CSI Compressco (CCLP) 10-K2022 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

COMMISSION FILE NUMBER 001-35195

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

TABLE OF CONTENTS

 

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.

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

About CSI Compressco LP

We are a provider of contract services related to the exploration and production of oil and natural gas, including natural gas compression services and treating services. Natural gas compression is used for oil and natural gas production, gathering, artificial lift, transmission, processing, and storage. Treating services include removal of contaminants from a natural gas stream and cooling to reduce the temperature of produced gas and liquids. We also sell used standard compressor packages and provide aftermarket services and compressor package parts and components manufactured by third-party suppliers. We provide contract compression and treating services and compressor parts and component sales to a broad base of natural gas and oil exploration and production, midstream, transmission, and storage companies operating throughout many of the onshore producing regions of the United States, as well as in a number of international locations, including the countries of Mexico, Canada, Argentina, Egypt and Chile.

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

Our aftermarket business provides a wide range of services and compressor package parts and components manufactured by third-party suppliers to support the needs of customers who own compression equipment. These services include operations, maintenance, overhaul, and reconfiguration services and may be provided under turnkey engineering, procurement and construction contracts. Our aftermarket services are provided by our factory- and internally-trained technicians in most of the major oil and natural gas producing basins in the United States and Mexico.

Our long-term growth strategy includes expanding our existing businesses through organic growth and accretive acquisitions, both in the U.S. and internationally.

Our operations are organized into a single business segment. See Note 15 - “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 16 - “Geographic Information” contained in the Notes to Consolidated Financial Statements in this Annual Report.

Contribution of Spartan entities

On November 10, 2021, the Partnership entered into a Contribution Agreement (the “Contribution Agreement”) by and among the Partnership, CSI Compressco GP, Spartan, and CSI Compressco Sub Inc., a Delaware corporation (“Compressco Sub”). Pursuant to the terms of the Contribution Agreement, Spartan contributed to the Partnership 100% of the limited liability company interest in Treating Holdco, LLC, a Delaware limited liability company (“Treating Holdco”), 100% of the common stock in Spartan Terminals Operating, Inc., a Delaware corporation (“Spartan Terminals”), and 99% of the limited liability company interests in Spartan Operating Company LLC, a Delaware limited liability company (“Spartan Operating” and together with Treating Holdco and Spartan Terminals, “Spartan Treating”) (such interests in Spartan Treating, the “Contributed Interests”) and the Partnership, CSI Compressco GP and Spartan agreed to cancel the incentive distribution rights (the “IDRs”) in the Partnership in exchange for the issuance of 48.4 million common units. We refer to the acquisition of the Contributed Interests as the “Spartan Acquisition.” As the Partnership and Spartan Treating were under common control at the time of the Spartan Acquisition, the results of operations have been combined for the Partnership and Spartan Treating from the date of common control which was January 29, 2021.

Certain of our U.S. services are performed by our wholly owned subsidiary CSI Compressco Operating LLC, a Delaware limited liability company (our “Operating LLC”), pursuant to contracts that our outside legal counsel has concluded generate qualifying income under Section 7704 of the Internal Revenue Code of 1986, as amended (the “Code”), or “qualifying income.” We do not pay U.S. federal income taxes on the portion of our business conducted by Operating LLC. Compressco Sub, which is also a wholly owned subsidiary of ours, conducts substantially all of our operations that our outside legal counsel has not concluded generate qualifying income, and we pay U.S. federal income tax with respect to such operations. We strive to ensure that all new U.S. compression contracts are entered into by our Operating LLC and generate qualifying income. We also pay state and local income taxes in certain states, and we incur income taxes related to our foreign operations.

As a limited partnership, we are managed and controlled by our general partner. On January 29, 2021, Spartan acquired from TETRA our general partner, our IDRs and 10.95 million of our common units in the Partnership (the “GP Sale”). As of March 9, 2023, common units held by the public represented approximately a 54.7% ownership interest, which is exclusive of Spartan’s 44.9% limited partner interest and 0.5% general partner interest. In connection with the GP Sale, on January 29, 2021, TETRA entered into a Transition Services Agreement (the “Transition Services Agreement”) with the Partnership, pursuant to which TETRA provided certain accounting, information technology and back-office support services to the Partnership for a period of one year following closing. The Transition Services Agreement with TETRA expired on January 31, 2022.

    Through Spartan’s wholly owned subsidiary and our general partner, CSI Compressco GP LLC, Spartan manages and controls us. We rely on our general partner’s board of directors and executive officers to manage our operations and make decisions on our behalf. Our general partner is an indirect, wholly owned subsidiary of Spartan. Unlike shareholders in a publicly traded corporation, our unitholders are not entitled to elect our general partner or its directors. Following the GP Sale, all of our general partner’s directors are elected by Spartan. Our general partner does not receive any management fee in connection with its management of our business. However, our general partner is reimbursed for certain expenses, including compensation expenses, incurred on our behalf. In addition, our general partner receives distributions based on its limited and general partner interests.

Products and Services

    We are a provider of contract services including natural gas compression services and treating services. Natural gas compression is a mechanical process in which the pressure of a given volume of natural gas is increased to a higher pressure. It is essential to the production and movement of natural gas. Compression is typically required numerous times in the natural gas production and sales cycle, including (i) at the wellheads, (ii) throughout gathering and distribution systems, (iii) into and out of processing and storage facilities, and (iv) in natural gas pipelines. Compression is also utilized for gas lift, an artificial lift technique for producing oil that has insufficient reservoir pressure. Natural gas treating encompasses several processes used to remove contaminants and improve the marketability of gas. We also provide aftermarket compression services and compressor package parts and components manufactured by third-party suppliers.

    We use our fleet of compressor packages to provide a variety of compression services to our customers to meet their specific requirements. Our fleet includes approximately 4,600 compressor packages that provide

approximately 1.2 million in aggregate horsepower, employing a wide spectrum of low-, medium-, and high-horsepower engines. The horsepower of our natural gas compressor package fleet as of December 31, 2022 is summarized in the following table:

 

    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, telemetry-based reporting system, we remotely monitor, in real time, whether our services are being continuously provided at our U.S. customer well sites.

    As owner of the equipment, we are obligated to pay ad valorem taxes levied on the equipment and related insurance expenses, and we typically do not seek reimbursement for such taxes and expenses from our service agreement customers.

Market Overview and Competition

 

    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 Canada, Mexico, Argentina, Egypt and Chile. While most of our services in the U.S. are performed throughout Texas (with a concentration in the Permian Basin), the Haynesville shale, the San Juan Basin, the Rocky Mountain region, and the Mid-Continent region, we also have a presence in the Marcellus / Utica and other producing regions. We continue to evaluate opportunities to further expand our operations into other regions in the U.S. and elsewhere in the world.

Other Business Matters

    We use various marketing strategies to promote our services and compressor package products. Our account managers work to build close working relationships with our existing and potential future customers, educating them about our services and products by scheduling personal visits, hosting and attending workshops, tradeshows and conferences, and participating in industry organizations. We sponsor and make presentations at industry events that are targeted to production managers, compression specialists and other decision makers. Our marketing representatives also use these marketing opportunities to promote our value-added service initiatives, such as the use of our proprietary telemetry-based system, our wellsite optimization program and our fleet reliability center.

collective bargaining agreements. We believe that the various employers of these employees have good relations with these employees and we have not experienced work stoppages in the past.

Diversity and Inclusion

Career Development

Compensation and Benefits

Safety

    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.

significant costs and liabilities will not be incurred now or in the future. Changes in health, safety, and environmental laws and regulations could subject us to more rigorous standards and could affect demand for our customer’s product which in turn would impact demand for our products. We cannot predict the extent to which our operations may be affected by any changes to existing laws, regulations, and enforcement policies, new interpretations of existing laws, regulations, and policies, or any new laws, regulations, or policies promulgated in the future.

    We are subject to numerous federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of human health and the environment. The primary environmental laws that impact our operations in the U.S. include:

    Our operations in the U.S. 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 CAA and implementing regulations, and comparable state laws and regulations, regulate emissions of air pollutants from various industrial sources and impose various monitoring and reporting requirements, including requirements related to emissions from certain stationary engines, including our compressor packages. These laws and regulations impose limits on the levels of various substances that may be emitted into the atmosphere from our compressor packages and require us to meet stringent air emission standards and install new emission control equipment on all of our engines built after July 1, 2008. In addition, regulations under the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) provisions of the CAA require control of hazardous air pollutants from new and existing stationary reciprocal internal combustion engines. Our equipment is also subject to prescribed maintenance practices and catalyst installation may also be required. Furthermore, in June 2016, the Environmental Protection Agency (“EPA”) finalized rules that establish new air emission controls under the EPA’s New Source Performance Standards (“NSPS”) and NESHAP for natural gas and natural gas liquids production, processing and transportation activities. These rules establish specific requirements associated with volatile organic compounds and methane emissions from compressor packages and controllers at natural gas gathering and boosting stations. While the EPA under the Trump Administration finalized rules to rescind or modify certain of these requirements in September 2020, including removing sources in the transmission and storage segment from the source category and rescinding the methane-specific requirements applicable to sources in the production and processing segments of the oil and gas industry, various states and industry and environmental groups are separately challenging the EPA’s June 2016 standards and its September 2020 final rule. However, the U.S. Congress passed, and President Biden signed into law, a revocation of the 2020 rulemaking effectively reinstating the 2016 standards. Additionally, in November 2021, the EPA issued a proposed rule that, if finalized, would establish OOOOb new source and OOOOc first-time existing source standards of performance for GHG and volatile organic compound (“VOC”) emissions for crude oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities. Owners or operators of affected emission units or processes would have to comply with specific standards of performance that may include leak detection using optical gas imaging and subsequent repair requirements, reduction of emissions by 95% through capture and control systems, zero-emission requirements, operations and maintenance requirements, and so-called “green well” completion requirements. The EPA issued a supplemental proposal enhancing this proposed rulemaking in 2022 and anticipates issuing a final rule in 2023. While we are not currently aware of any material impacts to our operations associated with the current regulatory requirements, additional or more stringent regulations could impose new air permitting or pollution control requirements on our equipment that could require us to incur material costs. Additionally, in 2022 the Inflation Reduction Act (“IRA 2022”) was signed into law, which imposes the first ever federal methane fee on excess methane emissions from sources required to report their GHG emissions to the EPA.

    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.

    RCRA and implementing regulations, and comparable state laws and regulations, address the management and disposal of solid and hazardous waste. These laws and regulations govern the generation, storage, treatment, transfer, and disposal of wastes including, but not limited to, used oil, antifreeze, filters, sludges, paint, solvents and sandblast materials. The EPA and various state agencies have limited the approved methods of disposal for these types of wastes.

    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.

    Although we believe that we have properly disposed of all historical waste streams and that we have no outstanding liability regarding any past waste handling or spill activities, there is always the possibility that future spills and releases of petroleum hydrocarbons, wastes, or other regulated substances into the environment could cause us to become subject to remediation costs and liabilities under CERCLA, RCRA, or other environmental laws. The costs and liabilities associated with the future imposition of remedial obligations could have the potential for a material adverse effect on our operations or financial position.

    We are also subject to the requirements of OSHA and comparable state statutes. These laws and regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA, and similar state statutes require that we maintain and/or disclose information about hazardous materials used or produced in our operations.

Related Party Agreements

    

    For a more comprehensive discussion on agreements we have entered into with related parties, please see “Item 13 - Certain Relationships and Related Transactions, and Director Independence.”

Item 1A. Risk Factors.

Certain Business Risks

 

    Although it is not possible to identify all of the risks we encounter, we have identified the following significant risk factors that could affect our actual results and cause actual results to differ materially from any such results that might be projected, forecasted, or estimated by us in this Annual Report.

 

    Our operations are significantly dependent upon the demand for, and production of, oil and natural gas in the various U.S. and international markets in which we operate. Oil and natural gas production rates are volatile and may be affected by, among other factors, prices for such commodities, market uncertainty, weather and availability of alternative energy sources.

    Oil prices steadily rose during the first half of 2022 because of lower inventory related to Russia’s full-scale invasion of Ukraine in late February and higher demand resulting from rising economic activity after pandemic-related restrictions eased. From early June through the remainder of 2022, oil prices decreased as concerns about a possible economic recession and severe COVID-19 containment measures in China reduced global demand. West Texas Intermediate oil prices reached a high of $123.64 per barrel in March 2022 and a low of $71.05 per barrel in December 2022. The West Texas Intermediate price averaged $94.84 per barrel during 2022. Over this same period, U.S. natural gas prices have been volatile, with the Henry Hub price ranging from a high of $9.85 per million British thermal units ("MMBtu") in August 2022 due to a record-high summer power burn, to a low of $3.46 per MMBtu in November 2022 as a result of above-normal temperatures. The natural gas price began to increase again in December because of dropping winter temperatures that increased demand for natural gas for heating. The Henry Hub price averaged $6.45 per MMBtu during 2022, the highest annual average since 2008. As of March 6, 2023, the price of West Texas Intermediate oil was $80.39 per barrel and the Henry Hub price for natural gas was $2.46 per MMBtu. The prolonged volatility of oil and natural gas prices and persisting supply and demand imbalances have impacted the levels of exploration, development, and production activity. If oil and natural gas

prices decline significantly, and the supply and demand imbalance persists, there would be a material adverse effect on our business, consolidated results of operations, and consolidated financial condition. Should current market conditions worsen for an extended period of time, we may be required to record additional asset impairments. Such potential impairment charges could have a material adverse impact on our operating results.

    Factors affecting the prices of oil and natural gas include: the levels of supply and demand for oil and natural gas, worldwide; governmental regulations, including the policies of governments regarding the exploration for and production and development of their oil and natural gas reserves; weather conditions, natural disasters, and health or similar issues, such as pandemics or epidemics; worldwide political, military, and economic conditions; the ability or willingness of the Organization of Petroleum Exporting Countries ("OPEC") and non-OPEC countries, such as Russia, to set and maintain oil production levels; the levels of oil production in the U.S. and by other non-OPEC countries; oil refining capacity and shifts in end-customer preferences toward fuel efficiency and the use of natural gas; the cost of producing and delivering oil and natural gas; and acceleration of the development of, and demand for, alternative energy sources.

During the first half of 2021, the COVID-19 pandemic and the resulting economic impact had a significant negative impact on the oil and gas industry. The deterioration in demand for oil caused by the pandemic, coupled with oil oversupply had an adverse impact on the demand for our services. Although global demand for oil and natural gas began to rebound in 2021, a worsening of the pandemic, and the resulting actions that may be taken in the future by governments, various regulatory agencies, our customers and our suppliers may in the future have certain negative impacts on our financial condition, results of operations, and liquidity. In addition, the impact of COVID-19 in China continues to impact the global demand for oil and gas.

Any of the negative impacts of the COVID-19 pandemic, including those described above, alone or in combination with others, may have a significant adverse effect on our financial condition, results of operations, or liquidity. Any of these negative impacts, alone or in combination with others, could exacerbate many of the risks discussed elsewhere in these “Risk Factors.”

Continuing or worsening inflationary issues and associated changes in monetary policy have resulted in and may result in additional increases in the cost of our goods, services and labor, which in turn may cause our capital expenditures and operating costs to rise.

We may be unable to repurchase our 7.50% First Lien Notes due 2025 and 10.000%/10.750% Second Lien Notes due 2026 in the event of a change of control as required by their respective indentures.

Holders of our 7.50% First Lien Notes due 2025 (the “First Lien Notes”) and 10.000%/10.750% Second Lien Notes due 2026 (the “Second Lien Notes”) have the right to require us to repurchase their notes at a price equal to 101% of the principal amount, in each case, upon the occurrence of any specified change of control event.

Any change of control also would constitute a default under our Credit Agreement. Therefore, upon the occurrence of a change of control, the lenders under our Credit Agreement would have the right to accelerate the

    The aggregate carrying value of our First Lien Notes and Second Lien Notes as of December 31, 2022 are $400.3 million and $172.5 million, respectively. In addition, we have an aggregate carrying value of $54.9 million and $6.3 million outstanding on our Spartan Credit Agreement and our CSI Credit Agreement, respectively, as of December 31, 2022. The interest expense related to our long-term indebtedness reduces our cash available to fund capital expenditures or for distribution. Our ability to service our indebtedness in the future will depend upon, among other things, our future financial and operating performance, which will be impacted by prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we may be forced to consider taking actions such as reducing or delaying our business activities, acquisitions, investments and/or capital expenditures, delaying any desired increase of distributions, selling assets, restructuring or refinancing our indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to take any of these courses of action.

    Many of our operating expenses have been volatile and may continue to be volatile or increase in the future. To the extent our efforts to contain these costs are not successful, our generation of operating cash flows to fund or increase our quarterly distributions will be negatively impacted.

    Our Credit Agreement includes a maximum credit commitment of $35.0 million, which is available for loans, letters of credit (with a sublimit of $25.0 million), and swingline loans (with a sublimit of $3.5 million), subject to a borrowing base determined by reference to the value of certain of our accounts receivable and inventory. We are required to maintain a $3.5 million reserve with respect to the borrowing base, which results in reduced liquidity. The maximum credit commitment may be increased by $25.0 million, subject to the terms and conditions of the Credit Agreement. The Credit Agreement contains certain affirmative and negative covenants, including covenants that restrict our ability to take certain actions including, among other things and subject to certain significant exceptions, incurring debt, granting liens, making investments, entering into or amending existing transactions with affiliates, paying dividends, and selling assets.

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 business risk profile of Spartan 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 Spartan and its affiliates in assigning a rating because of Spartan’s control of us, their performance of certain administrative functions for us, and our contractual relationships with them. Furthermore, the trading price of our common units may be adversely affected by financial or operational difficulties or excessive debt levels at Spartan. If the pledge of Spartan ownership of our general partner becomes effective in the future, control over our general partner could be transferred to Spartan’s lenders in the event of a default by Spartan.

Our ability to manage and grow our business effectively and provide quality services to our customers may be adversely affected if our general partner loses its management or is unable to retain trained personnel.

We rely primarily on the executive officers and other senior management of our general partner and Spartan to manage our operations and make decisions on our behalf. Our ability to provide quality compression services depends to a significant extent upon our general partner’s and Spartan’s ability to hire, train, and retain an adequate number of trained personnel. The departure of any of our general partner’s executive officers or other senior management could have a significant negative effect on our business, operating results, financial condition, and our ability to compete effectively in the marketplace. In connection with Spartan’s acquisition of our general partner, most of our general partner’s executive officers and other senior management resigned their positions, and Spartan appointed new officers in their place. Such significant turnover in management of our general partner could have negative impact on our business. We operate in an industry characterized by highly competitive labor markets, and, similar to many of our competitors, we have experienced high employee turnover in certain regions. It is possible that our labor expenses could increase if there is a shortage in the supply of skilled regional service supervisors and other service professionals. Our general partner may be unable to maintain an adequate skilled labor force necessary for us to operate efficiently and to support our growth strategy. Failure to do so could impair our ability to operate efficiently and to retain current customers and attract prospective customers, which could cause our business to suffer materially. Additionally, increases in labor expenses may have an adverse impact on our operating results and may reduce the amount of cash available for distribution to our common unitholders.

Beginning in 2020 and continuing into 2021, decreased commodity prices had a negative impact on oil and gas drilling and capital expenditure activity, which affected the demand for a portion of our products and services. In the latter half of 2021 and through 2022, the prices of and demand for oil and natural gas began to recover to prior levels. If prices or demand levels begin to decline again, demand for our products and services may significantly decrease, which could impact the expected utilization rates of our compressor package fleet.

Although equipment used in providing services to our customers is normally readily available, market conditions could trigger constraints in the supply chain of certain equipment, and replacement parts for such equipment, used in providing services to our customers. If we experience future supply chain disruptions, it could also impact the expected utilization rate of our compressor package fleet.

Under U.S. GAAP, we review the carrying value of our long-lived assets when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable, based on their expected future cash flows. The impact of reduced expected future cash flow could require the write-down of all or a portion of the carrying value for these assets, which would result in impairments, resulting in decreased earnings.

We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.

Our assets and operations are subject to inherent risks such as vehicle accidents, equipment defects, malfunctions and failures, as well as other incidents that result in releases or uncontrolled flows of gas or well fluids, fires, or explosions. These risks could expose us to substantial liability for personal injury, death, property damage, pollution, and other environmental damages. On occasion, we have experienced fires that have damaged or destroyed certain units in our compression services fleet, and additional accidents or fires could occur in the future. We do not insure all of our assets and the insurance we do obtain may be inadequate to cover our liabilities.

    Sanctions imposed by the U.S. Office of Foreign Assets Control (“OFAC”) prohibit our operations in or sales to customers in certain non-U.S. markets. We are also subject to the FCPA, which prohibits U.S. companies and their intermediaries from bribing overseas 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 non-U.S. counterparts, including the UK Bribery Act, contain similar prohibitions, although varying in both scope and jurisdiction. We operate in parts of the world that have experienced governmental corruption in the past.

    We have policies and procedures to maintain our compliance with the FCPA, OFAC sanctions, export controls, and similar laws and regulations. The implementation of such policies and procedures may be time consuming and expensive and could result in the discovery of issues or violations with respect to the foregoing by us or our employees, independent contractors, subcontractors, or agents of which we were previously unaware. If we violate any of these regulations, significant administrative, civil, and criminal penalties could be assessed on us. In addition, foreign governments and agencies often establish permit and regulatory standards different from those in the U.S. If we cannot obtain foreign regulatory approvals or cannot obtain them in a timely manner, our growth and profitability from international operations could be adversely affected.

    In recent years, incidents of security disruptions throughout many regions of Mexico have increased. Drug-related gang activity has grown in Mexico. Certain incidents of violence have occurred in regions in which we operate and have resulted in the interruption of our operations, and these interruptions could increase in the future. To the extent that such security disruptions increase, the levels of revenue and operating cash flow from our Mexican operations could be reduced.

    The current economic, legal, and political environment in Argentina and the recent devaluations of the Argentinian peso have created increased instability for foreign investment in Argentina. The Argentinian government is currently attempting to address the current high rate of inflation and the continuing currency devaluation pressure. Fiscal and monetary expansion in Argentina has led to devaluations of the Argentinian peso. Additional devaluation may be necessary to help boost the current Argentina economy, and they may be accompanied by fiscal and monetary tightening, including additional restrictions on the transfer of U.S. dollars out of Argentina. On June 30, 2018, we determined the economy in Argentina to be highly inflationary. As a result of this determination and in accordance with U.S. generally accepted accounting principles ("GAAP"), on July 1, 2018, the functional currency of our operations in Argentina was changed from the Argentine peso to the U.S. dollar. The remeasurement did not have a material impact on our consolidated financial position or results of operations.

    As a result of our operations in Argentina, consolidated revenues and operating cash flow generated in Argentina have experienced growth over the past five years. The process of repatriating this cash to the U.S. is subject to increasingly complex regulations. There can be no assurances that our growing Argentinian operations will not expose us to the loss of liquidity, foreign exchange losses, and other potential financial impacts.

    The personnel conducting our operations in Mexico are currently subject to collective labor agreements. These collective labor agreements consist of “evergreen” contracts that have no expiration date and whose terms remain in full force and effect from year-to-year, unless the parties agree to negotiate new terms. The employees subject to these “evergreen” agreements may, however, request a renegotiation of their employee compensation terms on an annual basis or a renegotiation of the entire agreement on a biannual basis, although we are not required to honor any such request. The personnel conducting operations in Argentina are also subject to collective labor agreements. We have not experienced work stoppages in Mexico or Argentina in the past but cannot guarantee that we will not experience work stoppages in the future. A prolonged work stoppage could adversely impact our revenues, cash flows, and net income. Mexico’s Federal Labor Law was reformed effective August 1, 2021, in relation to labor subcontracting which resulted in an increase in Statutory Profit Sharing (PTU).

Terrorist activities, anti‑terrorist efforts, war and other armed conflicts and political or civil unrest could adversely affect the U.S. and global economies and could prevent us from meeting financial and other obligations. We could experience loss of business, delays or defaults in payments from payors or disruptions of fuel supplies and markets if pipelines, production facilities, processing plants, refineries or transportation facilities are direct targets or indirect casualties of an act of terror or war. Such activities could reduce the overall demand for oil and natural gas, which, in turn, could also reduce the demand for our services. War and other armed conflicts, including conflict related to Russia’s invasion of Ukraine, and any resulting economic downturn could adversely affect our results of operations, impair our ability to raise capital or otherwise adversely impact our ability to realize certain business strategies. In addition, sanctions imposed on foreign countries by the U.S. or other foreign governments could adversely affect our results of operations, impair our ability to raise capital or otherwise adversely impact our ability to realize certain business strategies.

    Because we have operations in Mexico, Canada, Argentina, Chile and Egypt, and in certain other non-U.S. jurisdictions, a portion of our business is conducted in foreign currencies. As a result, we are exposed to currency exchange rate fluctuations that could have an adverse effect on our results of operations. If a foreign currency weakened significantly, we would be required to convert more of that foreign currency to U.S. dollars to satisfy our obligations, which would cause us to have less cash available for distribution. A significant strengthening of the U.S. dollar could result in an increase in our financing expenses and could materially affect our financial results under U.S. GAAP. Because we report our operating results in U.S. dollars, changes in the value of the U.S. dollar also result in fluctuations in our reported revenues and earnings. Most of our billings under the contracts with PEMEX and other clients in Mexico are in U.S. dollars; however, a large portion of our expenses and costs under those contracts are incurred in Mexican pesos. In addition, future contract awards with PEMEX may require us to bill a larger portion of our revenues in Mexican pesos, which would expose us to additional foreign currency exchange rate risks.

    As a result of the above, we are exposed to fluctuations in the values of the Mexican peso, Argentinian peso, Chilean peso, and the Egyptian pound against the U.S. dollar. A material increase in the values of these foreign currencies relative to the U.S. dollar would adversely affect our cash flows and net income. On June 30, 2018, we determined the economy in Argentina to be highly inflationary. As a result of this determination and in accordance with U.S. GAAP, on July 1, 2018, the functional currency of our operations in Argentina was changed from the Argentine peso to the U.S. dollar. In addition, for our operations in Canada, where the Canadian dollar is the functional currency under U.S. GAAP, all U.S. dollar-denominated monetary assets and liabilities, such as cash and cash equivalents, accounts receivable, restricted cash, accounts payable, long-term debt and capital lease obligations, are revalued and reported based on the prevailing exchange rate at the end of the reporting period. This revaluation may cause us to report significant foreign currency exchange gains and losses in certain periods.

    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 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.

    The EPA has adopted regulations to restrict emissions of GHGs under existing provisions of the CAA. Such EPA rules regulate GHG emissions under the CAA and require a reduction in emissions of GHGs from motor vehicles and from certain large stationary sources. For example, the EPA published final rules in June 2016 that require the reduction of volatile organic compounds and methane emissions from certain hydraulically fractured natural gas wells and further require that most wells use so-called “green” completions at certain hydraulically fractured natural gas wells. These regulations also established new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. Certain of our compressor packages are subject to these requirements and additional control equipment and maintenance operations are required. While the EPA under the Trump Administration finalized rules to rescind or modify certain of these requirements in September 2020, including rescission of the methane-specific requirements applicable to sources in the production and processing segments of the oil and gas industry, various states and industry and environmental groups are separately challenging the EPA’s 2016 standards and its September 2020 final rule. However, the U.S. Congress passed, and President Biden signed into law, a revocation of the 2020 rulemaking effectively reinstating the 2016 standards. Additionally, in November 2021, the EPA issued a proposed rule that, if finalized, would establish OOOOb new source and OOOOc first-time existing source standards of performance for GHG and volatile organic compound (“VOC”) emissions for the crude oil and natural gas well sites, natural gas gathering and boosting compressor stations, natural gas processing plants, and transmission and storage facilities. Owners or operators of affected emission units or processes would have to comply with specific standards of performance that may include leak detection using optical gas imaging and subsequent repair requirements, reduction of emissions by 95% through capture and control systems, zero-emission requirements, operations and maintenance requirements, and so-called “green well” completion requirements. The EPA issued a supplemental proposal enhancing this proposed rulemaking in 2022, which, among other items, sets forth specific revisions strengthening the first nationwide emissions guidelines for states to limit methane emissions from existing oil and natural gas facilities. The proposal also revises requirements for fugitive emissions monitoring and repair as well as equipment leaks and the frequency of monitoring surveys, establishes a “super-emitter” response program to timely mitigate emissions events, and provides additional options for the use of advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions. The proposal is currently subject to public comment and is expected to be finalized in 2023; however, it is likely that these requirements will be subject to legal challenges. While we do not believe that compliance with current regulatory requirements will have a material adverse effect on our business, additional or more stringent regulations could impose new air permitting or pollution control requirements on our equipment that could require us to incur material costs. In addition, the EPA requires the annual reporting of GHG emissions from specified large GHG emission sources in the U.S., including petroleum refineries, as well as from certain oil and gas production facilities.

 

    In addition, in December 2015, over 190 countries, including the U.S., reached an agreement to reduce global GHG emissions (the “Paris Agreement”). The Paris Agreement entered into force in November 2016 after more than 170 nations, including the U.S., ratified or otherwise indicated their intent to be bound by the Paris Agreement. Although the U.S. withdrew from the Paris Agreement in November 2020, President Biden recommitted the United States in February 2021, and, in April 2021, announced a new, more rigorous nationally determined emissions reduction level of 50-52% reduction from 2005 levels in economy-wide net GHG emissions by 2030. The international community gathered in Glasgow in November 2021 at the 26th Conference to the Parties (“COP26”) during which multiple announcements were made, including a call for parties to eliminate fossil fuel subsidies, amongst other measures. Relatedly, the United States and European Union jointly announced at COP26 the launch of the Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector. These goals were reaffirmed at COP27 in November 2022, and countries were called upon to accelerate efforts to phase out inefficient fuel subsidies, though no firm commitments or timelines were made. The full impact of these actions is uncertain at this time, and it is unclear what additional initiatives may be adopted or implemented that may have adverse effects on us and our customers’ operations.

    President Biden has also issued executive orders that commit to substantial action on climate change, calling for, among other things, the increased use of zero-emissions vehicles by the federal government, the elimination of subsidies provided to the fossil fuel industry, and an increased emphasis on climate-related risk across government agencies and economic sectors. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our facilities and operations could require us to incur costs. Further, Congress has considered and almost one-half of the states have adopted legislation that seeks to control or reduce emissions of GHGs from a wide range of sources, and has passed laws such as the IRA 2022 that advance numerous climate-related activities. Any such legislation could adversely affect demand for the oil and natural gas our customers produce and, in turn, demand for our products and services. Litigation risks are also increasing as a number of parties have sought to bring suit against certain oil and natural gas companies in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time, but defrauded their investors or customers by failing to adequately disclose those impacts.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns, that could adversely impact our operations. Such physical risks may result in damage to our customers’ facilities and otherwise adversely impact their operations, such as if they become subject to water use curtailments in response to drought, or demand for their products, such as to the extent warmer winters reduce the demand for energy for heating purposes. If any such effects were to occur, they could have an adverse effect on our operations and cause us to incur costs in preparing for or responding to those effects.

    Hydraulic fracturing typically is regulated by state oil and gas commissions or similar state agencies, but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA asserted regulatory authority pursuant to the federal Safe Drinking Water Act, Underground Injection Control program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities; published final rules under the CAA in 2012 and published additional final regulations in June 2016 governing methane and volatile organic compound performance standards, including standards for the capture of air emissions released by 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 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 2016 that established new or more stringent standards for performing hydraulic fracturing on federal and Indian lands. BLM under the Trump Administration

issued a final rule in late 2018 rescinding the 2016 action; however, a California federal court vacated the 2018 final rule in July 2020, and a Wyoming federal court subsequently vacated the 2016 final rule in October 2020. Accordingly, the 2016 final rule is no longer in effect, but the Wyoming decision is expected to be appealed. Moreover, the Biden Administration is expected to pursue regulatory initiatives that regulate hydraulic fracturing activities on federal lands as well as other actions to more stringently regulate certain aspects of oil and gas development such as air emissions and water discharges. In 2021, the Biden Administration took multiple actions to pause new oil and gas leases and drilling permits on non-Indian federal lands and waters for a period of 60 days. In addition, President Biden issued an executive order on January 27, 2021, that suspends new leasing activities for oil and gas exploration and production on non-Indian federal lands and offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices that take into consideration potential climate and other impacts associated with oil and gas activities on such lands and waters. The suspension of these federal leasing activities prompted legal action by several states against the Biden Administration resulting in the issuance of a nationwide permanent injunction by a federal district judge in Louisiana effectively halting implementation of the leasing suspension. Relatedly, the Department of the Interior released its report on federal gas leasing and permitting practices in November 2021, referencing a number of recommendations and an overarching intent to modernize the federal oil and gas leasing program, including by adjusting royalty and bonding rates, prioritizing leasing in areas with known resource potential, and avoiding leasing that conflicts with recreation, wildlife habitat, conservation, and historical and cultural resources. Additionally, the Bureau of Land Management proposed a rule in November 2022 that would limit flaring from well sites on federal lands, as well as allow the delay or denial of permits if the Bureau finds that an operator’s methane waste minimization plan is insufficient. Implementation of many of the recommendations in the report will require Congressional action and provisions of the reforms have been subject to litigation. We cannot predict the extent to which the recommendations may be implemented now or in the future, but restrictions on federal oil and gas activities have the potential to result in increased costs on our customers, decreased demand for our services on federal lands, and an adverse impact on our business.

    The U.S. Congress (“Congress”) has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, some states, including Texas, Oklahoma and New Mexico have adopted, and other states are considering adopting legal requirements that could impose new or more stringent permitting, public disclosure, or well construction requirements on hydraulic fracturing activities. States could elect to prohibit high volume hydraulic fracturing altogether, following the approach taken by the State of New York in 2015. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted, our customers could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.

    

    Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs for our customers in the production of oil and gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of additional regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and an associated decrease in demand for our services and increased compliance costs and time, which could have a material adverse effect on our liquidity, consolidated results of operations, and consolidated financial condition.

and services, we cannot guarantee that such participation or certification will have the intended results on our ESG profile.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our access to and costs of capital. Additionally, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations. Such ESG matters may also impact our customers, which may adversely impact our business, financial condition, or results of operations.

In August 2022, President Biden signed the Inflation Reduction Act of 2021 (the “IRA 2022”) into law. The IRA 2022 contains hundreds of billions in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, among other provisions. In addition, the IRA 2022 imposes the first ever federal fee on the emission of greenhouses gases through a methane emissions charge. The IRA 2022 amends the federal CAA to impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas production and gathering and boosting source categories. The methane emissions charge would start in calendar year 2024 at $900.00 per ton of methane, increase to $1,200.00 in 2025, and be set at $1,500.00 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA 2022. The methane charge imposed on our oil and gas customers could further accelerate the transition of the economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives. This could decrease demand for oil and gas and consequently adversely affect the business of our customers, thereby reducing demand for our services.

    Our information technology systems (including the information technology systems of TETRA, provided through January 31, 2022 under the Transition Services Agreement), are critically important to operating our business efficiently. We rely on these information technology systems to manage business data, communications, supply chain, customer invoicing, employee information, and other business processes. We outsource certain business process functions to third-party providers and we rely on these third-parties to maintain and store confidential information on their systems. The failure of these information technology systems to perform as we anticipate could disrupt our business and could result in transaction errors, processing inefficiencies, and the loss of sales and customers, causing our business and results of operations to suffer.

    Although we allocate significant resources to protect these information technology systems, we have experienced within the past year varying degrees of cyber-incidents in the normal conduct of our business, including viruses, worms, other destructive software, process breakdowns, phishing and other malicious activities. On January 6, 2020, the Department of Homeland Security issued a public warning that indicated companies in the

energy industry might be specific targets of cybersecurity threats. Such breaches have in the past and could again in the future result in unauthorized access to information including customer, supplier, employee, or other company confidential data. We are investing in security technology and designing 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.

If we cannot meet the continued listing requirements of the NASDAQ Exchange (the “NASDAQ”), the NASDAQ may delist our common units.

The Partnership has been notified by the NASDAQ in the past from time to time that the closing price of the Partnership’s common units over the prior 30 consecutive trading day period was below $1.00 per unit, which is the minimum closing price per unit required to maintain listing on the NASDAQ under Rule 5450 (“Rule 5450”). While the Partnership is currently in compliance with Rule 5450, there can be no assurance that the Partnership will maintain compliance with such rule or the NASDAQ’s other listing rules in the future. On March 9, 2023, the trading price of our common units closed at $1.45 per unit.

Upon receipt of notice of noncompliance from NASDAQ, the Partnership has a period of six months to regain compliance with Rule 5450, during which time our common units continue to be listed and traded on the NASDAQ, subject to our compliance with other continued listing standards. If we fail to regain compliance with Rule 5450 by the end of the cure period, the common units will be subject to the NASDAQ’s suspension and delisting procedures. If necessary, to regain compliance with NASDAQ listing standards, we may, subject to approval of the board of directors of our general partner, implement a reverse split of our common units. A delisting of our common units from the NASDAQ could negatively impact us by, among other things, reducing the liquidity and market price of our common units, reducing the number of investors willing to hold or acquire our common units, limiting our ability to issue securities or obtain financing in the future, and limiting our ability to use a registration statement to offer and sell freely tradable securities, thereby restricting our ability to access the public capital markets.

    Spartan controls our general partner, and through the general partner controls us. Some of our general partner’s directors are directors or officers of Spartan or its affiliates that own our general partner. Therefore, conflicts of interest may arise between Spartan 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 Spartan and its affiliates over the interests of our common unitholders. These conflicts include, among others, the following situations:

    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.

 

    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 Spartan, its transferees and persons who acquired such partnership units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of our common unitholders to call meetings or to acquire information about our operations, as well as other provisions.

    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 9, 2023, our general partner and its affiliates own an aggregate of 44.9% of our common units.

 

    Under certain circumstances, our common unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our common unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the

obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners because of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

 

    While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by affiliates of Spartan). As of March 9, 2023, our general partner and its affiliates own an aggregate of 44.9% of our common units.

 

    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.

 

    The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. Despite the fact that we are a limited partnership under Delaware law, we will be treated as a corporation for U.S. federal income tax purposes unless we satisfy a "qualifying income" requirement. Based upon our current operations and current Treasury Regulations, we believe that we satisfy the qualifying income requirement. However, no ruling has been or will be requested regarding our treatment as a partnership for U.S. federal income tax purposes. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

    If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on all of our taxable income at the corporate tax rate and would likely pay additional state and local income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

    We conduct a portion of our operations through subsidiaries that are organized as corporations for U.S. federal income tax purposes. We may elect to conduct additional operations through these corporate subsidiaries in the future. These corporate subsidiaries are subject to U.S. corporate-level tax, which reduces the cash available for distribution to us and, in turn, to our unitholders. If the IRS were to successfully assert that these corporations have more tax liability than we anticipate or legislation were enacted that increases the corporate tax rate, our cash available for distribution to our unitholders would be further reduced. Distributions from any such corporate subsidiary will generally be treated as dividend income to the extent of the current and accumulated earnings and profits of such corporate subsidiary. An individual unitholder's share of dividend income from any

corporate subsidiary would constitute portfolio income that could not be offset by the unitholder's share of our other losses or deductions.

    The 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 changes or differing interpretations at any time. From time to time, members of the U.S. Congress have proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership tax treatment. Recent proposals have provided for the expansion of the qualifying income exception for publicly traded partnerships in certain circumstances, and other proposals have provided for the total elimination of the qualifying income exception upon which we rely for our partnership tax treatment.

    In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future.

    Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any similar or future legislative changes could negatively impact the value of an investment in our common units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.

    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.

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.

 

    We have not requested a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner, because the costs will reduce our cash available for distribution.

    Legislation applicable to partnership tax years beginning after December 31, 2017 alters the procedures for auditing large partnerships and for assessing and collecting taxes due (including penalties and interest) as a result of a partnership-level U.S. federal income tax audit. Under this legislation, unless we are eligible to (and do) elect to issue revised information statements to our unitholders and former unitholders with respect to an audited and adjusted partnership tax return, the IRS (and some states) may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed. If we are required to pay taxes, penalties and interest as a result of audit adjustments, cash available for distribution to our unitholders may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited tax year. These rules are not applicable for tax years beginning on or prior to December 31, 2017.

Our unitholders are required to pay taxes on their share of our income, even if they do not receive any cash distributions from us.

    Our unitholders are required to pay any U.S. federal income taxes, and, in some cases, state and local income taxes on their share of our taxable income, even if they do not receive cash distributions from us. Unitholders with a greater than 10% interest in us may also be required to include their pro rata share of any global intangible low-taxed income attributable to our foreign corporate subsidiaries in the year in which such income is earned, even if the unitholder receives no cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

    If our unitholders sell common units, they will recognize a gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease the tax basis in their common

units, the amount, if any, of such prior excess distributions with respect to the units our unitholders sell will, in effect, become taxable income to our unitholders if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if our unitholders sell their units, they may incur a tax liability in excess of the amount of cash the unitholders receive from the sale.

    A substantial portion of the amount realized from a unitholder’s sale of our units, whether or not representing gain, may be taxed as ordinary income to such unitholder due to potential recapture items, including depreciation recapture. Thus, a unitholder may recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than such unitholder’s adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which a unitholder sells its units, such unitholder may recognize ordinary income from our allocations of income and gain to such unitholder prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.

    Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Tax-exempt entities should consult a tax advisor before investing in our common units.

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

    We prorate our items of income, gain, loss, and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate (i) certain deductions for depreciation of capital additions, (ii) gain or loss realized on a sale or other disposition of our assets, and (iii) in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Although final Treasury Regulations allow publicly traded partnerships to use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, these regulations do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to successfully challenge our proration method, we may be required to change our allocation of items of income, gain, loss, and deduction among our unitholders.

    For taxable years beginning after December 31, 2017 and ending on or before December 31, 2025, a unitholder is generally allowed a deduction equal to 20% of our “qualified publicly traded partnership income” that is allocated to such unitholder. For purposes of the deduction, the term qualified publicly traded partnership income includes the net amount of such unitholder’s allocable share of our income that is effectively connected to our U.S. trade or business activities. Because our non-U.S. business operations earn income that is not effectively connected with a U.S. trade or business, unitholders may not apply the 20% deduction for qualified publicly traded partnership income to that portion of our income.

    Because there are no specific rules governing the U.S. federal income tax consequence of loaning a partnership interest, a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units. In that case, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller, and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss, or deduction with respect to those units may not be reportable by the unitholder, and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

    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.

    In addition to U.S. federal income taxes, unitholders will likely be subject to other taxes, including non-U.S., state and local taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we do business or control property now or in the future, even if they do not live in any of those jurisdictions. Unitholders will likely be required to file non-U.S., state, and local income tax returns and pay non-U.S., state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. In the United States, we own assets and conduct business in many states, most of which currently impose a personal income tax on individuals and an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own or control assets or conduct business in additional jurisdictions that impose a personal income tax. It is our unitholders’ responsibility to file all U.S. federal, non-U.S., state and local tax returns and pay any taxes due in these jurisdictions. Unitholders should consult with their own tax advisors regarding the filing of such tax returns, the payment of such taxes, and the deductibility of any taxes paid.

    Unitholders may be subject to tax in one or more non-U.S. jurisdictions, including Canada, Mexico, Argentina, Egypt and Chile as a result of owning our common units if, under the laws of any such jurisdiction, we are considered to be carrying on business there. If unitholders are subject to tax in any such jurisdiction, they may be required to file a tax return with, and pay taxes to, that jurisdiction based on their allocable share of our income. We may be required to reduce distributions to unitholders on account of any withholding obligations imposed upon us by that jurisdiction in respect of such allocation to the unitholders. In addition, the U.S. may not allow a tax credit for any foreign income taxes that unitholders directly or indirectly incur.

Item 1B. Unresolved Staff Comments.

Item 2. Properties.

 

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.

PART II

Market Information

Distribution Policy

 

 

 

    See “Item 12. Security Ownership of Certain Beneficial Owners and Management” for information regarding our equity compensation plans as of December 31, 2022.

    We are a provider of contract services related to the exploration and production of oil and natural gas, including natural gas compression services and treating services. Natural gas compression equipment is used for natural gas and oil production, gathering, artificial lift, production enhancement, transmission, processing, and storage. We also provide a variety of natural gas treating services. Our compression business includes a fleet of approximately 4,600 compressor packages providing approximately 1.2 million in aggregate horsepower, utilizing a full spectrum of low-, medium-, and high-horsepower engines. Our treating fleet includes amine units, gas coolers, and related equipment. Our aftermarket business provides compressor package overhaul, repair, engineering and design, reconfiguration and maintenance services, as well as the sale of compressor package parts and components manufactured by third-party suppliers. Our customers operate throughout many of the onshore producing regions of the United States, as well as in a number of international locations, including Mexico, Canada, Argentina, Egypt and Chile.

    Demand for our services is directly driven by the production of crude oil and associated natural gas from unconventional shale plays, production of natural gas from conventional plays and the transmission of natural gas to and within sales pipelines. Our fleet of compressors, ranging from 20 to 2,500 horsepower per unit, allows us to service our customers compression needs at the wellhead through high-horsepower compression needs at centralized gathering and gas lift facilities.

During 2021, our financial results were affected by the economic impact of the COVID-19 pandemic. Reduced spending by oil and gas operators led to a decline in our compression fleet utilization which impacted revenues and pricing. Oil and natural gas commodity prices gained strength throughout 2021 and increased significantly during 2022. West Texas Intermediate oil prices reached an average of $83 per barrel in the fourth quarter of 2022. This increase in commodity prices, coupled with the waning impact of the COVID-19 pandemic on the economy, resulted in an increase in the demand for our contract services, aftermarket services, and equipment rentals. Our compression fleet utilization increased to 86.8% as of December 31, 2022, compared to 80.8% as of December 31, 2021. In addition, as a result of increased customer demand, we were able to implement price increases on many of our compression contracts in the second half of 2021 and throughout 2022. Revenue from contract services increased each quarter in 2022. We secured orders from key customers for high-horsepower and electric compressors that started generating revenues in the fourth quarter of 2022 and continue to be deployed in 2023. Our customers remain focused on capital discipline; however, the levels of quote activity and awards remain strong. The strengthening market environment has increased, competition for field and corporate employees. Supply chain issues, increased commodity prices, and inflationary pressures have increased costs and impacted the availability of our parts and supplies. In December 2022, an international contract expired through its natural course, as of December 31, 2022 the contract has not renewed. Management is having ongoing conversations over a renewal or extension. External factors including Russia’s invasion of Ukraine, inflationary pressures and related monetary policy, such as Federal Reserve rate increases, could adversely affect our results of operations, impair our ability to raise capital, or otherwise adversely impact our ability to realize certain business strategies. We continue to monitor these risks and take the necessary actions to mitigate them. We have and will continue to

evaluate the sale of non-core assets, including our low-horsepower compression fleet. We can provide no assurance that we will consummate a future sale of our low-horsepower compression fleet.

The following data should be read in conjunction with the Consolidated Financial Statements and the associated Notes contained elsewhere in this document. On November 10, 2021, Spartan contributed Spartan Treating to the Partnership. As the Partnership and Spartan Treating were under common control at the time of the Spartan Acquisition, the results of operations have been combined for the Partnership and Spartan Treating from the date common control began which was January 29, 2021. See Note 4 - “Common Control Acquisition” in the Notes to Consolidated Financial Statements in this Annual Report for further information. Previously, our equipment sales business included our new unit sales business that consisted of the fabrication and sale of new standard and custom-designed, engineered compressor packages fabricated primarily at our facility in Midland, Texas. We sold the Midland facility in July 2020. In the fourth quarter of 2020, we fully exited the new unit sales business and we have reflected these operations as discontinued operations for all periods presented. See Note 9 - “Discontinued Operations” in the Notes to Consolidated Financial Statements in this Annual Report for further information. Used equipment sales revenue continues to be included in equipment sales revenue.

2022 Compared to 2021

    Contract services revenues increased by $28.2 million, or 12.0%, during 2022 compared to the prior year. The increase in revenues is due to an increase in activity levels resulting from strong oil and gas commodity prices and the economic recovery as the impact of the pandemic diminishes. Compression fleet horsepower utilization and operating horsepower both increased in 2022 compared to the prior year. In addition, due to the improved market conditions, we implemented price increases resulting in an increase in revenues. Operating horsepower increased

compared to the prior year period due to the deployment of new compressor units in 2022 and the redeployment of idle compressor units in late 2021 and throughout 2022.

    Aftermarket services revenues increased $19.4 million, or 36.2%, during 2022 compared to the prior year due to increased demand for compression parts and services resulting from an increase in activity levels by our customers. With the improvement in market conditions and the strong oil and gas commodity prices, customers have increased production of oil and gas which, in turn, increased the demand for parts and services needed to maintain their compression fleet.

    Equipment sales revenues decreased $0.4 million, or 13.6%, during 2022 compared to the prior year due to a decrease in used unit sales.

    Cost of aftermarket services increased $12.6 million in 2022 compared to 2021 consistent with the increase

in revenues. The cost of aftermarket services was also impacted by inflation in 2022.

    Cost of equipment sales decreased $2.0 million during the current year as a result of selling aged units with decreased market value.

    Selling, general, and administrative expenses decreased $0.7 million during 2022 compared to 2021 largely due to decreased employment expenses, including wages, incentives, benefits, and other employee-related expenses of $6.2 million primarily due to the transition of headcount from TETRA shared services model to in-house functions and decreased bad debt expenses and other expenses of $0.9 million. These decreases were offset by increased general expenses such as office, tax, and insurance expenses of $5.3 million and increased professional services fees of $1.1 million.

    As a partnership, we are generally not subject to income taxes at the entity level, and our partners are separately taxed on their share of our taxable income. However, a portion of our business is conducted through taxable U.S. corporate subsidiaries. Accordingly, a U.S. federal and state income tax provision has been reflected in the accompanying statements of operations. Certain of our operations are located outside of the United States and the Partnership, through its foreign subsidiaries, is responsible for income taxes in these countries.     

    

    Our effective tax rate for the year ended December 31, 2022, was negative 27.4% primarily due to taxes in certain foreign jurisdictions and Texas gross margin taxes combined with losses generated in entities for which no related tax benefit has been recorded. Included in our 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.

    

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.

During 2022, oil and gas commodity prices remained strong resulting in an increase in activity levels by our customers and higher demand for our products and services. Although uncertainty remains, the outlook for the energy sector continues to be favorable. Despite these uncertainties, we remain committed to a long-term growth strategy. Our near-term focus is to reduce our leverage, preserve and enhance liquidity, and grow our profitability

through strategic operating and financial measures. We periodically evaluate engaging in strategic transactions and may consider divesting assets where our evaluation suggests such transactions are in the best interests of our business. We are subject to business and operational risks that could materially and adversely affect our cash flows and, when coupled with risks associated with current debt and equity market conditions, our ability or desire to issue securities. Please read “Item 1A. Risk Factors.”

    On January 20, 2023, our general partner declared a cash distribution attributable to the quarter ended December 31, 2022, of $0.01 per common unit. This distribution equates to a distribution of $0.04 per outstanding common unit on an annualized basis. This quarterly distribution was paid on February 14, 2023, to each of the holders of common units of record as of the close of business on January 31, 2023.

The level of growth capital expenditures depends on our ability to redeploy existing fleet equipment and demand for compression services. Improved market conditions have provided opportunities with our customer base to provide new compression horsepower, resulting in increased demand for growth capital. If the demand for compression services increases or decreases, the amount of planned expenditures on growth and expansion will be adjusted. We continue to review all capital expenditure plans carefully in an effort to conserve cash and fund our liquidity needs.

Spartan Credit Agreement

On November 10, 2021, certain unrestricted subsidiaries of the Partnership, Spartan Energy Services LLC, as borrower, and Treating Holdco, as new guarantor, entered into the First Amendment to Loan, Security and Guaranty Agreement (the “Spartan Amendment”) amending the Loan, Security and Guaranty Agreement dated January 29, 2021 (as amended, restated, amended and restated, supplemented or otherwise modified from time to time, the “Spartan Credit Agreement”) with Bank of America, N.A., in its capacity as agent, and the other lenders and loan parties party thereto. As of December 31, 2022, and subject to compliance with the covenants, borrowing base, and other provisions of the agreements that may limit borrowings under the Spartan Credit Agreement, we had availability of $14.5 million.

Notes

As of December 31, 2022, our 10.000%/10.750% Second Lien Notes due 2026 (the “Second Lien Notes”) had $172.5 million outstanding, net of unamortized discounts, unamortized deferred financing costs and deferred restructuring gains. Interest on the Second Lien Notes is payable on April 1 and October 1 of each year. The Second Lien Notes are secured by a second-priority security interest in substantially all of the Partnership’s and its subsidiaries assets, subject to certain permitted encumbrances and exceptions, and are guaranteed on a senior secured basis by each of the Partnership’s U.S. restricted subsidiaries (other than Finance Corp, certain immaterial subsidiaries and certain other excluded U.S. subsidiaries). In connection with the payment of PIK Interest (as defined below), if any, in respect of the Second Lien Notes, the issuers will be entitled, to increase the outstanding aggregate principal amount of the Second Lien Notes or issue additional notes (“PIK notes”) under the Second Lien Notes indenture on the same terms and conditions as the already outstanding Second Lien Notes. Interest will accrue at (1) the annual rate of 7.250% payable in cash, plus (2) at the election of the Issuers (made by delivering a notice to the Second Lien Trustee not less than five business days prior to the record date), the annual rate of (i) 2.750% payable in cash (together with the annual rate set forth in clause (1), the “Cash Interest Rate”) or (ii) 3.500% payable by increasing the principal amount of the outstanding Second Lien Notes or by issuing additional PIK notes, in each case rounding up to the nearest $1.00 (such increased principal amount or additional PIK notes, the “PIK Interest”). We have elected to cash pay interest starting April 1, 2022, prior to this we elected to pay interest by issuing additional PIK Notes.

        CSI Compressco Field Services International LLC

        CSI Compressco Holdings LLC

        CSI Compressco International LLC

        CSI Compressco Leasing LLC

        CSI Compressco Operating LLC

        CSI Compressco Sub, Inc.

        CSI Compression Holdings, LLC

        Rotary Compressor Systems, Inc.

    As a result of these guarantees, we are presenting the following summarized financial information of the obligor group pursuant to Rule 1-02(bb) of Regulation S-X. These schedules are presented using the equity method of accounting for all periods presented. Under this method, investments in subsidiaries are recorded at cost and adjusted for our share in the subsidiaries’ cumulative results of operations, capital contributions and distributions and other changes in equity. Elimination entries relate primarily to the elimination of investments in subsidiaries and associated intercompany balances and transactions. The Other Subsidiaries column includes financial information for those subsidiaries that do not guarantee the First Lien Notes or the Second Lien Notes. In addition to the financial information of the Partnership, financial information of the Issuers includes CSI Compressco Finance Inc., which had no assets or operations for any of the periods presented.

Critical Accounting Policies and Estimates

Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

 

 

 

 

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

 

Management’s Report on Internal Control over Financial Reporting

 

financial reporting is a process to provide reasonable assurance regarding the reliability of our financial reporting for external purposes in accordance with accounting principles generally accepted in the United States of America.

    Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. In addition, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Changes in Internal Control over Financial Reporting

 

Houston, Texas

March 13, 2023

Item 10. Directors, Executive Officers, and Corporate Governance.

 

Corporate Governance and Director Independence

 

Directors and Executive Officers

a global provider of compression, production, and processing equipment and turnkey facilities. Prior to Valerus, Mr. Gill served in various senior positions at Exterran and Hanover, including Vice President – International and at Ingersoll Rand & Dresser Rand. Mr. Gill holds a B.S. degree in Mechanical Engineering from Texas A&M University.

Board Meetings and Committees

 

As required by the Third Amended and Restated Agreement of Limited Partnership of the Partnership, the Board reviewed the independence of Messrs. Larson and Gill and Ms. Essenberg and determined that each of them meets the independence standards established thereunder as required for service on the Conflicts Committee. Included within such determination, the Board also determined that each of Messrs. Larson, Gill and Tucker and Ms.

Item 11. Executive Compensation.

 

Compensation of Named Executive Officers

Beginning in February 2021, we reimbursed our general partner under the terms of our partnership agreement for any expenses and expenditures incurred or payments made on our behalf, including operating expenses related to our operations and for the provision of various general and administrative services for our benefit.

Pursuant to the Management Services Agreement dated November 10, 2021, the general partner, Spartan Operating and Spartan GP will provide certain services reasonably necessary for the operation of the businesses of the Partnership and its subsidiaries, Spartan, Spartan GP and Spartan Treating, including certain corporate and general and administrative services. The general partner and Spartan GP will allocate any costs and expenses incurred on a reasonable basis, and the parties will reimburse such other parties for costs and expenses allocated to them.

None of the NEOs are a party to an employment agreement or other individual service agreement. Base salary amounts were determined by the Board of Directors. As noted above, each NEO participated in the CICP during the 2022 year. The CICP budget pool for the 2022 awards under the CICP is based on EBITDA and pays out in accordance with the following table:

Individual bonus payouts may be increased or decreased by 0-200% of the CICP target based on individual performance at the discretion of the Board of Directors. The 2022 CICP target for John Jackson was 120% and 75% for Jonathan Byers and Robert Price, respectively.

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.

 

The NEOs became eligible to participate in the CSI Compressco 401(k) Retirement plan (the “CSI Compressco 401(k) Plan”) effective January 1, 2022. The CSI Compressco 401(k) Plan is intended to supplement a participant’s personal savings and social security. Under this plan, the NEOs may contribute on a pre-tax basis up to 70% of their compensation, subject to an annual maximum established under the Internal Revenue Code (the “Code”). The Partnership makes a matching contribution under these plans equal to 50% of the first 8% of the NEOs annual compensation that is contributed to the plan. Such matching contribution was suspended in April 2020 and reinstated in December 2021. All employees (other than nonresident aliens) who have reached the age of eighteen are eligible to participate in the CSI Compressco 401(k) Plan beginning on the first day of the month following their completion of thirty (30) days of service with us.

 

 

 

Outstanding Equity Awards at Fiscal Year End Table

Each director who is not an employee of our general partner or any of its subsidiaries, receives non-cash compensation of $60,000 per year for attending regularly scheduled board meetings. The non-cash compensation is paid for the upcoming service year in the form of phantom unit awards that have an intended grant date value of $60,000, prorated for any newly elected director to such director’s date of election and that vest over the service year as set forth below. All such awards of phantom units are granted under our LTIP. Each phantom unit award granted to the directors on February 7, 2022, was granted in tandem with distribution equivalent rights (“DERs”) that entitle the award holder to receive an additional number of units equal in value to any distributions we pay during the period the award is outstanding times the number of units subject to the award. 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 cash installments. Directors who are appointed as chairmen of the Audit Committee receive an additional cash retainer of $10,000 per year paid in quarterly installments.

Directors who are also our officers or employees, or officers or employees of our general partner or any of its subsidiaries, did not receive any compensation for duties performed as our directors. Consequently, none of Mr.

Jackson (our current Chief Executive Officer), Mr. Byers (our current Chief Financial Officer) or Mr. Price (our current Chief Operating Officer) was compensated for their respective service to us as a director during 2022.

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, 2022.

Director Compensation Table

Beneficial Ownership of Certain Unitholders and Management

The following table sets forth the beneficial ownership of our units held by each person who beneficially owned 5% or more of our outstanding common units as of December 31, 2022, and (i) our directors; (ii) our Named Executive Officers (“NEOs”); and (iii) our directors and executive officers as a group during 2022.

The amounts and percentages of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed

to be a “beneficial owner” of a security if that person has or shares “voting power,” which includes the power to vote or to direct the voting of such security, or “investment power,” which includes the power to dispose of or to direct the disposition of such security. A person is also deemed to be a beneficial owner of any securities of which that person has a right to acquire beneficial ownership within 60 days. Under these rules, more than one person may be deemed a beneficial owner of the same securities and a person may be deemed a beneficial owner of securities as to which he has no economic interest.

Except as indicated by footnote, the persons named in the following table have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

Equity Compensation Plan Information

Certain Transactions