the COC Agreement). For an overview of the specific terms and conditions of the COC Agreements, please read the section titled "Potential Payments upon a Change of Control or Termination" in this Item 11, below.

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 Certificate 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. Brightman, Coombs, Murphy, Serrano, 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.

Compensation Committee Report

Our general partner, CSI Compressco GP Inc., does not have a compensation committee. The Board of Directors of CSI Compressco GP Inc., the general partner of CSI Compressco LP, has reviewed and discussed the Compensation Discussion and Analysis with management and, based upon such review and discussion, has approved the Compensation Discussion and Analysis for inclusion in this Annual Report on Form 10-K.

Submitted by the Board of Directors of CSI Compressco GP Inc.,

Stuart M. Brightman, Chairman

Paul D. Coombs            Brady M. Murphy

D. Frank Harrison            Owen A. Serjeant

James R. Larson            William D. Sullivan

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Compensation of Executive Officers

Summary Compensation

The following table sets forth the compensation earned by (i) our President (“Principal Executive Officer”), (ii) our former Presidents, who served as Principal Executive Officers for portions of 2017, (iii) our Chief Financial Officer (“Principal Financial Officer”), (iv) our former Chief Financial Officer, who served as the Principal Financial Officer for a portion of 2017, and (iv) each of our three other most highly compensated executive officers (each a “Named Executive Officer”) for the fiscal year ended December 31, 2017.

Summary Compensation Table 

Name and Principal Position	Year	Salary			Bonus			Unit Awards(1)		Non-Equity Incentive Plan Comp.			All Other Comp.(2)			Total
		($)			($)			($)		($)			($)			($)
Owen A. Serjeant(3)	2017	$	39,423		$	—		$	500,000	$	—		$	—		$	539,423
President
Elijio V. Serrano	2017	(4		)	(4		)	$	—	(4		)	(4		)	$	—
Chief Financial Officer	2016	(4		)	(4		)	225,628		(4		)	(4		)	225,628
	2015	(4		)	(4		)	375,019		(4		)	(4		)	375,019
C. Brad Benge(5)	2017	$	233,538		$	100,000		$	150,855	$	34,768		$	76,338		$	595,499
VP of Operations	2016	225,231			—			142,505		—			16,290			384,026
	2015	240,000			—			117,066		49,014			17,729			423,809
Ronald J. Foster	2017	$	316,250		$	—		$	60,342	$	52,972		$	126,516		$	556,080
SVP, Chief Marketing Officer	2016	300,813			—			71,261		—			60,329			432,403
	2015	325,000			—			162,604		73,856			45,347			606,807
Levent Caglar	2017	$	226,330		$	—		$	120,684	$	36,071		$	10,721		$	393,806
VP NA Sales, Comp. Serv.	2016	183,011			—			95,003		—			33,075			311,089
Timothy A. Knox	2017	$	288,846		$	—		$	452,544	$	—		$	205,744		$	947,134
Former President (PEO)	2016	328,769			—			427,514		—			41,628			797,911
	2015	400,000			—			450,006		121,200			25,065			996,271
Stuart M. Brightman	2017	(4		)	(4		)	$	—	(4		)	(4		)	$	—
Former President (PEO)	2016	(4		)	(4		)	625,002		(4		)	(4		)	625,002
	2015	(4		)	(4		)	884,031		(4		)	(4		)	884,031
Derek C. Coffie(6)	2017	$	59,946		$	—		$	90,513	$	—		$	—		$	150,459
Former Chief Financial Officer	2016	129,808			—			200,001		—			59,580			389,389

(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, 2017, 2016, and 2015, 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 2017 performance phantom unit awards assuming achievement of the maximum performance level would be: Mr. Benge, $150,855; Mr. Foster, $60,342; Mr. Caglar, $120,684; Mr. Knox, $452,544; and Mr. Coffie, $90,513. Phantom unit awards and performance phantom unit awards granted under the CSI Compressco equity plan on February 24, 2017 relate to our common units and are valued at $10.76 per common unit in accordance with FASB ASC Topic 718. The phantom unit award granted to Mr. Serjeant on November 20, 2017 is valued at $5.28 per common unit in accordance with FASB ASC Topic 718. Each phantom unit award granted on February 24, 2017 and November 20, 2017 was granted in tandem with distribution equivalent rights (“DERs”) that entitle the award holder

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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.

(2) The amounts reflected represent: (i) matching contributions under our 401(k) Retirement Plan; (ii) for Messrs. Knox, Benge, Foster, and Caglar, 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 $71,105 for Mr. Benge, $124,253 for Mr. Foster, $4,555 for Mr. Caglar, and $172,599 for Mr. Knox in 2017; (iii) for Messrs. Benge, Foster, Caglar, and Knox, a car allowance for the use of a company-owned vehicle; (iv) for Mr. Knox in 2016 and 2017, the aggregate value of his monthly housing allowance, which was $30,875 in 2017; (v) and for Mr. Coffie in 2016, a relocation allowance under the terms of his initial offer of employment with us.

(3) Mr. Serjeant was first employed by us on November 20, 2017. Prior period information is not applicable.

(4) The compensation of Mr. Brightman, the CEO of TETRA ,and Mr. Serrano, the Sr. Vice President and Chief Financial Officer of TETRA, is determined by TETRA. As noted above, no compensation has been reported for Messrs. Brightman and Serrano other than grants of phantom unit awards in 2015 and 2016 because none of their 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 either Mr. Brightman or Mr. Serrano. The phantom units awarded to Messrs. Brightman and Serrano in 2015 and 2016 are also included in the Summary Compensation Table of TETRA's Proxy.

(5) The amount included in the "Bonus" column for Mr. Benge in 2017 is the first of two cash retention awards payable to Mr. Benge under the terms of the cash retention award letter date May 15, 2017. The second payment under such letter, in the amount of $200,000, is payable to Mr. Benge on May 15, 2018.

(6) Mr. Coffie was first employed by us on June 20, 2016. Prior period information is not applicable.

Grants of Plan Based Awards

The following table discloses the actual number of phantom unit awards and performance phantom unit awards granted under the CSI Compressco LP Amended and Restated 2011 Long Term Incentive Plan during the fiscal year ended December 31, 2017 to each Named Executive Officer, including the grant date fair value of these awards, and the threshold, target, and maximum amounts of the annual non-equity (cash) incentive granted under TETRA’s Cash Incentive Compensation Plan during the fiscal year ended December 31, 2017 to each Named Executive Officer.

Grants of Plan Based Awards Table

			Estimated Possible Payouts Under Non-Equity Incentive Plan Awards(1)						Estimated Future Payouts Under Equity Incentive Plan Awards(2)			All Other Stock Awards: Number of Units	Grant Date Fair Value of Stock and Option Awards(3)
Name	Grant Date		Threshold		Target		Maximum		Threshold	Target	Maximum
			($)		($)		($)		(#)	(#)	(#)	(#)	($)
Owen A. Serjeant	11/20/2017	(4)										94,697	$	500,000
Elijio V. Serrano													$	—
C. Brad Benge	2/22/2017	(1)	$	25,200	$	84,000	$	168,000
	2/24/2017	(5)							701	7,010	14,020		$	75,428
	2/24/2017	(6)										7,010	$	75,428
Ronald J. Foster	2/22/2017	(1)	$	43,875	$	146,250	$	292,500
	2/24/2017	(5)							280	2,804	5,608		$	30,171
	2/24/2017	(6)										2,804	$	30,171
Levent Caglar	2/22/2017	(1)	$	26,145	$	87,150	$	174,300
	2/24/2017	(5)							561	5,608	11,216		$	60,342
	2/24/2017	(6)										5,608	$	60,342
Timothy A. Knox	2/22/2017	(1)	$	72,000	$	240,000	$	480,000
	2/24/2017	(5)							2,103	21,029	42,058		$	226,272
	2/24/2017	(6)										21,029	$	226,272
Stuart M. Brightman													$	—
Derek C Coffie	2/22/2017	(1)	$	26,250	$	87,500	$	175,000
	2/24/2017	(5)							421	4,206	8,412		$	45,257
	2/24/2017	(6)										4,206	$	45,257

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(1) The estimated possible payouts under non-equity incentive plan awards granted on February 22, 2017 are the threshold, target, and maximum amounts of the annual cash incentive granted for 2017 performance under TETRA’s Cash Incentive Compensation Plan. The actual amounts of annual cash incentive earned for 2017 performance, but unpaid as of the date of this filing, are as follows: Mr. Benge, $34,768; Mr. Foster, $52,792; and Mr. Caglar, $36,071. Messrs. Knox and Coffie, who were no longer employed by us as of year end 2017, did not earn an annual cash incentive for the 2017 performance period.

(2) The equity incentive plan awards granted on February 24, 2017 are the threshold, target, and maximum numbers of our common units that may be earned under performance phantom unit awards granted under the CSI Compressco equity plan. "Threshold" is the lowest possible payout (10% of the award) and "maximum" is the highest possible payout (200% of the award).

(3) The FASB ASC Topic 718 value of the phantom unit and performance phantom unit awards granted under the CSI Compressco equity plan on February 24, 2017 is $10.76 per unit. The FASB ASC Topic 718 value of the phantom unit award granted under the CSI Compressco equity plan on November 20, 2017 is $5.28 per unit. Performance phantom units are shown at target value.

(4) The phantom unit award granted under the CSI Compressco equity plan on November 20, 2017 vests over a three-year period at a rate of one-third per year beginning on the first anniversary date of the award based on continued employment over such three-year period.

(5) Performance phantom unit awards granted on February 24, 2017 may be earned under the CSI Compressco equity plan based on the level of achievement of the cumulative distributable cash flow per outstanding unit performance objective for the three-year performance period ending on December 31, 2019. Each performance phantom unit award was granted in tandem with 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.

(6) Phantom unit awards granted under the CSI Compressco equity plan on February 24, 2017 vest over a three-year period at a rate of one-third per year beginning on the first anniversary date of the award based on continued employment over such three-year period.

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, 2017 for each Named Executive Officer. The table also discloses the number and value of unvested phantom unit awards granted under the CSI Compressco LP Amended and Restated 2011 Long Term Incentive Plan as of December 31, 2017.

Outstanding Equity Awards at Fiscal Year End Table

	Option Awards(1)					Unit Awards
	Number of Securities Underlying Unexercised Options		Option Exercise Price		Option Expiration Date	Number of Units that Have Not Vested		Market Value of Units that Have Not Vested(2)		Equity Incentive Plan Awards: Number of Unearned Units that Have Not Vested(3)		Equity Incentive Plan Awards: Market Value or Payout Value of Unearned Units that Have Not Vested(3)
Name	Options Exercisable	Options Unexercisable
	(#)	(#)	($/Share)			(#)		($)		(#)		($)
Owen A. Serjeant						94,697	(4)	$	517,993
Elijio Serrano(5)						6,984	(6)	$	38,202	26,989	(7)	$	147,630
C. Brad Benge						908	(8)	$	4,967
C. Brad Benge						5,682	(9)	$	31,081	8,523	(7)	$	46,621
C. Brad Benge						7,010	(10)	$	38,345	7,010	(11)	$	38,345
Ronald J. Foster	8,000	—	$	21.10	5/20/2018
Ronald J. Foster	31,500	—	$	4.17	4/9/2019
Ronald J. Foster	14,500	—	$	10.20	5/20/2020
Ronald J. Foster						1,262	(8)	$	6,903
Ronald J. Foster						2,841	(9)	$	15,540	4,262	(7)	$	23,313
Ronald J. Foster						2,804	(10)	$	15,338	2,804	(11)	$	15,338
Levent Caglar						667	(8)	$	3,648
Levent Caglar						3,788	(9)	$	20,720	5,682	(7)	$	31,081
Levent Caglar						5,608	(10)	$	30,676	5,608	(11)	$	30,676
Stuart M. Brightman(5)						13,967	(6)	$	76,399	74,761	(7)	$	408,943

(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

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by $5.47, the closing price of our common units on December 29, 2017.

(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 $5.47, the closing price of our common units on December 29, 2017.

(4) One-third portions of the phantom unit award granted on November 20, 2017 will vest on November 20, 2018, November 20, 2019, and November 20, 2020.

(5) The table above includes only the outstanding equity awards held by Messrs. Serrano and Brightman in the Partnership. Outstanding equity awards held by Messrs. Serrano and Brightman in TETRA will be reflected in TETRA’s 2018 Proxy Statement.

(6) The phantom unit award will cliff-vest on May 4, 2018.

(7) The performance phantom unit award for the performance period of January 1, 2016 through December 31, 2018 may be settled pursuant to the terms of the award in March of 2019 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) The remaining one-third portion of the unvested phantom unit award granted on May 4, 2015 will vest on May 4, 2018.

(9) One-third portions of the remaining unvested phantom unit award granted on May 2, 2016 will vest on May 2, 2018, and May 2, 2019.

(10) One-third portions of the unvested phantom unit award granted on February 24, 2017 will vest on February 24, 2018, and February 24, 2019.

(11) The performance phantom unit award for the performance period of January 1, 2017 through December 31, 2019 may be settled pursuant to the terms of the award in March of 2020 if applicable performance objectives are met. The number of units shown is the target number of units that may be issued under the award.

Option Exercises and Stock Vested

The following table sets forth certain information regarding phantom unit awards and performance phantom unit awards under the CSI Compressco LP Amended and Restated 2011 Long Term Incentive Plan that became vested or were earned for each of our Named Executive Officers during the fiscal year ended December 31, 2017.

Option Exercises and Stock Vested Table 

	Option Awards			Unit Awards(1)
Name	Number of Shares Acquired on Exercise	Value Realized on Exercise		Number of Units Acquired on Vesting	Value Realized on Vesting
	(#)	($)		(#)	($)
Owen A. Serjeant	—	$	—	—	$	—
Elijio V. Serrano	—	$	—	—	$	—
C. Brad Benge	—	$	—	32,806	$	160,305
Ronald J. Foster	—	$	—	54,490	$	258,757
Levent Caglar	—	$	—	3,185	$	23,559
Tim Knox	—	$	—	80,742	$	404,627
Stuart M. Brightman	—	$	—	—	$	—
Derek C. Coffie	—	$	—	—	$	—

(1) Includes the number and value of units issued pursuant to DERs settled in tandem with phantom unit awards.

(2) The table above reflects only the activity of Messrs. Serrano and Brightman with respect to equity awards granted by the Partnership. Any activity with respect to TETRA’s equity awards will be reflected in TETRA’s 2018 Proxy Statement.

Nonqualified Deferred Compensation

TETRA maintains the TETRA Technologies, Inc. Executive Nonqualified Excess Plan, an unfunded, nonqualified deferred compensation plan that allows participants to defer a portion of their base salaries and performance-based compensation. As of December 31, 2017, none of the Named Executive Officers had elected to participate in this plan.

Potential Payments upon a Change of Control or Termination

Effective August 4, 2014, in connection with the acquisition of CSI, we entered into Employment Agreements with Messrs. Knox, Foster, and Benge. Each of these Employment Agreements has expired and is no longer in effect. We also entered into a Change of Control Agreement with Mr. Knox that has been terminated and

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is no longer in effect. Separately, we have entered into Change of Control Agreements with Messrs. Serjeant and Foster that are further described below.

Under the CSI Compressco LP 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.

Change of Control Agreement with Mr. Serjeant. We have entered into a change of control agreement with Mr. Serjeant (the “Serjeant COC Agreement”). The Serjeant 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 Serjeant COC Agreement, we have an obligation to provide certain benefits to Mr. Serjeant upon a qualifying termination event that occurs in connection with or within two years following a “change of control” of CSI Compressco LP or TETRA. A qualifying termination event under the Serjeant COC Agreement includes the termination of Mr. Serjeant’s employment by us other than for “Cause” (as that term is defined in the Serjeant COC Agreement) or termination by Mr. Serjeant for “Good Reason” (as that term is defined in the Serjeant COC Agreement).

Under the Serjeant 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. Serjeant the following cash severance amounts: (i) (A) an amount equal to Mr. Serjeant’s earned but unpaid Annual Bonus (as that term is defined in the Serjeant COC Agreement) attributable to the immediately preceding calendar year and earned but unpaid Long Term Bonus (as that term is defined in the Serjeant 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. Serjeant 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. Serjeant’s prorated target Annual Bonus for the current year, plus (C) an amount equal to Mr. Serjeant’s target Long-Term Bonus for each outstanding award; plus (ii) the product of two times the sum of Mr. Serjeant’s Base Salary (as that term is defined in the Serjeant COC Agreement) 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. Serjeant 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 TETRA's group health plan for Mr. Serjeant and his eligible dependents without subsidy from us for a period of two years following the date of his qualifying termination event. The Serjeant COC Agreement also provides for full acceleration of vesting of any outstanding restricted unit awards, phantom unit awards, and other unit-based awards upon any qualifying termination event to the extent permitted under the applicable plan. All payments and benefits due under the Serjeant COC Agreement are conditioned upon the execution and non-revocation by Mr. Serjeant of a release for our benefit. All payments under the Serjeant 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 Serjeant COC Agreement also contains certain confidentiality provisions and related restrictions applicable to Mr. Serjeant. In addition to restrictions upon improper disclosure and use of Confidential Information (as defined in the Serjeant COC Agreement), Mr. Serjeant 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 Serjeant COC Agreement. Such obligations are only binding on Mr. Serjeant if he receives the severance benefits described above.

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).

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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 Change of Control Agreements with Messrs. Serrano and Brightman, which were in effect during 2017. Payments and benefits under the TETRA Change of Control Agreements are triggered only on a change of control of TETRA. The terms of the TETRA Change of Control Agreements and a quantification of potential benefits to Messrs. Serrano and Brightman under the TETRA Change of Control Agreements will be disclosed in TETRA’s 2018 Proxy Statement.

The following table quantifies the potential payments to Named Executive Officers who were employed by us as of December 31, 2017, under the contracts, agreements, or plans discussed above in various scenarios involving a change of control or termination of employment, assuming a December 31, 2017 termination date. In addition to the amounts reflected in the table, the Named Executive Officers would receive upon termination any salary earned through December 31, 2017, and any benefits they would otherwise be entitled to under TETRA's 401(k) Plan.

Name	Cash Severance Payment		Bonus Payment		Accelerated Vesting of Unit Awards(1)		Continuation of Health Benefits		Total
Owen A. Serjeant
Death/disability	$	—	$	—	$	517,993	$	—	$	517,993
Retirement	—		—		517,993		—		517,993
Termination for Cause	—		—		—		—		—
Termination for no cause or good reason	—		—		—		—		—
Termination upon a change of control(2)	1,394,000		—		517,993		33,954		1,945,947

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Name	Cash Severance Payment		Bonus Payment		Accelerated Vesting of Unit Awards(1)		Continuation of Health Benefits		Total
C. Brad Benge
Death/disability	$	—	$	—	$	159,358	$	—	$	159,358
Retirement	—		—		159,358		—		159,358
Termination for Cause	—		—		—		—		—
Termination for no cause or good reason	—		—		—		—		—
Termination upon a change of control	—		—		159,358		—		159,358
Ronald J. Foster
Death/disability	$	—	$	—	$	76,432	$	—	$	76,432
Retirement	—		—		76,432		—		76,432
Termination for Cause	—		—		—		—		—
Termination for no cause or good reason	—		—		—		—		—
Termination upon a change of control(2)	942,500		52,972		76,432		44,478		1,116,382
Levent Caglar
Death/disability	$	—	$	—	$	116,801	$	—	$	116,801
Retirement	—		—		116,801		—		116,801
Termination for Cause	—		—		—		—		—
Termination for no cause or good reason	—		—		—		—		—
Termination upon a change of control	—		—		116,801		—		116,801

(1) Our Amended and Restated 2011 Long Term Incentive Plan allows acceleration upon termination following a change of control and upon death, disability, or retirement at the discretion of our Board of Directors (with regard to Named Executive Officers). Under the terms of COC Agreements with Messrs. Serjeant and Foster, acceleration would automatically occur upon a qualifying termination of employment following a change of control. The value of accelerated unit awards is calculated by multiplying the number of accelerated units by $5.47, the closing price of our common units on December 29, 2017.

(2) Pursuant to the terms of Change of Control Agreements with Messrs. Serjeant and Foster, amounts shown represent a multiple of base salary plus target annual cash bonus, payment of the earned portion of annual bonuses for the 2017 performance period, acceleration of outstanding unit awards, and provision of health benefits through December 31, 2019.

Director Compensation

As of January 1, 2017, 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 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. On July 1, 2016, the Board of Directors voluntarily agreed to a 10% reduction in the annual cash retainer to align with the employee wage and salary reductions implemented in 2016; the annual cash retainer was reinstated to $60,000 on March 1, 2017. The value of the equity award remained unchanged.

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. Serjeant, our President, Mr. Knox, our former President, Mr. Brightman, who served as our President for a portion of 2017 and is the Chief Executive Officer of TETRA, or Mr. Elkhoury, the former Senior Vice President and Chief Operating Officer of TETRA who

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also served as our director for a portion of the year, was compensated for his service to us as a director during 2017.

On May 5, 2017, the Board approved awards of 8,634 phantom units with an aggregate grant date fair market value of $60,438 to Messrs. Coombs, Harrison, Larson, and Sullivan for their service as directors during the May 2017 through May 2018 service year. Also on May 5, 2017, with regard to the May 2017 through May 2018 service year, Mr. Harrison received an additional award of 719 phantom units with a grant date fair market value of $5,033 for his service as chairman of the Conflicts Committee, and Mr. Larson received an additional award of 1,438 phantom units with a grant date fair market value of $10,066 for his service as chairman of the Audit Committee. One-third of all of the phantom units so awarded were immediately vested on May 5, 2017, and additional one-third portions of each award vest on January 5, 2018 and May 5, 2018. 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, 2017.

Director Compensation Table

Name	Fees Earned or Paid in Cash(1)			Unit Awards(2)			All Other Compensation			Total
	($)			($)			($)			($)
Stuart M. Brightman	$	—	(3)	$	—	(3)	$	—	(3)	$	—	(3)
Joseph Elkhoury	—		(3)	—		(3)	—		(3)	—		(3)
Paul D. Coombs	58,500			60,438			—			118,938
D. Frank Harrison	58,500			65,471			—			123,971
James R. Larson	58,500			70,504			—			129,004
Owen A. Serjeant	—		(3)	—		(3)	—		(3)	—		(3)
William D. Sullivan	58,500			60,438			—			118,938

(1) The amounts in this column reflect payments earned for service as a non-employee director during 2017.

(2) Phantom units granted on May 5, 2017 are valued at $7.00 per common unit in accordance with FASB ASC Topic 718.

(3) Mr. Elkhoury served as our director until June 2, 2017. Messrs. Brightman and Elkhoury did not receive compensation for their service as directors during 2017.

Compensation Policies and Risk Management

To the extent that risks may arise from our compensation policies and practices for our employees that are reasonably likely to have a material adverse effect on us, we are required to 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.

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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 2017, Messrs. Brightman, Elkhoury, Knox, and Serjeant, who were directors of our general partner, were also executive officers of TETRA. All compensation decisions with respect to Messrs. Brightman and Elkhoury are made by TETRA and they do not receive any compensation directly from us or from our general partner, with the exception of equity awards granted under our Amended and Restated 2011 Long Term Incentive Plan, as described above. All compensation decisions with respect to Messrs. Knox and Serjeant are made by TETRA and our general partner as described above, with the exception of equity awards under the CSI Compressco LP 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, 2017 with respect to each person that beneficially owns five percent (5%) or more of our outstanding common units, and as of March 1, 2018, with respect to (i) our directors; (ii) our Named Executive Officers; 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	15,151,743	(2)	38.9	%
OppenheimerFunds, Inc. 225 Liberty Street New York, New York 10281	3,758,958	(3)	10.4	%
Hudson Bay Capital Management LP 777 Third Avenue, 30th Floor New York, New York 10017	4,079,568	(4)	9.9	%
Goldman Sachs Asset Management 200 West Street New York, New York 10282	3,321,164	(5)	9.1	%
Stuart M. Brightman	24,700		*
Paul D. Coombs	30,063		*
D. Frank Harrison	29,535		*
James R. Larson	35,405		*
Brady M. Murphy	—		*
William D. Sullivan	44,832		*
C. Brad Benge	26,206		*
Ronald J. Foster	87,205		*
Levent Caglar	14,531		*
Director and executive officers as a group (13 persons)	299,575		0.9	%

* 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. In addition, the number of common units does not include common units that are issuable within sixty (60) days of February 28, 2018, upon conversion of a portion of the Preferred Units held by CSI Compressco Investment LLC. Such Preferred Units are converted into common units based upon a conversion price determined by the trading prices of the common units over the month preceding the conversion date and as a result, the number of common units is indeterminable at this time.

(3) Pursuant to a Schedule 13G/A dated January 10, 2018, Oppenheimer Funds, Inc. reports shared voting power and shared dispositive power with respect to 3,758,958 of our common units.

(4) Pursuant to Schedule 13G dated February 2, 2018, Hudson Bay Capital Management L.P and Sander Gerber report shared voting power and shared dispositive power with respect to 4,079,568 of our common units (including 3,728,637 common units issuable upon conversion

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of Series A Preferred Units). Hudson Bay Capital Management L.P. serves as the investment manager to Hudson Bay MLP Fund LP and HB Fund LLC. HB Fund LLC serves as the managing member of HBC MLP LLC. The common reported are held by Hudson Bay MLP Fund LP and HBC MLP LLC. Hudson Bay Capital Management L.P. may be deemed to be the beneficial owner of all common units held by HBC MLP LLC and all common units underlying the securities held by Hudson Bay MLP Fund LP and HBC MLP LLC. Mr. Gerber serves as the managing member of Hudson Bay Capital GP LLC, the general partner of Hudson Bay Capital Management LP, and disclaims beneficial ownership of such common units.

(5) Pursuant to a Schedule 13G/A dated February 8, 2018, Goldman Sachs Asset Management, L.P., together with G.S. Investment Strategies, LLC, report shared voting power and shared dispositive power with respect to 3,321,164 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 1, 2018 with respect to (i) our directors; (ii) our Named Executive Officers; and (iii) our directors and executive officers as a group.

Name of Beneficial Owner	Amount and Nature of Beneficial Ownership		Percentage of Class
Stuart M. Brightman	1,636,666	(1)	1.4	%
Paul D. Coombs	751,338		*
D. Frank Harrison	—		*
James R. Larson	—		*
Brady M. Murphy	—		*
William D. Sullivan	167,410		*
C. Brad Benge	—		*
Ronald J. Foster	54,000	(2)	*
Levent Caglar	—		*
Director and executive officers as a group (12 persons)	3,244,786	(3)	2.8	%

* Less than 1%.

(1) Includes 929,620 shares subject to options exercisable within 60 days of March 1, 2018.

(2) Includes 54,000 shares subject to options exercisable within 60 days of March 1, 2018.

(3) Includes 1,315,587 shares subject to options exercisable within 60 days of March 1, 2018.

Equity Compensation Plan Information

The following table provides information as of December 31, 2017, 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	—		$	—	—
Equity compensation plans not approved by security holders(1)	609,417	(2)	$	—	629,509
Total:	609,417		$	—	629,509

(1) Consists of the Amended and Restated 2011 Long Term Incentive Plan, which was approved by the Board of our general partner in connection with the Initial Public Offering. Please read "Item 11. Executive Compensation" of this Annual Report on Form 10-K for additional information regarding the Amended and Restated 2011 Long Term Incentive Plan.

(2) Represents phantom unit awards and performance phantom unit awards outstanding under the Amended and Restated 2011 Long Term Incentive Plan. These phantom unit awards and performance phantom unit awards do not have an exercise price.

Please see “Compensation Discussion and Analysis – Compensation Elements – Equity Incentive Awards” under Item 11 of this Annual Report for information about the material features of the Amended and Restated 2011 Long Term Incentive Plan, which information is incorporated by reference in this Item 12.

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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 2017 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 underthe 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 1, 2018, TETRA and certain of its subsidiaries, including our general partner, owned 15,151,743 common units, which constitutes a 40.0% limited partner interest in us, and an approximate 2% general partner interest in us. Prior to August 18, 2014, TETRA also held 6,273,970 subordinated units. Effective August 18, 2014, all of these subordinated units were automatically converted on a one-for-one basis into common units. TETRA is, therefore, a “related person” to us as such term is defined by the SEC.

In August 2016 and September 2016, we issued and sold 6,999,126 newly-authorized Series A Convertible Preferred Units (the "Preferred Units") in a private placement. One of the purchasers in the Initial Private Placement was TETRA, which purchased 874,891 of the Preferred Units at the aggregate Issue Price of $10.0 million and representing 12.5% ownership of the Preferred Units.

Distributions and Payments to the General Partner and its Affiliates.We will generally make cash distributions 98% to unitholders on a pro rata basis, including our general partner and certain subsidiaries of TETRA, as the holders of 15,151,743 common units and approximately 2% 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 are 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 2016, our quarterly cash distribution was reduced to $0.1875 per common unit, and fell below the target distribution levels needed to result in Incentive Distribution Rights distribution to the General Partner. In addition, TETRA, as holders of 874,891 Preferred Units, is entitled to its share of paid in kind distributions paid to holders of Preferred Units beginning in November 2016, as prescribed in our Partnership Agreement, as amended.

For the year ended December 31, 2017, we paid aggregate cash distributions of approximately $32.4 million on our common units, and $0.6 million on our general partner interest to TETRA and our general partner. In addition, in November 2016, we distributed 13,861 of paid in kind Preferred Units to TETRA. On February 14, 2018, we paid quarterly distributions with respect to the period from October 1, 2017 through December 31, 2017, including approximately $6.8 million aggregate cash distribution on our common units and $0.1 million cash

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distribution on our general partner interest to TETRA and our general partner, as well as 19,137 paid in kind Preferred Units paid to TETRA. 

Omnibus Agreement.Our ongoing relationship with TETRA and our general partner is governed by the Omnibus Agreement. On June 20, 2014, the Board of our general partner, upon the recommendation of the Conflicts Committee, approved an amendment to the Omnibus Agreement to extend the term of the agreement (which was set to expire on that date). 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. For the year ended, December 31, 2017, in connection with our operations in Argentina, a subsidiary of TETRA provided services to a subsidiary of ours on a subcontract basis for approximately $1.7 million.

Sales, Leases, or Like-Kind Exchanges ofEquipment

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 year ended December 31, 2017, 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 equipment rental amounts of approximately $0.5 million during 2017. In addition, another TETRA subsidiary charged our subsidiaries $0.2 million during 2017 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 $1.4 million during 2017 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 $0.2 million during 2017.

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Income Sharing

Under our agreement with TETRA to provide early production services ("EPS") to a customer in Argentina, we retain a portion of the income generated under the EPS contract. During 2017, a subsidiary of TETRA invoiced a subsidiary of ours approximately $0.0 million pursuant to our income sharing agreement with TETRA.

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, 2017, TETRA and our general partner charged us approximately $34.0 million in reimbursement for such services. The amount to be charged by TETRA and our general partner increased beginning in the fourth quarter of 2014 as a result of the CSI Acquisition.

In January 2017, we and TETRA agreed that our reimbursement for corporate general and administrative services performed by TETRA during the fourth quarter of 2016 would be paid using common units rather than cash, with the number of units issued determined based on average trading price of our common units over a defined period. These services, which totaled $1.6 million for the fourth quarter of 2016, were reimbursed with the issuance of 159,192 common units issued in January 2017.

In May 2017, our General Partner and TETRA entered into an agreement (the "First Quarter 2017 Omnibus

Reimbursement Agreement") pursuant to which $1.7 million of Amounts Payable to Affiliates as of March 31, 2017

that were owed by us to TETRA under the Omnibus Agreement would be satisfied by newly issued common units

instead of cash, with the number of common units calculated based on the average trading price of our common

units, subject to limitations, over a defined period that began on May 12, 2017. This amount owed by us

represented certain corporate and general and administrative services provided in the first quarter of 2017.

Pursuant to the First Quarter 2017 Omnibus Reimbursement Agreement, 280,257 common units were issued to

TETRA in June 2017.

Indemnification for Environmental and Related Liabilities

Under the Omnibus Agreement, subject to certain limitations, TETRA and our general partner have indemnified 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 indemnified 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 have also indemnified 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, 2017, and 2016, respectively:

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	2017		2016
Audit fees	$	1,753,000	$	1,572,000
Audit related fees	—		—
Tax fees	—		—
Total fees	$	1,753,000	$	1,572,000

Our Audit Committee pre-approved 100% of the fees shown in the above table. Before approving these 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, 2017 and 2016	F-3
	Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015	F-4
	Consolidated Statements of Comprehensive Income for the years ended December 31, 2017, 2016, and 2015	F-5
	Consolidated Statements of Partners’ Capital for the years ended December 31, 2017, 2016, and 2015	F-6
	Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016, 2015	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	First Amended and Restated Agreement of Limited Partnership of Compressco Partners, L.P., dated June 20, 2011  (incorporated by reference to Exhibit 3.1 to the Partnership’s Current Report on Form 8-K filed on June, 24, 2011 (SEC File No. 001-35195)).
3.3	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)).

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3.4	First Amended and Restated Bylaws of Compressco Partners GP Inc., dated June 20, 2011 (incorporated by reference to Exhibit 3.2 to the Partnership’s Current Report on Form 8-K filed on June, 24, 2011 (SEC File No. 001-35195)).
3.5	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)).
3.6	Amendment to the Certificate of Limited Partnership of Compressco Partners, L.P., dated November 19, 2004 (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)).
3.7	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Compressco Partners, L.P., dated December 1, 2014 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K filed on December 1, 2014 (SEC File No. 001-35195)).
3.8	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)).
3.9	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)).
3.10	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)).
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	Registration Rights Agreement, dated as of August 4, 2014, by and among Compressco Partners, L.P., Compressco Finance Inc., the Guarantors party thereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated as representative of the Initial Purchasers named therein (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K filed on August 4, 2014 (SEC File No. 001-35195)).
4.4	Registration Rights Agreement, dated as of April 30, 2015, by and among CSI Compressco LP, TETRA Technologies, Inc., and Wells Fargo Energy Capital, Inc., in its capacity as noteholder representative (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on May 6, 2016 (SEC File No. 001-35195)).
4.5	Registration Rights Agreement, dated as of August 8, 2016, by and among CSI Compressco LP and the other parties signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on August 8, 2016 (SEC File No. 001-35195)).
4.6	Registration Rights Agreement, dated as of September 20, 2016, by and among CSI Compressco LP and the other parties signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on September 21, 2016 (SEC File No. 001-35195)).
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***	Compressco Partners, L.P. 2011 Long Term Incentive Plan (incorporated by reference to Exhibit  4.4 to the Partnership’s Registration Statement on Form S-8 filed on June 17, 2011 (SEC File No. 333-175007)).
10.4***	Form of Employee Restricted Unit Agreement under the Compressco Partners, L.P. 2011 Long Term Incentive Plan (incorporated by reference to Exhibit 4.5 to the Partnership’s Registration Statement on Form S-8 filed on June 17, 2011 (SEC File No. 333-175007)).
10.5***	Form of Director Restricted Unit Agreement under the Compressco Partners, L.P. 2011 Long Term Incentive Plan (incorporated by reference to Exhibit 4.6 to the Partnership’s Registration Statement on Form S-8 filed on June 17, 2011 (SEC File No. 333-175007)).
10.6	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)).
10.7	Credit Agreement, dated June 24, 2011, by and among Compressco Partners, L.P., Compressco Partners Operating, LLC and Compressco Partners Sub, Inc., as the borrowers, the Partnership’s existing and future domestic subsidiaries, as loan guarantors, and JP Morgan Chase Bank, N.A., as the lender (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 30, 2011 (SEC File No. 001-35195)).

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10.8***	Summary Description of the Compensation of Non-Employee Directors of Compressco Partners GP Inc. (incorporated by reference to Exhibit 10.8 to the Annual Report on Form 10-K filed on March 11, 2016 (SEC File No. 001-35195)).
10.9***	Summary Description of Named Executive Officer Compensation (incorporated by reference to Exhibit 10.9 to the Annual Report on Form 10-K filed on March 11, 2016 (SEC File No. 001-35195)).
10.10***	Forms of Phantom Unit Agreement, Non-Employee Director Phantom Unit Agreement and Performance Phantom Unit Agreement under the 2011 Long Term Incentive Plan (incorporated by reference to Exhibits 99.1, 99.2 and 99.3, respectively, to the Current Report on Form 8-K filed on June 1, 2012 (SEC File No. 001-35195)).
10.11	First Amendment to Credit Agreement, dated December 4, 2012, by and among Compressco Partners, L.P., Compressco Partners Operating, LLC, and Compressco Partners Sub, Inc., the other Loan Parties party thereto, and JPMorgan Chase Bank, N.A., as the lender (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on December 5, 2012 (SEC File No. 001-35195)).
10.12	Second Amendment to Credit Agreement and First Amendment to Pledge and Security Agreement, dated May 14, 2013, by and among Compressco Partners, L.P., Compressco Partners Operating, LLC and Compressco Partners Sub, Inc., as the borrowers, the Partnership’s existing and future domestic subsidiaries, as loan guarantors, and JP Morgan Chase Bank, N.A. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on May 16, 2013 (SEC File No. 001-35195)).
10.13	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)).
10.14	Credit Agreement, dated October 15, 2013, by and among Compressco Partners, L.P., Compressco Partners Operating, LLC, Compressco Partners Sub, Inc., Compressco Holdings, LLC, Compressco Leasing, LLC, Compressco Field Services International, LLC, and Compressco International, LLC, as the borrowers, JP Morgan Chase Bank, N.A., as Administrative Agent, and JPMorgan Chase Bank, N.A., Bank of America, N.A., and PNC Bank, National Association, as lenders (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on October 18, 2013 (SEC File No. 001-35195)).
10.15	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)).
10.16	Stock Purchase Agreement, dated as of July 20, 2014, by and between Warren Equipment Company and Compressco Partners Sub, Inc. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K filed on July 21, 2014 (SEC File No. 001-35195)).
10.17	Guaranty, dated July 20, 2014, by Compressco Partners, L.P. in favor of Warren Equipment Company (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on July 21, 2014 (SEC File No. 001-35195)).
10.18	Contribution and Unit Purchase Agreement, dated as of July 20, 2014, by and among Compressco Partners, L.P., Compressco Partners GP, Inc. and TETRA Technologies, Inc. (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on July 21, 2014 (SEC File No. 001-35195)).
10.19	Purchase Agreement, dated as of July 29, 2014, by and among Compressco Partners, L.P., Compressco Finance Inc., the Guarantors party thereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated as representative of the Initial Purchasers named therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on August 4, 2014 (SEC File No. 001-35195)).
10.20	Purchase Agreement Joinder, dated as of August 4, 2014, by and among the Guarantors party thereto and Merrill Lynch, Pierce, Fenner & Smith Incorporated as Representative of the Initial Purchasers named therein (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on August 4, 2014 (SEC File No. 001-35195)).
10.21	Credit Agreement, dated as of August 4, 2014, by and among Compressco Partners, L.P., Compressco Partners Sub, Inc., the lenders from time to time party thereto, Bank of America, N.A., in its capacity as administrative agent for the lenders and collateral agent, and the other parties thereto (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on August 4, 2014 (SEC File No. 001-35195)).
10.22***	Employment Agreement dated August 4, 2014 by and between Compressco Partners GP Inc. and Timothy A. Knox (incorporated by reference to Exhibit 10.6 to the Quarterly Report on Form 10-Q filed on November 14, 2014 (SEC File No. 001-35195)).
10.23***	Change in Control Agreement dated August 4, 2014 by and between Compressco Partners GP Inc. and Timothy A. Knox (incorporated by reference to Exhibit 10.7 to the Quarterly Report on Form 10-Q filed on November 14, 2014 (SEC File No. 001-35195)).
10.24***	Employment Agreement executed November 6, 2014, but effective as of August 4, 2014, by and between Compressco Partners GP, Inc. and Ronald J. Foster (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on November 12, 2014 (SEC File No. 001-35195)).
10.25***	Employment Agreement dated July 20, 2014, but effective as of August 4, 2014, by and between Compressco Partners GP Inc. and Charles B. Benge (incorporated by reference to Exhibit 10.31 to the Annual Report on Form 10-K filed on March 30, 2015 (SEC File No. 001-35195)).
10.26***	Employment Agreement dated July 20, 2014, but effective as of August 4, 2014, by and between Compressco Partners GP Inc. and Anthony D. Speer (incorporated by reference to Exhibit 10.32 to the Annual Report on Form 10-K filed on March 20, 2015 (SEC File No. 001-35195)).

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10.27***	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)).
10.28***	Separation and Release Agreement by and between Kevin Book and CSI Compressco GP Inc., dated December 21, 2015 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on December 22, 2015 (SEC File No. 001-35195)).
10.29	Third Amendment to Credit Agreement dated May 25, 2016 (incorporated by reference to Exhibit 10.1 to the Partnership's Current Report on Form 8-K filed on May 25, 2016 (SEC File No. 001-35195)).
10.30***	Amendment dated May 9, 2016 to Employment Agreement dated effective as of August 4, 2014 between CSI Compressco GP Inc. and Timothy A. Knox (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on May 9, 2016 (SEC File No. 001-35195)).
10.31***	Amendment dated May 9, 2016 to Employment Agreement dated effective as of August 4, 2014 between CSI Compressco GP Inc. and Ronald J. Foster (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on May 9, 2016 (SEC File No. 001-35195)).
10.32***	Amendment dated May 9, 2016 to Employment Agreement dated effective as of August 4, 2014 between CSI Compressco GP Inc. and Charles B. Benge (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on May 9, 2016 (SEC File No. 001-35195)).
10.33***	Amendment dated May 9, 2016 to Employment Agreement dated effective as of August 4, 2014 between CSI Compressco GP Inc. and Anthony D. Speer (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K filed on May 9, 2016 (SEC File No. 001-35195)).
10.34***	Consent and Acknowledgment between CSI Compressco GP Inc and Timothy A. Knox dated August 1, 2016 (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q filed on November 9, 2016 (SEC File No. 001-35195)).
10.35	Series A Preferred Unit Purchase Agreement, dated as of August 8, 2016, by and among CSI Compressco LP and the Purchasers party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on August 8, 2016 (SEC File No. 001-35195)).
10.36	Series A Preferred Unit Purchase Agreement, dated as of September 20, 2016, by and among CSI Compressco LP and the Purchasers party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on September 21, 2016 (SEC File No. 001-35195)).
10.37	Fourth Amendment to Credit Agreement dated November 3, 2016 (incorporated by reference to Exhibit 10.1 to the Partnership's Current Report on Form 8-K/A filed on November 4, 2016 (SEC File No. 001-35195)).
10.38	Fifth Amendment to Credit Agreement, dated May 5, 2017, by and among CSI Compressco LP, CSI Compressco Sub Inc., the other Loan Parties party thereto, Bank of America, N.A., as administrative agent, as collateral agent, and the lenders party thereto (incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q filed on August 8, 2017 (SEC File No. 001-35195)).
10.39	Mutual Termination of Employment Agreement effective August 4, 2017, between CSI Compressco GP Inc. and C. Brad Benge (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on May 15, 2017 (SEC File No. 001-35195)).
10.40	Mutual Termination of Employment Agreement effective August 4, 2017, between CSI Compressco GP Inc. and Ronald J. Foster (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on May 15, 2017 (SEC File No. 001-35195)).
10.41	Mutual Termination of Employment Agreement effective August 4, 2017, between CSI Compressco GP Inc. and Anthony D. Speer (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K filed on May 15, 2017 (SEC File No. 001-35195)).
10.42	Cash Retention Award Letter from CSI Compressco GP Inc. to Mr. Benge dated May 15, 2017 (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K filed on May 15, 2017 (SEC File No. 001-35195)).
10.43***	Change in Control Agreement dated November 20, 2017 by and between CSI Compressco GP Inc. and Owen Serjeant. (incorporated by reference to Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on November 21, 2017 (SEC File No. 001-35195)).
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

88

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, 2017, 2016 and 2015; (ii) Consolidated Balance Sheets as of December 31, 2017 and December 31, 2016; (iii) Consolidated Statements of Partners’ Capital/Net Parent Equity for the years ended December 31, 2017, 2016 and 2015; (iv) Consolidated Statements of Comprehensive Income for the years ended December 31, 2017, 2016 and 2015; (v) Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015; and (vi) Notes to Consolidated Financial Statements for the year ended December 31, 2017.

89

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 1, 2018	By:	/s/Owen Serjeant
			Owen Serjeant, 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/Stuart M. Brightman	Chairman of	March 1, 2018
Stuart M. Brightman	the Board of Directors
/s/Owen Serjeant	President and Director	March 1, 2018
Owen Serjeant	(Principal Executive Officer)
/s/Elijio V. Serrano	Chief Financial Officer	March 1, 2018
Elijio V. Serrano	(Principal Financial Officer)
/s/Michael E. Moscoso	Vice President - Finance	March 1, 2018
Michael E. Moscoso	(Principal Accounting Officer)
/s/Paul D. Coombs	Director	March 1, 2018
Paul D. Coombs
/s/D. Frank Harrison	Director	March 1, 2018
D. Frank Harrison
/s/James R. Larson	Director	March 1, 2018
James R. Larson
/s/Brady M. Murphy	Director	March 1, 2018
Brady M. Murphy
/s/William D. Sullivan	Director	March 1, 2018
William D. Sullivan

90

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, 2017 and 2016, and 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, 2017, 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, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, 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, 2017, 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 1, 2018, 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 include 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 1, 2018

F-1

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, 2017, 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, 2017, 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 consolidated balance sheets of the Partnership as of December 31, 2017 and 2016, and 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, 2017 and our report dated March 1, 2018, 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 1, 2018

F-2

CSI Compressco LP

Consolidated Balance Sheets

(In Thousands, Except Unit Amounts)

	December 31, 2017			December 31, 2016
ASSETS
Current assets:
Cash and cash equivalents	$	7,601		$	20,797
Trade accounts receivable, net of allowances for doubtful accounts of $822 in 2017 and $2,253 in 2016	47,776			44,904
Inventories	42,283			31,442
Prepaid expenses and other current assets	4,487			4,861
Total current assets	102,147			102,004
Property, plant, and equipment:
Land and building	34,972			34,962
Compressors and equipment	846,615			834,921
Vehicles	10,837			11,040
Construction in progress	13,261			8,138
Total property, plant, and equipment	905,685			889,061
Less accumulated depreciation	(299,206		)	(242,055		)
Net property, plant, and equipment	606,479			647,006
Other assets:
Deferred tax assets	10			28
Intangible assets, net of accumulated amortization of $21,829 in 2017 and $18,666 in 2016	33,942			37,102
Other assets	354			—
Total other assets	34,306			37,130
Total assets	$	742,932		$	786,140
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
Accounts payable	$	21,661		$	15,682
Unearned income	15,526			8,078
Accrued liabilities and other	23,785			19,974
Amounts payable to affiliates	3,034			6,180
Total current liabilities	64,006			49,914
Other liabilities:
Long-term debt, net	512,176			504,090
Series A Preferred Units	70,260			88,130
Deferred tax liabilities	1,403			718
Other long-term liabilities	60			39
Total other liabilities	583,899			592,977
Commitments and contingencies
Partners' capital:
General partner interest	1,618			3,061
Common units (37,618,734 units issued and outstanding at December 31, 2017 and 33,262,376 units issued and outstanding at December 31, 2016)	104,898			150,599
Accumulated other comprehensive income (loss)	(11,489		)	(10,411		)
Total partners' capital	95,027			143,249
Total liabilities and partners' capital	$	742,932		$	786,140

See Notes to Consolidated Financial Statements

F-3

CSI Compressco LP

Consolidated Statements of Operations

(In Thousands, Except Unit and Per Unit Amounts)

	Year Ended December 31,
	2017			2016			2015
Revenues:
Compression and related services	$	205,774		$	224,736		$	287,680
Aftermarket services	40,287			33,303			46,921
Equipment sales	49,505			53,324			123,040
Total revenues	295,566			311,363			457,641
Cost of revenues (excluding depreciation and amortization expense):
Cost of compression and related services	116,956			117,154			142,327
Cost of aftermarket services	32,256			25,362			39,232
Cost of equipment sales	44,286			48,744			109,101
Total cost of revenues	193,498			191,260			290,660
Depreciation and amortization	69,140			72,123			81,838
Long-lived asset impairment	—			10,223			11,797
Insurance recoveries	(2,352		)	—			—
Selling, general, and administrative expense	33,438			36,222			43,479
Goodwill impairment	—			92,334			139,444
Interest expense, net	43,135			38,055			34,964
Series A Preferred fair value adjustment	(3,402		)	5,036			—
Other expense, net	(216		)	2,383			2,190
Income (loss) before income tax provision (benefit)	(37,675		)	(136,273		)	(146,731		)
Provision (benefit) for income taxes	2,784			1,865			(101		)
Net income (loss)	$	(40,459	)	$	(138,138	)	$	(146,630	)
General partner interest in net income (loss)	$	(809	)	$	(2,763	)	$	(1,892	)
Common units interest in net income (loss)	$	(39,650	)	$	(135,375	)	$	(144,738	)
Net income (loss) per common unit:
Basic and diluted	$	(1.13	)	$	(4.07	)	$	(4.36	)
Weighted average common units outstanding:
Basic and diluted	35,035,428			33,262,376			33,169,413

See Notes to Consolidated Financial Statements

F-4

CSI Compressco LP

Consolidated Statements of Comprehensive Income (Loss)

(In Thousands)

	Year Ended December 31,
	2017			2016			2015
Net income (loss)	$	(40,459	)	$	(138,138	)	$	(146,630	)
Foreign currency translation adjustment, net of tax of $0 in 2017, 2016, and 2015	(1,078		)	(2,018		)	(5,057		)
Comprehensive income (loss)	$	(41,537	)	$	(140,156	)	$	(151,687	)

See Notes to Consolidated Financial Statements

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, 2014	$	11,341		33,142	$	542,276		$	(3,336	)	$	550,281
Net loss for 2015	(1,892		)	—	(144,738		)	—			(146,630		)
Distributions ($1.98 per unit)	(2,607		)	—	(65,753		)	—			(68,360		)
Equity compensation	—			—	1,924			—			1,924
Vesting of Phantom Units	—			44	—			—			—
Other comprehensive loss	—			—	—			(5,057		)	(5,057		)
Balance as of December 31, 2015	$	6,842		33,186	$	333,709		$	(8,393	)	$	332,158
Net loss for 2016	(2,763		)	—	(135,375		)	—			(138,138		)
Distributions ($1.51 per unit)	(1,018		)	—	(50,236		)	—			(51,254		)
Equity compensation	—			—	2,541			—			2,541
Vesting of Phantom Units	—			76	—			—			—
Other	—			—	(40		)	—			(40		)
Other comprehensive loss	—			—	—			(2,018		)	(2,018		)
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 ($0.75 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
Other comprehensive income (loss)	—			—	—			(1,078		)	(1,078		)
Other	—			—	(649		)	—			(649		)
Balance as of December 31, 2017	$	1,618		37,618	$	104,898		$	(11,489	)	$	95,027

See Notes to Consolidated Financial Statements

F-5

CSI Compressco LP

Consolidated Statements of Cash Flows

(In Thousands)

	Year Ended December 31,
	2017			2016			2015
Operating activities:
Net income (loss)	$	(40,459	)	$	(138,138	)	$	(146,630	)
Reconciliation of net income (loss) to cash provided by operating activities:
Depreciation and amortization	69,140			72,123			81,838
Impairments of long-lived assets	—			10,223			11,797
Impairment of goodwill	—			92,334			139,444
Provision (benefit) for deferred income taxes	757			30			(605		)
Insurance recoveries associated with damaged equipment	(2,352		)	—			—
Series A Preferred offering costs	37			3,111			—
Series A Preferred accrued paid in kind distributions	8,380			3,094			—
Series A Preferred fair value adjustments	(3,402		)	5,036			—
Gain on extinguishment of debt	—			(1,405		)	—
Equity compensation expense	1,219			3,028			2,164
Provision for doubtful accounts	968			1,704			508
Amortization of deferred financing costs	3,167			2,739			2,786
Other non-cash charges and (credits)	571			1,558			825
(Gain) loss on sale of property, plant, and equipment	(315		)	(501		)	(196		)
Changes in operating assets and liabilities, net of acquisition:
Accounts receivable	(2,706		)	11,208			19,732
Inventories	(10,840		)	10,542			64,893
Prepaid expenses and other current assets	(501		)	1,729			(2,753		)
Accounts payable and accrued expenses	15,765			(17,039		)	(71,592		)
Other	(361		)	68			(318		)
Net cash provided by operating activities	39,068			61,444			101,893
Investing activities:
Purchases of property, plant, and equipment, net	(25,126		)	(10,659		)	(95,272		)
Insurance recoveries associated with damaged equipment	2,352			—			—
Advances and other investing activities	21			(22		)	(69		)
Net cash used in investing activities	(22,753		)	(10,681		)	(95,341		)
Financing activities:
Proceeds from long-term debt	80,900			109,000			63,000
Payments of long-term debt	(74,900		)	(172,882		)	(23,000		)
Proceeds from Series A Preferred Units, net of offering costs	(37		)	76,934			—
Distributions	(33,068		)	(51,254		)	(68,360		)
Contribution from general partner	—			—			—
Financing costs and other financing activities	(2,229		)	(1,688		)	—
Net cash (used in) provided by financing activities	(29,334		)	(39,890		)	(28,360		)
Effect of exchange rate changes on cash	(177		)	(696		)	(1,638		)
Increase (decrease) in cash and cash equivalents	(13,196		)	10,177			(23,446		)
Cash and cash equivalents at beginning of period	20,797			10,620			34,066
Cash and cash equivalents at end of period	$	7,601		$	20,797		$	10,620

F-6

Supplemental cash flow information:
Interest paid	$	31,674	$	32,947	$	32,994
Taxes paid	$	3,005	$	1,277	$	598

See Notes to Consolidated Financial Statements

F-7

CSI COMPRESSCO LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2017

NOTE A—ORGANIZATION AND OPERATIONS

CSI Compressco LP (formerly known as Compressco Partners, L.P.), a Delaware limited partnership, is a provider of compression services and equipment for natural gas and oil production, gathering, transportation, processing, and storage. We sell standard and custom-designed compressor packages and oilfield fluid pump systems, 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 foreign countries, including Mexico, Canada, and Argentina. We design and fabricate a majority of the compressor packages that we use to provide compression services and that we 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.

In April 2017, our General Partner announced a reduction of approximately 50% in the level of cash

distributions on our common units beginning with the quarter ended March 31, 2017. In May 2017, we entered into an amendment of the agreement governing our bank revolving credit facility (as amended, the "Credit Agreement") by, among other things, favorably amending certain covenants. (See Note D - Long-Term Debt and Other Borrowings.) We have reviewed our financial forecasts as of March 1, 2018 for the subsequent twelve month period, which consider the amended covenants and the current distribution levels to our common unitholders. Based on these financial forecasts, which are based on the current market conditions as of March 1, 2018, we believe that we will have adequate liquidity, earnings, and operating cash flows to fund our operations and debt obligations and maintain compliance with our debt covenants through March 1, 2019.

NOTE B — 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 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 bematerial.

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

The fair values of our financial instruments, which may include cash, accounts receivable, amounts outstanding under our variable rate bank credit facility, accounts payable and accrued liabilities, approximate their

F-8

carrying amounts. 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.

As a result of the outstanding balances under our variable rate revolving credit facility, we face market risk exposure related to changes in applicable interest rates. Although we have no interest rate swap contracts outstanding to hedge this potential risk exposure, we have entered into certain fixed interest rate notes, which are scheduled to mature in 2022 and which mitigate this risk on our total outstanding borrowings.

Significant Customers

During2017 and 2016, ConocoPhillips accounted for approximately 11.0% of our revenues. During2015, no individual customer accounted for 10% or more of our revenues.

Foreign Currencies

We have designated the Canadian dollar and Argentine peso as the functional currencies for our operations in Canada and Argentina, respectively. 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 gains and (losses) are included in other expense and totaled $48,000, $(1.6) million, and $(2.0) million during the years ended December 31, 2017, 2016, and 2015, respectively.

Allowances for Doubtful Accounts

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

	Year Ended December 31,
	2017			2016			2015
	(In Thousands)
At beginning of period	$	2,253		$	1,973		$	1,496
Activity in the period:
Provision for doubtful accounts	968			1,704			508
Account (chargeoffs) recoveries, net	(2,399		)	(1,424		)	(31		)
At end of period	$	822		$	2,253		$	1,973

Inventories

Inventoriesconsist primarily of compressor package parts and supplies and work in process and are stated at the lower of cost ormarket value. For parts and supplies, cost is determined using the weighted averagecostmethod. The cost of work in progress is determined using the specific identification method. Work in progress inventories consist primarily of new compressor packages located at our fabrication facility in Midland, Texas. We write down the value of inventory by an amount equal to the difference between its cost and its estimated market value. Components of inventories as of December 31, 2017, and December 31, 2016, are as follows: 

F-9

	December 31, 2017		December 31, 2016
	(In Thousands)
Parts and supplies	$	31,703	$	25,932
Work in progress	10,580		5,510
Total inventories	$	42,283	$	31,442

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	12–20years
Other equipment	2–8years
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, 2017,2016, and2015was $66.0 million, $68.8 million, and $71.7 million, respectively.

Construction in progress as of December 31, 2017 consists primarily of new compressor packages under fabrication and capital expenditures that sustain the capacity of our existing fleet. Construction in progress as of December 31, 2016 consists primarily of capitalized system software development costs incurred during 2016. Interest capitalized for the years ended December 31, 2017,2016, and2015was $0.6 million, $0.2 million, and $0.0 million, respectively.

Intangible Assets other than Goodwill

Trademarks/trade names, customer relationships, and other intangible assets are recorded on the basis of cost and 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 $3.2 million, $3.4 million, and $6.8 million for the years ended December 31, 2017,2016, and2015, 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 2018, $2.9 million for 2019, $2.9 million for 2020, $2.9 million for 2021, and $2.9 million for 2022.

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. See "Impairments of Long-Lived Assets" section below.

Goodwill

Goodwill represents the excess of cost over the fair value of the net assets of businesses acquired in purchase transactions. Prior to the impairment of remaining goodwill as of March 31, 2016, we performed a goodwill impairment test on an annual basis or whenever indicators of impairment were present. We performed the annual test of goodwill impairment following the fourth quarter of each year. The assessment for goodwill impairment begins with a qualitative assessment of whether it is “more likely than not” that the fair value of our business is less than its carrying value. This qualitative assessment requires the evaluation, based on the weight of evidence, of the significance of all identified events and circumstances. During 2015, and continuing into 2016, global oil and natural gas commodity prices, particularly crude oil, were significantly reduced. These low commodity prices had a negative

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impact on industry drilling and capital expenditure activity, which affected the demand for a portion of our products and services. The accompanying decrease in the price of our common units during the last half of 2015 and early 2016 also resulted in an overall reduction in our market capitalization. Based on this qualitative assessment, we determined that, due to the decline in the price of our common units that resulted in our market capitalization being less than the book value of our consolidated partners' capital balance as of December 31, 2015 and March 31, 2016, it was “more likely than not” that the fair value of our business was less than its carrying value as of these dates.

When the qualitative analysis indicates that it is “more likely than not” that our business’ fair value is less than its carrying value, the resulting goodwill impairment test consists of a two-step accounting test being performed. The first step of the impairment test is to compare the estimated fair value with the recorded net book value (including goodwill) of our business. If the estimated fair value is higher than the recorded net book value, no impairment is deemed to exist and no further testing is required. If, however, the estimated fair value is below the recorded net book value, an impairment loss is calculated by comparing the recorded net book value of goodwill to our estimated implied fair value of that goodwill. Our estimates of our fair value, when required,are based on a combination of an income and market approach. These estimates are imprecise and are subject to our estimates of our future cash flows and our judgment as to how these estimated cash flows translate into our estimated fair value. These estimates and judgments are affected by numerous factors, including the general economic environment at the time of our assessment, which affects our overall market capitalization.

Our management must apply judgment in determining the estimated fair value for purposes of performing the goodwill impairment test. Management uses all available information to make these fair value determinations, including the present value of expected future cash flows using discount rates commensurate with the risks involved in the assets. The resultant fair values calculated are then compared to observable metrics for other companies in our industry or on mergers and acquisitions in our industry, to determine whether those valuations, in our judgment, appear reasonable.

The accounting principles regarding goodwill acknowledge that the observed market prices of individual trades of a company’s stock (and thus its computed market capitalization) may not be representative of the fair value of the company as a whole. Substantial value may arise from the ability to take advantage of synergies and other benefits that flow from control over another entity. Consequently, measuring the fair value of a collection of assets and liabilities that operate together in a controlled entity is different from measuring the fair value of a single share of that entity’s common stock. Therefore, once the fair value of the reporting units was determined, we also added a control premium to the calculations. This control premium is judgmental and is based on observed mergers and acquisitions in our industry.

As part of our internal annual business outlook that we performed during 2015 and 2016, we considered changes in the global economic environment that affected our common unit price and market capitalization. As a result of the annual goodwill impairment test process described above, we recorded impairments of goodwill of $92.3 million as of December 31, 2015 and $92.4 million as of March 31, 2016. As of December 31, 2015, as a result of decreased demand for our products and services due to decreased oil and natural gas commodity prices, and due to decrease in the price of our common units, we determined that it was "more likely than not" that our fair value was less than our net book value as of December 31, 2015. With regard to the 2016 impairment, due to the decrease in the price of our common units during the first three months of 2016, our market capitalizations as of March 31, 2016, was again below our recorded net book value, including remaining goodwill. In addition, the continuing low oil and natural gas commodity price environment resulted in a further negative impact on demand for the products and services for each of our reporting units. As a result of these factors, we determined that it was “more likely than not” that our fair value was less than our net book value as of March 31, 2016.

As of December 31, 2017, the carrying amount of goodwill is $0.0 million, after giving effect to the $233.5 million of accumulated impairment losses.

The changes in the carrying amount of goodwill are as follows:

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	Year Ended December 31,
	2017		2016			2015
	(In Thousands)
Balance, beginning of year	$	—	$	92,402		$	233,548
Goodwill acquired during the year	—		—			—
Goodwill adjustments	—		(92,402		)	(141,146		)
Balance, end of year	$	—	$	—		$	92,402

Impairments of Long-Lived Assets

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 the first quarter of 2016, as a result of continuing decreased demand as a result of current market conditions, we recorded impairments of approximately $7.9 million associated with certain identified intangible assets. During the fourth quarter of 2016, as a result of fire damage to compressor packages, we recorded impairments of approximately $2.4 million associated with certain identified compressor units. This amount was charged to Long-Lived Asset Impairment expense in the accompanying consolidated statement of operations.

Revenue Recognition

We recognize revenue using the following criteria: (a) persuasive evidence of an exchange arrangement exists; (b) delivery has occurred or services have been rendered; (c) the buyer’s price is fixed or determinable; and (d) collectability is reasonably assured. 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. Collections associated with progressive billings to customers for the construction of compression equipment is included in unearned income in the consolidated balance sheets.

Compression and Related Services Revenues and Costs

Our compression and related services revenues include revenues from our U.S. corporate subsidiaries' operating lease agreements with customers. For the three years in the period ended December 31, 2017, the following operating lease revenues and associated costs were included in compression and related service revenues and cost of compression and related services, respectively, in the accompanying consolidated statements of operations. As a result of our customers entering into compression service contracts, our revenues from rental contracts have decreased during the year ended December 31, 2017 compared to the prior years.

	Year Ended December 31,
	2017		2016		2015
	(In Thousands)
Rental revenue	$	38,720	$	42,644	$	117,540
Rental expenses	$	17,560	$	25,039	$	66,040

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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, consultants, and directors of our general partner. Total equity-based compensation expense for the three years ended December 31, 2017, 2016, and 2015, was $1.2 million, $3.0 million, and $2.2 million, respectively. For further discussion of equity-based compensation, see Note I - 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. Beginning in 2015, a portion of the carrying value of certain deferred tax assets is subjected to a valuation allowance. See Note G - Income Taxes for further discussion.

Accumulated Other Comprehensive Income (Loss)

Certain ofour 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) during the three years ended December 31, 2017, December 31, 2016, and December 31, 2015 is as follows:

	Year Ended December 31,
	2017			2016			2015
	(In Thousands)
Balance, beginning of year	$	(10,411	)	$	(8,393	)	$	(3,336	)
Foreign currency translation adjustment, net of tax of $0 in 2017, 2016, and 2015	(1,078		)	(2,018		)	(5,057		)
Balance, end of year	$	(11,489	)	$	(10,411	)	$	(8,393	)

Activity within accumulated other comprehensive income includes noreclassifications to net income.

Allocation of Net Income

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

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.

Under U.S. generally accepted accounting principles ("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

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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.

We utilize fair value measurements to account for certain items and account balances within our consolidated financial statements. Fair value measurements are utilized in the determination of the carrying value of our Preferred Units (a Level 3 fair value measurement), which were issued in August and September 2016. 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 as determined by our counterparty financial institution (a level 2 fair value measurement). 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 and goodwill (a Level 3 fair value measurement), and for the impairment of long-lived assets, including goodwill (a level 3 fair value measurement). The fair value of certain of our financial instruments, which may include cash, accounts receivable, short-term borrowings, and variable-rate long-term debt pursuant to our bank credit agreement, approximate their carrying amounts. The fair values of our publicly traded long-term 7.25% Senior Notes at December 31, 2017 and December 31, 2016, were approximately $279.7 million and $278.2 million (a level 2 fair value measurement). Those fair values compared to an aggregate principal amount of such notes at December 31, 2017 and 2016 of $295.9 million.

The Preferred Units are valued using a lattice modeling technique that, among a number of lattice structures, includes significant unobservable items (a level 3 fair value measurement). These unobservable items include (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 utilizes market information related to the debt yields of comparable peer companies, and (iii) a future conversion price analysis. The fair valuation of our Preferred Units liability is increased by, among other factors, projected increases in our common unit price, and by increases in the volatility and decreases in the debt yields of comparable peer companies. Increases (or decreases) in the fair value of our Preferred Units will increase (decrease) the associated liability and result in future adjustments to earnings for the associated valuation losses (gains).

A summary of these recurring fair value measurements as of December 31, 2017 and 2016, is as follows:

				Fair Value Measurements Using
Description	Total as of December 31, 2017			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	$	(70,260	)	$	—	$	—		$	(70,260	)
Asset for foreign currency derivative contracts	130			—		130			—
Liability for foreign currency derivative contracts	(10		)	—		(10		)	—
	$	(70,140	)

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				Fair Value Measurements Using
Description	Total as of December 31, 2016			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	$	(88,130	)	$	—	$	—	$	(88,130	)
Asset for foreign currency derivative contracts	$	57		$	—	$	57	$	—
	$	(88,073	)

During 2016, we recorded total impairment charges of $102.6 million, reflecting the decreased fair value for certain assets. Assets that were partially impaired included certain of our intangible assets. The fair values used in these impairment calculations were estimated based on discounted estimated future cash flows, which is based on significant unobservable inputs (Level 3) in accordance with the fair value hierarchy.A summary of these nonrecurring fair value measurements during the year ended December 31, 2016, using the fair value hierarchy is as follows:

				Fair Value Measurements Using
				Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Year-to-Date Impairment Losses
Description	Total Fair Value
	(In Thousands)
Tangible compressor assets	$	—		$	—	$	—	$	—	$	2,357
Identified intangible assets	20,600		(1)	—		—		20,600		7,866
Goodwill	—			—		—		—		92,402
Total	$	20,600		$	—	$	—	$	20,600	$	102,625

⁽¹⁾ Fair value as of March 31, 2016 date of impairment.

Recently Issued Accounting Pronouncements

In May 2014, the FASB issued Accounting Standards Update ("ASU") 2014-09, "Revenue from Contracts with Customers." ASU 2014-09 supersedes the revenue recognition requirements in ASC 605, Revenue Recognition, and most industry-specific guidance. The core principle of the guidance is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This ASU is effective for annual periods beginning after December 15, 2017, and interim periods within those years, under either full or modified retrospective adoption. During 2016, in preparation for the adoption of ASU No. 2014-09, we began a review of the various types of customer contract arrangements for our compression services, aftermarket services, and equipment sales operations. These reviews include 1) accumulating all customer contractual arrangements; 2) identifying individual performance obligations pursuant to each arrangement; 3) quantifying consideration under each arrangement; 4) allocating consideration among the identified performance obligations; and 5) determining the timing of revenue recognition pursuant to each arrangement. During 2017, we completed these contract reviews and have implemented revised accounting system processes in order to capture information required to be disclosed under ASU 2014-09. We will adopt this new guidance using the modified retrospective method on January 1, 2018. We have substantially completed our analysis of the new guidance and have not identified any material changes to the timing or amount of revenue to be recognized in future periods. The disclosures related to revenue recognition will be significantly expanded under ASU 2014-09, specifically around the

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quantitative and qualitative information about performance obligations, changes in contract assets and liabilities, and disaggregation of revenue. We continue to evaluate these requirements.

In March 2016, the FASB issued ASU 2016-08,"Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)" to clarify the guidance on principal versus agent considerations. This ASU does not change the effective date or adoption method under ASU 2014-09 which is noted above.

In April 2016, the FASB issued ASU 2016-10,"Revenue from Contracts with Customers (Topic 606): Identifying Performance Obligations and Licensing" to clarify the guidance on identifying performance obligations and the licensing implementation guidance. This ASU does not change the effective date or adoption method under ASU 2014-09, which is noted above.

Additionally, in May 2016, the FASB issued ASU 2016-12,"Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients". This ASU addresses and amends several aspects of ASU 2014-09, but does not change the core principle of the guidance. This ASU does not change the effective date or adoption method under ASU 2014-09 which is noted above.

In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory”, which simplifies the subsequent measurement of inventory by requiring entities to measure inventory at the lower of cost or net realizable value, except for inventory measured using the last-in, first-out (LIFO) or the retail inventory methods. The ASU requires entities to compare the cost of inventory to one measure - net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The ASU is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods, and is to be applied prospectively with early adoption permitted. As a result of the adoption of this standard during the first quarter of 2017, there was no material impact on our consolidated financial statements.

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)" to increase comparability and transparency among different organizations. Organizations are required to recognize lease assets and lease liabilities in the balance sheet and disclose key information about the leasing arrangements and cash flows. The ASU is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods, with early adoption permitted, under a modified retrospective adoption. We are currently assessing the potential effects of these changes to our consolidated financial statements.

In March 2016, the FASB issued ASU 2016-09, "Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting" as part of a simplification initiative. The update addresses and simplifies several aspects of accounting for share-based payment transactions. The ASU is effective for annual periods beginning after December 15, 2016, and interim periods within those annual periods, with early adoption permitted, and is to be applied using either modified retrospective, retrospective, or prospective transition method based on which amendment is being applied. Upon adoption of ASU 2016-09, we elected to change our accounting policy to account for forfeitures as they occur, using a modified retrospective method and determined that a cumulative-effect adjustment to retained earnings would be immaterial at transition during the first quarter of 2017. As a result of the adoption of this ASU, there was no impact on our consolidated financial statements.

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. ASU 2016-13, which has an effective date of the first quarter of fiscal 2022, also applies to employee benefit plan accounting. We are currently assessing the potential effects of these changes to our consolidated financial statements and employee benefit plan accounting.

In August 2016, the FASB issued ASU 2016-15, "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments" to reduce diversity in practice in classification of certain transactions in the statement of cash flows. The ASU is effective for annual periods beginning after December 15, 2017, and interim periods within those annual periods, with early adoption permitted, under a retrospective transition adoption. We are currently assessing the potential effects of these changes to our consolidated financial statements.

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In November 2016, the FASB issued ASU 2016-16, "Intra-Entity Transfers of Assets Other Than Inventory"

which requires companies to account for the income tax effects of intercompany transfers of assets other than

inventory when the transfer occurs. The ASU is effective for annual periods beginning after December 15, 2017,

and interim periods within those annual periods, with early adoption permitted, under a modified retrospective

transition adoption. We are currently assessing the potential effects of these changes to our consolidated financial

statements.

In May 2017, the FASB issued ASU 2017-09, "Compensation-Stock Compensation (Topic 718): Scope of

Modification Accounting" to clarify when to account for a change to the terms or conditions of a share-based

payment award as a modification. The ASU is effective for annual periods beginning after December 15, 2017, and

interim periods within those annual periods, with early adoption permitted. We do not expect the adoption of this

standard to have a material impact on our consolidated financial statements.

In July 2017, the FASB issued ASU 2017-11, "Earnings Per Share (Topic 260); Distinguishing Liabilities

from Equity (Topic 480); Derivatives and Hedging (Topic 815): (Part I) Accounting for Certain Financial Instruments

with Down Round Features, (Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial

Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a

Scope Exception" to consider “down round” features when determining whether certain equity-linked financial

instruments or embedded features are indexed to an entity’s own stock. Entities that present earnings per share

("EPS") under ASC 260 will recognize the effect of a down round feature in a freestanding equity-classified financial

instrument only when it is triggered. The effect of triggering such a feature will be recognized as a dividend and a

reduction to income available to common shareholders in basic EPS. The ASU is effective for annual periods

beginning after December 15, 2018, and interim periods within those annual periods. We are currently assessing

the potential effects of these changes to our consolidated financial statements.

In August 2017, the FASB issued ASU 2017-12, "Derivatives and Hedging (Topic 815): Targeted

Improvements to Accounting for Hedging Activities" to change how companies account for and disclose hedges. The ASU is effective for annual periods beginning after December 15, 2018, and interim periods within those annual

periods. We are currently assessing the potential effects of these changes to our consolidated financial statements.

NOTE C — 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 "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,ourGeneralPartnerprovidesall personnel and services reasonably necessary to manageouroperations and conductourbusiness(other than in Mexico, Canada, and Argentina),andcertain ofTETRA’sLatin American-based subsidiaries provide personnel and services necessaryfor theconductof certain ofourLatin American-based businesses. In addition, under the Omnibus Agreement,TETRAprovidescertain corporate and general and administrative servicesas requested by ourGeneralPartner,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,wereimburseourGeneralPartnerandTETRAfor services they provide tous. For the years ended December 31, 2017, 2016, and 2015,we were charged by TETRA $37.2 million, $41.5 million, and $113.9 million, respectively, for expenses incurred on our behalf as described below. Amounts charged under the Omnibus Agreement and outstanding as of December 31, 2017 and 2016 are included in Amounts Payable to Affiliates in the accompanying consolidated balance sheets.

In January 2017, our General Partner and TETRA agreed that $1.6 million of Amounts Payable to Affiliates as of December 31, 2016 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. This amount represents certain corporate and general and administrative

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services for the fourth quarter of 2016. Pursuant to this agreement, 159,192 units were issued to TETRA in January 2017.

In May 2017, our General Partner and TETRA entered into an agreement (the "First Quarter 2017 Omnibus

Reimbursement Agreement") pursuant to which $1.7 million of Amounts Payable to Affiliates as of March 31, 2017

that were owed by us to TETRA under the Omnibus Agreement would be satisfied by newly issued common units

instead of cash, with the number of common units calculated based on the average trading price of our common

units, subject to limitations, over a defined period that began on May 12, 2017. This amount owed by us

represented certain corporate and general and administrative services provided in the first quarter of 2017.

Pursuant to the First Quarter 2017 Omnibus Reimbursement Agreement, 280,257 common units were issued to

TETRA in June 2017.

Underthe terms of the Omnibus Agreement,weorTETRAmay, but neitherare under anyobligation to, perform for the other such production enhancement or other oilfield services on a subcontract basis as are needed or desired by theother, for such periods of time and in such amounts as may be mutually agreed upon byTETRAandourGeneral Partner. Any such services are required to be performed on terms that are (i) approved by the conflicts committee ofourGeneral Partner’s board of directors, (ii) no less favorable tousthan those generally being provided to or available from non-affiliated third parties, as determined byourGeneral Partner, or (iii) fair and reasonable tous, taking into account the totality of the relationships betweenTETRAandus(including other transactions that may be particularly favorable or advantageous tous), as determined byourGeneral Partner.

Under the terms of the Omnibus Agreement,weorTETRAmay, butare under no obligationto, sell, lease or exchange on a like-kind basis tothe other such production enhancement or other oilfield services equipment as is needed or desiredto meet either of ourproduction enhancement or other oilfield services obligations, in such amounts, uponsuch conditions and for such periods of time, ifapplicable, as may be mutually agreed upon byTETRAandourGeneral Partner. Any such sales, leases,or like-kind exchanges are required to be on terms that are (i) approved by the conflicts committee ofourGeneral Partner’s board of directors, (ii) no less favorable tousthan those generally being provided to or available from non-affiliated third parties, as determined byourGeneral Partner, or (iii) fair and reasonable tous, taking into account the totality of the relationships betweenTETRAandus(including other transactions that may be particularly favorable or advantageous tous), as determined byourGeneral Partner. In addition, unless otherwise approved by the conflicts committee ofourGeneral Partner’sboard of directors,TETRAmay purchasenewly fabricated equipment fromus at a negotiated price, provided that such price may not beless than the sum of the total costs (other than any allocations of general and administrative expenses) incurred byusin fabricating such equipment plus a fixedmargin percentage thereof, andTETRAmay purchase fromuspreviously 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, 2017 and 2016 is approximately 41% and 44%, respectively, with the common units held by the public representing an approximate 59% and 56% interest in us, respectively. As of December 31, 2017, TETRA's ownership is through various wholly owned subsidiaries and consists of approximately 39% of the limited partner interests plus the approximately 2% general partner interest, 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 $14.2 million, $22.3 million, and $30.5 million during the years ended December 31, 2017, 2016, and 2015, respectively.

In August 2016 and September 2016, we issued and sold 6,999,126 of the Preferred Units in a private placement. One of the purchasers in the Initial Private Placement was TETRA, which purchased 874,891 of the Preferred Units at the aggregate Issue Price of $10.0 million and representing 12.5% ownership of the Preferred Units. For further discussion, see Note E - Series A Convertible Preferred Units.

Indemnification Agreement

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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.

NOTE D —LONG-TERM DEBT AND OTHER BORROWINGS

Long-term debt consists of the following:

		December 31,
		2017		2016
	Scheduled Maturity	(In Thousands)
Credit Agreement (presented net of the unamortized deferred financing costs of $4.0 million as of December 31, 2017 and $4.5 million as of December 31, 2016)	August 4, 2019	$	223,985	$	217,467
7.25% Senior Notes (presented net of the unamortized discount of $2.8 million as of December 31, 2017 and $3.3 million as of December 31, 2016 and unamortized deferred financing costs of $5.0 million as of December 31, 2017 and $6.0 million as of December 31, 2016)	August 15, 2022	288,191		286,623
Total debt		512,176		504,090
Less current portion		—		—
Total long-term debt		$	512,176	$	504,090

As described below, we are in compliance with all covenants of our debt agreements as of December 31, 2017.

The following discussion is not a complete description our long-term debt agreements or amendments and is qualified in its entirety by reference to the full text of the complete agreement and amendment, which are filed as an exhibit to our filings with the SEC.

Bank Credit Facilities

Under our credit agreement, as amended (the "Credit Agreement"), with a syndicate of banks including Bank of America, N.A. as administrative agent, we have an asset-based revolving credit facility with a borrowing capacity of up to $315 million, subject to certain requirements, which matures August 4, 2019. The Credit Agreement is available to provide our working capital needs, letters of credit, and for general partnership purposes, including capital expenditures and potential future expansions or acquisitions. The Credit Agreement provides that we can make distributions to holders of our common units, but only if there is no default or event of default under the facility and we maintain excess availability of $30.0 million under the Credit Agreement. Borrowings under the Credit Agreement bear interest at a rate per annum equal to, at our option, either (a) LIBOR (adjusted to reflect any required bank reserves) for an interest period equal to one, two, three, or six months (as selected by us), plus a leverage-based margin or (b) a base rate plus a leverage-based margin; such base rate shall be determined by reference to the highest of (1) the prime rate of interest per annum announced from time to time by Bank of America, N.A., (2) the Federal Funds rate plus 0.50% per annum, and (3) LIBOR (adjusted to reflect any required bank reserves) for a one month interest period on such day plus 1.00% per annum. In addition to paying interest on outstanding principal under the Credit Agreement, we are required to pay a commitment fee in respect of the unutilized commitments. We are also required to pay a customary letter of credit fee equal to the applicable margin on revolving credit LIBOR loans, fronting fees, and other fees, agreed to with the administrative agent and lenders.

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As of December 31, 2017, we had a balance outstanding of $228.0 million, had approximately $7.2 million letters of credit, and had availability under the Credit Agreement of approximately $79.8 million.

Under our Credit Agreement, we and our subsidiary CSI Compressco Sub Inc. are named as the borrowers, and all obligations under the Credit Agreement are guaranteed by all of our existing and future, direct and indirect, domestic restricted subsidiaries (other than domestic subsidiaries that are wholly owned by foreign subsidiaries). The Credit Agreement includes customary covenants that, among other things, limit our ability to incur additional debt, incur, or permit certain liens to exist, or make certain loans, investments, acquisitions, or other restricted payments. Our Credit Agreement includes a maximum credit commitment and included within the maximum amount is availability for letters of credit (with a sublimit of $20.0 million) and swingline loans (with a sublimit of $60.0 million). The amount of outstanding borrowings under the Credit Agreement is subject to certain limitations, including a borrowing-base calculation as described below and borrowing limitations as a result of financial covenants.

On May 25, 2016, we entered into an amendment (the "Third Amendment") to our Credit Agreement that, among other things, modified certain financial covenants in the Credit Agreement. As discussed below, these financial covenants were further amended in November 2016. In addition, the Third Amendment provided for other changes related to the Credit Agreement including, among other amendments (i) reducing the maximum aggregate lender commitments from $400.0 million to $340.0 million, (ii) increasing the applicable margin by 0.25% with a range between 2.00% and 3.00% per annum for LIBOR-based loans and 1.00% to 2.00% per annum for base-rate loans, based on the applicable consolidated total leverage ratio, and (iii) imposing a requirement that we use designated consolidated cash and cash equivalent balances in excess of $35.0 million to prepay the loans as well as other provisions and restrictions. As a result of the reduction of the maximum lender commitment pursuant to the Third Amendment, unamortized deferred finance costs of $0.7 million were charged to interest expense during the year ended December 31, 2016. Pursuant to the Third Amendment, bank fees of $0.7 million were incurred during the year ended December 31, 2016 and were deferred, netting against the carrying value of the amount outstanding under our Credit Agreement.

On November 3, 2016, we entered into an additional amendment (the "Fourth Amendment") to our Credit Agreement that, among other changes, further modified certain financial covenants in the Credit Agreement. The Fourth Amendment converted the Credit Agreement from a secured revolving credit facility into an asset-based revolving credit facility ("ABL Facility"). Borrowings under the Credit Agreement, as amended, may not exceed a borrowing base equal to the sum of (i) 80% of the aggregate net amount of our eligible accounts receivable, plus (ii) 20% of the aggregate value of any eligible parts inventory, in the event we elect to include eligible parts inventory pursuant to a notice to the administrative agent, plus (iii) 80% of the net in-place eligible compressor equipment, decreased each month by the amount of associated depreciation expense, plus (iv) 80% of the cost of new eligible compressor equipment, and minus (v) the amount of any reserves established by the administrative agent in its discretion. In addition, the Fourth Amendment imposed other requirements, including requirements related to borrowing base reporting on a monthly basis and provisions to permit periodic appraisal and inspection of collateral assets. Pursuant to the Fourth Amendment, certain additional restrictive provisions ("cash dominion provisions") are imposed if an event of default has occurred and is continuing or excess availability under the ABL Facility falls below $30.0 million. In addition, the Fourth Amendment reduced the maximum aggregate lender commitments from $340.0 million to $315.0 million. As a result of the further reduction of the aggregate lender commitments pursuant to the Fourth Amendment, unamortized deferred finance costs of $0.3 million were charged to interest expense during the year ended December 31, 2016. Pursuant to the Fourth Amendment, associated fees of $0.8 million were incurred during the year ended December 31, 2016 and were deferred, netting against the carrying value of the amount outstanding under the Credit Agreement.

On May 5, 2017, we entered into an amendment (the "Fifth Amendment") to our Credit Agreement that

modified certain financial covenants in the Credit Agreement, providing that (i) the consolidated total leverage ratio

may not exceed (a) 5.95 to 1 as of March 31, 2017; (b) 6.75 to 1 as of June 30, 2017 and September 30, 2017; (c)

6.50 to 1 as of December 31, 2017 and March 31, 2018; (d) 6.25 to 1 as of June 30, 2018 and September 30, 2018;

(e) 6.00 to 1 as of December 31, 2018; and (e) 5.75 to 1 as of March 31, 2019 and thereafter; and (ii) the

consolidated secured leverage ratio may not exceed 3.25 to 1 as of the end of any fiscal quarter. The consolidated

interest coverage ratio was not amended by the Fifth Amendment. In addition, the Fifth Amendment (i) increased

the applicable margin by 0.25% in the event the consolidated total leverage ratio exceeds 6.00 to 1, resulting in a

range for the applicable margin between 2.00% and 3.50% per annum for LIBOR-based loans and 1.00 to 2.50%

per annum for base-rate loans, according to the consolidated total leverage ratio, and (ii) modified the appraisal

delivery requirement from an annual requirement to a semi-annual requirement. In connection with the Fifth

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Amendment, the board of directors of our General Partner adopted resolutions limiting the cash distributions

payable on our common units to no more than $0.1875 per common unit for the quarterly period ended June 30,

2017. The Fifth Amendment also included additional revisions that provide flexibility for the issuance of preferred

securities.

The weighted average interest rate on borrowings outstanding under the Credit Agreement as of December 31, 2017 was 5.0% per annum. At December 31, 2017, our consolidated total leverage ratio was 6.48 to 1 (compared to 6.50 to 1 maximum as required under the Credit Agreement), our consolidated secured leverage ratio was 2.89 to 1 (compared to 3.25 to 1 maximum as required under the Credit Agreement) and our consolidated interest coverage ratio was 2.55 to 1 (compared to a 2.25 to 1 minimum as required under the Credit Agreement). The consolidated total leverage ratio and the consolidated secured leverage ratio, as both are calculated under the Credit Agreement, exclude the long-term liability for the Preferred Units in the determination of total indebtedness.

We are in compliance with all covenants of the Credit Agreement as of December 31, 2017. We have reviewed our financial forecasts as of March 1, 2018 for the subsequent twelve month period, which considers the current level of distributions to be paid on our common units. We believe that we will have adequate liquidity, earnings, and operating cash flows to fund our operations and debt obligations and maintain compliance with the covenants under our debt agreements through March 1, 2019.

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 the Issuers, the "Obligors"). The 7.25% Senior Notes and the subsidiary guarantees thereof (together, the "Securities") were issued pursuant to an indenture described below. As of December 31, 2017, 295.9 million in aggregate principal amount of the 7.25% Senior Notes are outstanding.

The Obligors issued the Securities pursuant to the Indenture dated as of August 4, 2014 (the "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 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 Indenture. The 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 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.

During September 2016 and October 2016, we repurchased on the open market and retired $54.1 million aggregate principal amount of 7.25% Senior Notes for a purchase price of $50.9 million, at an average repurchase price of 94% of the principal amount of the 7.25% Senior Notes, plus accrued interest, utilizing a portion of the net proceeds of the sale of the Preferred Units. Following the repurchase of these 7.25% Senior Notes, $295.9 million aggregate principal amount of 7.25% Senior Notes remain outstanding. In connection with the repurchase of these 7.25% Senior Notes, $1.4 million of early extinguishment net gain was credited to other expense during the year ended December 31, 2016, representing the difference between the repurchase price and the $54.1 million aggregate principal amount of the 7.25% Senior Notes repurchased, and $1.8 million of remaining unamortized deferred finance costs and discounts associated with the repurchased 7.25% Senior Notes.

NOTE E — SERIES A CONVERTIBLE PREFERRED UNITS

On August 8, 2016 and September 20, 2016, we entered into Series A Preferred Unit Purchase Agreements (the “Unit Purchase Agreements”) with certain purchasers to issue and sell in private placements (the "Initial Private Placement" and "Subsequent Private Placement," respectively) an aggregate of 6,999,126 Preferred Units for a

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cash purchase price of $11.43 per Preferred Unit (the “Issue Price”), resulting in total 2016 net proceeds, after deducting certain offering expenses, of approximately $77.3 million. One of the purchasers in the Initial Private Placement was TETRA, which purchased 874,891 of the Preferred Units at the aggregate Issue Price of $10.0 million.

The holders of Preferred Units (each, a “Preferred Unitholder”) receive quarterly distributions, which are paid in kind in additional Preferred Units, equal to an annual rate of 11.00% of the Issue Price (or $1.2573 per Preferred Unit annualized), subject to certain adjustments. The rights of the Preferred Units include certain anti-dilution adjustments, including adjustments for economic dilution resulting from the issuance of common units in the future below a set price.

A ratable portion of the Preferred Units have been, and will continue to be converted into common units on the eighth day of each month over a period of thirty months that began in March 2017 (each, a “Conversion Date”), subject to certain provisions of the Amended and Restated Partnership Agreement that may delay or accelerate all or a portion of such monthly conversions. On each Conversion Date, a portion of the Preferred Units will convert into common units representing limited partner interests in the Partnership in an amount equal to, with respect to each Preferred Unitholder, the number of Preferred Units held by such Preferred Unitholder divided by the number of Conversion Dates remaining, subject to adjustment described in the Amended and Restated Partnership Agreement, with the conversion price (the "Conversion Price") determined by the trading prices of the common units over the prior month, among other factors, and as otherwise impacted by the existence of certain conditions related to the common units. On June 7, 2017, as permitted under the Amended and Restated Partnership Agreement, we elected to defer the monthly conversion of Preferred Units for each of the Conversion Dates during the three month period beginning July 2017. As a result, no Preferred Units were converted into common units during the three month period ended September 30, 2017, and future monthly conversions were increased beginning in October 2017. Based on the number of Preferred Units outstanding as of December 31, 2017, the maximum aggregate number of common units that could be required to be issued pursuant to the conversion provisions of the Preferred Units is approximately 34.1 million common units; however, the Partnership may, at its option, pay cash, or a combination of cash and common units, to the Preferred Unitholders instead of issuing common units on any Conversion Date, subject to certain restrictions as described in the Amended and Restated Partnership Agreement and the Credit Agreement. The total number of Preferred Units outstanding as of December 31, 2017 was 5,975,200.

Because the Preferred Units may be settled using a variable number of common units, the fair value of the Preferred Units is classified as a long-term liability on our consolidated balance sheet in accordance with ASC 480 "Distinguishing Liabilities and Equity." The fair value of the Preferred Units as of December 31, 2017 was $70.3 million. Changes in the fair value during each quarterly period, including the $(3.4) million and $5.0 million net (decrease) increase in fair value during the years ended 2017 and 2016, respectively, are charged or credited to earnings in the accompanying consolidated statements of operations. Based on the conversion provisions of the Preferred Units, and using the Conversion Price calculated as of December 31, 2017, the theoretical number of common units that would be issued if all of the outstanding Preferred Units were converted on December 31, 2017 on the same basis as the monthly conversions would be approximately 14.6 million common units, with an aggregate market value of $79.9 million. A $1 decrease in the Conversion Price would result in the issuance of approximately 3.8 million additional common units pursuant to these conversion provisions.

NOTE F — LEASES

We lease some of our office space, warehouse space, operating locations, and machinery and equipment. The office, warehouse, and operating location leases, which vary from one to five year terms that expire at various dates through 2021 and are renewable for three and five year periods on similar terms, are classified as operating leasesandgenerally require us to pay all maintenance and insurance costs.

Future minimum lease payments by year and in the aggregate, under leases with terms of one year or more, consist of the following at December 31, 2017: 

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	Operating Leases
	(In Thousands)
2018	$	2,567
2019	1,450
2020	1,169
2021	821
2022	18
After 2020	—
Total minimum lease payments	$	6,025

Rental expense for all operating leases was$5.6 million,$7.2 million,and$9.2 millionin2017,2016, and2015, respectively.

NOTE G — INCOME TAXES

On December 22, 2017, the United States enacted significant changes to the U.S. tax law following the passage and signing of H.R.1, “An Act to Provide the Reconciliation Pursuant to Titles II and V of the Concurrent Resolution on the Budget for Fiscal Year 2018” (the “Act”) (previously known as “The Tax Cuts and Jobs Act”). Changes include, but are not limited to, a corporate tax rate decrease from 35% to 21% effective for tax years beginning after December 31, 2017, the transition of U.S. international taxation from a worldwide tax system to a territorial system, and a one-time transition tax on the mandatory deemed repatriation of cumulative foreign earnings as of December 31, 2017. We have calculated our best estimate of the impact of the Act in our year-end income tax provision in accordance with our understanding of the Act and guidance available as of the date of this filing and as result have recorded income tax expense of $21.9 million in the fourth quarter of 2017, the period in which the legislation was enacted. This income tax expense was fully offset by a decrease in the valuation allowance previously recorded on our net deferred tax assets. As such, the Act resulted in no net tax expense. The provisional amount related to the remeasurement of certain deferred tax assets and liabilities, based on the rates at which they are expected to reverse in the future was $21.9 million, offset by a corresponding decrease in our valuation allowance. The provisional amount related to the one-time transition tax was zero.

On December 22, 2017, Staff Accounting Bulletin 118 (“SAB 118”) was issued to address the application of US GAAP in situations when a registrant does not have the necessary information available, prepared, or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the Act. We have made reasonable estimates of the effects and recorded provisional amounts in our financial statement as of December 31, 2017. However, we are still analyzing certain aspects of the Act and refining our calculations, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts.

We have not yet completed our calculation of the total post-1986 E&P for these foreign subsidiaries. Further, the transition tax is based in part on the amount of those earnings held in cash and other specified assets.

This amount may change when we finalize the calculation of post-1986 foreign E&P previously deferred from US federal taxation and finalize the amounts held in cash or other specified assets.

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 cost are both acceptable methods subject to an accounting policy election. A provisional estimate could not be made as we have not yet completed our assessment or elected an accounting policy to either recognize deferred taxes for basis differences expected to reverse as GILTI or to record GILTI as period costs if and when incurred.

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 locatedoutside 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, 2017,2016, and2015consists of the following:

	Year Ended December 31,
	2017			2016			2015
	(In Thousands)
Current
Federal	$	(47	)	$	—		$	(1,632	)
State	688			836			1,330
Foreign	1,386			999			806
	2,027			1,835			504
Deferred
Federal	—			—			(847		)
State	19			(8		)	(354		)
Foreign	738			38			596
	757			30			(605		)
Total tax provision (benefit)	$	2,784		$	1,865		$	(101	)

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

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	Year Ended December 31,
	2017			2016			2015
	(In Thousands)
Income (loss) tax provision computed at statutory federal income tax rates	$	(12,809	)	$	(46,332	)	$	(49,888	)
Partnership (earnings) losses	12,809			46,332			49,888
Corporate subsidiary earnings (loss) subject to federal tax	5,805			(33,791		)	(36,712		)
Impact of goodwill impairments	—			2,134			3,341
Impact of U.S. tax law change	21,928			—			—
Valuation allowances	(28,236		)	33,056			33,682
Income tax expense attributable to foreign earnings	2,565			1,297			92
State income taxes (net of federal benefit)	734			(849		)	(619		)
Nondeductible expenses	36			23			79
Other	(48		)	(5		)	36
Total tax provision (benefit)	$	2,784		$	1,865		$	(101	)

Corporate subsidiary earnings (loss) subject to federal tax for 2017 includes $11.1 million related to a cumulative correcting cost allocation adjustment between U.S. subsidiary entities from prior years, the net impact from which is considered immaterial.

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

	Year Ended December 31,
	2017			2016			2015
	(In Thousands)
Domestic	$	(40,649	)	$	(146,007	)	$	(150,814	)
International	2,974			9,734			4,083
Total	$	(37,675	)	$	(136,273	)	$	(146,731	)

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	2012
Non-U.S. jurisdictions	2011

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:

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Deferred Tax Assets

	December 31,
	2017			2016
	(In Thousands)
Inventory reserve	$	270		$	690
Amortization for book in excess of tax expense	27,721			46,487
Accruals	264			452
Net operating losses	17,809			33,300
Bad debt reserve	144			472
Other	42			84
Total deferred tax assets	46,250			81,485
Valuation allowance	(39,367		)	(69,176		)
Net deferred tax assets	$	6,883		$	12,309

Deferred Tax Liabilities

	December 31,
	2017		2016
	(In Thousands)
Accruals	$	1,076	$	269
Depreciation for tax in excess of book expense	7,011		11,892
All other	190		838
Total deferred tax liability	8,277		12,999
Net deferred tax liability	$	1,394	$	690

At December 31, 2017, we have federal, state, and foreign net operating loss carryforwards/carrybacks equal to approximately $15.4 million, $1.5 million, and $0.9 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 2019 to 2036. 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 decrease in the valuation allowance during the year ended December 31, 2017 was $29.8 million. The change in the valuation allowance during 2017 primarily relates to the decrease in the federal statutory income tax rate from 35% to 21%. The increases in the valuation allowance during the years ended December 31, 2016 and 2015 were $33.0 million and $34.1 million, respectively. The change in the valuation allowance during 2016 primarily relates to deferred tax assets associated with losses generated in our U.S. corporate subsidiaries and certain foreign jurisdictions. 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, 2017 and 2016, 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 H — 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.

NOTE I — EQUITY-BASED COMPENSATION

2011 Long Term Incentive Plan

We havegranted phantom unit and performance phantom unit awards to certain employees, officers, and directors of our general partner pursuant to the CSI Compressco LP Amended and Restated 2011 Long Term Incentive Plan. Awards of phantom units generally vest over athreeyear 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 rightsthatenable 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 phantomunit 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, 2017, we granted to certain officers and employees an aggregate of290,190 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 $8.40 per unit, or an aggregate market value of $2.4 million.During the year ended December 31, 2016, we granted to certain officers and employees 396,692 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 $8.38 per unit, or an aggregate market value of $3.3 million.During the year ended December 31, 2015, we granted to certain officers and employees 180,136 restricted common unit awards, having an average market value (equal to the closing price of the common units on the dates of grant) of $20.35 per unit, or an aggregate market value of $3.9 million. The fair value of awards vesting during2017,2016, and 2015 was approximately $2.8 million, $1.5 million, and $1.1 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.

F-25

The following is a summary of unitactivity for the year ended December 31, 2017:

	Units		Weighted Average Grant Date Fair Value Per Unit
	(In Thousands)
Nonvested units outstanding at December 31, 2016(1)	609		$	13.41
Units granted	290		8.40
Exercised/released	(173	)	16.11
Cancelled/forfeited	(257	)	13.17
Nonvested units outstanding at December 31, 2017(2)	469		$	9.31

(1) This number excludes 289,830 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 176,159 performance-based phantom units, which, when combined with the 18,226 granted, (net of 2017 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 352,318.

Total estimated unrecognized equity-based compensation expense from unvested unitsas of December 31, 2017, was approximately $2.2 million and is expected to be recognized over a weighted average period of approximately 1.7 years. The amount recognized in2017, 2016, and 2015 was approximately $1.2 million, $3.0 million, and $2.2 million, respectively, and included in selling, general, and administrative expense.

NOTE J — MARKET RISKS AND DERIVATIVE CONTRACTS

We are exposed to financial and market risks that affect our businesses. 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. As a result of our variable rate bank credit facility, we face market risk exposure related to changes in applicable interest rates. We have concentrations of credit risk as a result of trade receivables owed to us by companies in the energy industry. Our financial risk management activities may at times involve, among other measures, the use of derivative financial instruments, such as swap and collar agreements, to hedge the impact of market price risk exposures.

Foreign Currency Derivative Contracts

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, 2017 and 2016, we had the following foreign currency derivative contracts outstanding relating to a portion of our foreign operations:

	December 31, 2017
	US Dollar Notional Amount		Traded Exchange Rate	Settlement Date
	(In Thousands)
Forward sale Mexican peso	$	6,067	19.28	1/18/2018

	December 31, 2016
	US Dollar Notional Amount		Traded Exchange Rate	Settlement Date
	(In Thousands)
Forward sale Mexican peso	$	2,483	20.18	1/18/2017

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

F-26

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 as reported to us by our counterparty (a Level 2 fair value measurement). The fair value of our foreign currency derivative instruments as of December 31, 2017 and 2016, are as follows:

	Balance Sheet	Fair Value at			Fair Value at
Foreign currency derivative instruments	Location	December 31, 2017			December 31, 2016
		(In Thousands)
Forward sale contracts	Current assets	$	130		57
Forward sale contracts	Current liabilities	(10		)	—
Total		$	120		57

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, 2017, 2016, and 2015, we recognized approximately $(38,000), $378,000, and $514,000 of net gains (losses), respectively, associated with our foreign currency derivative program, and such amount is included in other expense, net in the accompanying consolidated statement of operations.

NOTE K —EARNINGSPERCOMMON AND SUBORDINATED UNIT

The computations of earnings per common are based on the weighted average number of common outstanding during the applicable full-year period. Basic earnings per common 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 during the period.

When computing earnings per common under the two-class method in periods when distributions are greater than earnings, the amount of the distributions is deducted from net income 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,
	2017	2016	2015
	Common Units	Common Units	Common Units
Number of weighted average units outstanding	35,035,428	33,262,376	33,169,413
Unit awards outstanding	—	—	—
Average diluted units outstanding	35,035,428	33,262,376	33,169,413

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, 2017, 2016, and 2015 approximately 90,594, 9,707, and 29,372

F-27

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 are 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 is 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, 2017 and 2016.

NOTE L — SEGMENTS

ASC 280-10-50, “Operating Segments”, 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, net income, and EBITDA are not captured or analyzed by these items. 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 M — 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,
	2017		2016		2015
	(In Thousands)
Revenues from external customers:
U.S.	$	265,311	$	270,828	$	411,028
Latin America	23,493		32,673		36,843
Canada	3,678		2,666		4,282
Other	3,084		5,196		5,488
Total	$	295,566	$	311,363	$	457,641
Identifiable assets:
U.S.	$	691,588	$	733,077	$	907,028
Latin America	45,170		48,303		54,362
Canada	4,278		2,895		2,307
Other	1,896		1,865		2,930
Total identifiable assets	$	742,932	$	786,140	$	966,627

F-28

NOTE N — SUPPLEMENTAL GUARANTOR FINANCIAL INFORMATION

The $295.9 million in aggregate principal amount of the 7.25% Senior Notes as of December 31, 2017 is fully and unconditionally guaranteed, subject to certain customary release provisions, on a joint and several senior unsecured basis, by the following domestic restricted subsidiaries which are each a 100% owned subsidiary (each a "Guarantor Subsidiary" and collectively the "Guarantor Subsidiaries"):

Compressor Systems, Inc.

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

Pump Systems International, Inc.

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. 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.

Condensed Consolidating Balance Sheet

December 31, 2017

(In Thousands)

	Issuers		Guarantor Subsidiaries		Other Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets	$	—	$	78,942	$	23,205	$	—		$	102,147
Property, plant, and equipment, net	—		581,092		25,387		—			606,479
Investments in subsidiaries	169,411		19,146		—		(188,557		)	—
Intangible and other assets, net	—		33,688		618		—			34,306
Intercompany receivables	292,373		—		—		(292,373		)	—
Total non-current assets	461,784		633,926		26,005		(480,930		)	640,785
Total assets	$	461,784	$	712,868	$	49,210	$	(480,930	)	$	742,932
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities	$	8,306	$	49,639	$	3,027	$	—		$	60,972
Amounts payable to affiliate	—		1,475		1,559		—			3,034
Long-term debt	288,191		223,985		—		—			512,176
Series A Preferred Units	70,260		—		—		—			70,260
Intercompany payables	—		268,216		24,157		(292,373		)	—
Other long-term liabilities	—		142		1,321		—			1,463
Total liabilities	366,757		543,457		30,064		(292,373		)	647,905
Total partners' capital	95,027		169,411		19,146		(188,557		)	95,027
Total liabilities and partners' capital	$	461,784	$	712,868	$	49,210	$	(480,930	)	$	742,932

F-29

Condensed Consolidating Balance Sheet

December 31, 2016

(In Thousands)

	Issuers		Guarantor Subsidiaries		Other Subsidiaries		Eliminations			Consolidated
ASSETS
Current assets	$	35	$	74,574	$	27,395	$	—		$	102,004
Property, plant, and equipment, net	—		624,051		22,955		—			647,006
Investments in subsidiaries	214,703		15,112		—		(229,815		)	—
Intangible and other assets, net	—		36,794		336		—			37,130
Intercompany receivables	312,227		—		—		(312,227		)	—
Total non-current assets	526,930		675,957		23,291		(542,042		)	684,136
Total assets	$	526,965	$	750,531	$	50,686	$	(542,042	)	$	786,140
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities	$	8,089	$	31,789	$	3,856	$	—		$	43,734
Amounts payable to affiliate	874		3,780		1,526		—			6,180
Long-term debt	286,623		217,467		—		—			504,090
Series A Preferred Units	88,130		—		—		—			88,130
Intercompany payables	—		282,753		29,474		(312,227		)	—
Other long-term liabilities	—		39		718		—			757
Total liabilities	383,716		535,828		35,574		(312,227		)	642,891
Total partners' capital	143,249		214,703		15,112		(229,815		)	143,249
Total liabilities and partners' capital	$	526,965	$	750,531	$	50,686	$	(542,042	)	$	786,140

F-30

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 (benefit) 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		)	2,156			(1,078		)
Comprehensive income (loss)	$	(41,537	)	$	(12,223	)	$	4,034		$	8,189		$	(41,537	)

F-31

Condensed Consolidating Statement of Operations

and Comprehensive Income (Loss)

December 31, 2016

(In Thousands)

	Issuers			Guarantor Subsidiaries			Other Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	283,846		$	38,653		$	(11,136	)	$	311,363
Cost of revenues (excluding depreciation and amortization expense)	—			175,314			27,082			(11,136		)	191,260
Depreciation and amortization	—			69,327			2,796			—			72,123
Impairments of long-lived assets	—			10,154			69			—			10,223
Selling, general and administrative expense	3,969			30,574			1,679			—			36,222
Goodwill impairment	—			91,575			759			—			92,334
Interest expense, net	24,667			13,388			—			—			38,055
Series A Preferred FV Adjustment	5,036			—			—			—			5,036
Other expense, net	737			44			1,602			—			2,383
Equity in net income of subsidiaries	103,729			(3,798		)	—			(99,931		)	—
Income (loss) before income tax provision	(138,138		)	(102,732		)	4,666			99,931			(136,273		)
Provision (benefit) for income taxes	—			997			868			—			1,865
Net income (loss)	(138,138		)	(103,729		)	3,798			99,931			(138,138		)
Other comprehensive income (loss)	(2,018		)	(2,018		)	(2,018		)	4,036			(2,018		)
Comprehensive income (loss)	$	(140,156	)	$	(105,747	)	$	1,780		$	103,967		$	(140,156	)

F-32

Condensed Consolidating Statement of Operations

and Comprehensive Income (Loss)

December 31, 2015

(In Thousands)

	Issuers			Guarantor Subsidiaries			Other Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	435,954		$	42,956		$	(21,269	)	$	457,641
Cost of revenues (excluding depreciation and amortization expense)	—			280,479			31,450			(21,269		)	290,660
Depreciation and amortization	—			78,185			3,653			—			81,838
Impairments of long-lived assets	—			11,797			—			—			11,797
Selling, general and administrative expense	2,314			39,113			2,052			—			43,479
Goodwill impairment	—			138,035			1,409			—			139,444
Interest expense, net	26,740			8,224			—			—			34,964
Other expense, net	406			(272		)	2,056			—			2,190
Equity in net income of subsidiaries	117,170			(1,086		)	—			(116,084		)	—
Income (loss) before income tax provision	(146,630		)	(118,521		)	2,336			116,084			(146,731		)
Provision (benefit) for income taxes	—			(1,351		)	1,250			—			(101		)
Net income (loss)	(146,630		)	(117,170		)	1,086			116,084			(146,630		)
Other comprehensive income (loss)	(5,057		)	(5,057		)	(5,057		)	10,114			(5,057		)
Comprehensive income (loss)	$	(151,687	)	$	(122,227	)	$	(3,971	)	$	126,198		$	(151,687	)

F-33

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	—			(25,499		)	373			—			(25,126		)
Insurance recoveries associated with damaged equipment	—			2,352			—			—			2,352
Intercompany investment activity	33,187			—			—			(33,187		)	—
Advances and other investing activities	—			21			—			—			21
Net cash provided by (used in) investing activities	33,187			(23,126		)	373			(33,187		)	(22,753		)
Financing activities:
Proceeds from long-term debt	—			80,900			—			—			80,900
Payments of long-term debt	—			(74,900		)	—			—			(74,900		)
Proceeds from issuance of Series A Preferred	(37		)	—			—			—			(37		)
Distributions	(33,068		)	—			—			—			(33,068		)
Intercompany contribution (distribution)	—			(33,187		)	—			33,187			—
Financing costs and other	(82		)	(2,147		)	—			—			(2,229		)
Net cash provided by (used in) financing activities	(33,187		)	(29,334		)	—			33,187			(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

F-34

Condensed Consolidating Statement of Cash Flows

December 31, 2016

(In Thousands)

	Issuers			Guarantor Subsidiaries			Other Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	(26,052	)	$	86,348		$	1,148		$	—		$	61,444
Investing activities:
Purchases of property, plant, and equipment, net	—			(10,895		)	236			—			(10,659		)
Intercompany investment activity	51,254			—			—			(51,254		)	—
Advances and other investing activities	—			(22		)	—			—			(22		)
Net cash provided by (used in) investing activities	51,254			(10,917		)	236			(51,254		)	(10,681		)
Financing activities:
Proceeds from long-term debt	—			109,000			—			—			109,000
Payments of long-term debt	(50,882		)	(122,000		)	—			—			(172,882		)
Proceeds from issuance of Series A Preferred	76,934			—			—			—			76,934
Distributions	(51,254		)	—			—			—			(51,254		)
Intercompany contribution (distribution)	—			(51,254		)	—			51,254			—
Financing costs and other	—			(1,688		)	—			—			(1,688		)
Net cash provided by (used in) financing activities	(25,202		)	(65,942		)	—			51,254			(39,890		)
Effect of exchange rate changes on cash	—			—			(696		)	—			(696		)
Increase (decrease) in cash and cash equivalents	—			9,489			688			—			10,177
Cash and cash equivalents at beginning of period	—			2,712			7,908			—			10,620
Cash and cash equivalents at end of period	$	—		$	12,201		$	8,596		$	—		$	20,797

F-35

Condensed Consolidating Statement of Cash Flows

December 31, 2015

(In Thousands)

	Issuers			Guarantor Subsidiaries			Other Subsidiaries			Eliminations			Consolidated
Net cash provided by (used in) operating activities	$	—		$	84,351		$	17,542		$	—		$	101,893
Investing activities:
Purchases of property, plant, and equipment, net	—			(76,553		)	(18,719		)	—			(95,272		)
Intercompany investment activity	68,360			—			—			(68,360		)	—
Advances and other investing activities				(69		)	—						(69		)
Net cash provided by (used in) investing activities	68,360			(76,622		)	(18,719		)	(68,360		)	(95,341		)
Financing activities:
Proceeds from long-term debt	—			63,000			—			—			63,000
Payments of long-term debt	—			(23,000		)	—			—			(23,000		)
Distributions	(68,360		)	—			—			—			(68,360		)
Intercompany contribution (distribution)	—			(68,360		)	—			68,360			—
Net cash provided by (used in) financing activities	(68,360		)	(28,360		)	—			68,360			(28,360		)
Effect of exchange rate changes on cash	—			—			(1,638		)	—			(1,638		)
Increase (decrease) in cash and cash equivalents	—			(20,631		)	(2,815		)	—			(23,446		)
Cash and cash equivalents at beginning of period	—			23,343			10,723			—			34,066
Cash and cash equivalents at end of period	$	—		$	2,712		$	7,908		$	—		$	10,620

NOTE O — QUARTERLY FINANCIAL INFORMATION (Unaudited)

Summarized quarterly financial data for 2017and2016is as follows:

	Three Months Ended 2017
	March 31			June 30			September 30			December 31
	(In Thousands, Except Per Share Amounts)
Total revenues	$	65,552		$	75,315		$	71,598		$	83,101
Net income (loss)	(15,593		)	(6,372		)	(7,821		)	(10,673		)
Net income (loss) per common unit	$	(0.46	)	$	(0.18	)	$	(0.22	)	$	(0.29	)
Net income (loss) per diluted common unit	$	(0.46	)	$	(0.21	)	$	(0.22	)	$	(0.29	)

	Three Months Ended 2016
	March 31			June 30			September 30			December 31
	(In Thousands, Except Per Share Amounts)
Total revenues	81,692			76,089			70,714			82,868
Net income (loss)	(105,349		)	(4,680		)	(15,971		)	(12,138		)
Net income (loss) per common unit	$	(3.11	)	$	(0.14	)	$	(0.47	)	$	(0.36	)
Net income (loss) per diluted common unit	$	(3.11	)	$	(0.14	)	$	(0.47	)	$	(0.36	)

F-36

Net loss for the three months ended March 31, 2016, includes the impact of $92.3 million for goodwill impairment and $7.9 million for certain impairments of long-lived assets. Net loss for the three months ended December 31, 2016, includes the impact of $2.4 million for impairments of long-lived assets.

NOTE P — SUBSEQUENT EVENTS

On January 22, 2018, our General Partner declared a cash distribution attributable to the quarter ended December 31, 2017of $0.1875 per common unit. This distribution equates to a distribution of $0.75 per outstanding common unit on an annualized basis. Also on January 22, 2018, our General Partner approved the paid in kind distribution of 172,210 Preferred Units attributable to the quarter ended December 31, 2017 in accordance with the provisions of our partnership agreement, as amended. These distributions were paid on February 14, 2018, to the holders of common units and Preferred Units, respectively, of record as of the close of business February 1, 2018.

On January 8, 2018, 298,760 Preferred Units were converted into 692,665 common units. On February 8, 2018, 298,760 Preferred Units were converted into 634,729 common units.

F-37