The U.S. inflation rate increased in 2021, 2022 and into 2023. These inflationary pressures have resulted in and may result in additional increases to the costs of our goods, services and labor, which in turn [has caused and] may cause our capital expenditures and operating costs to rise. Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates multiple times in 2022. The U.S. Federal Reserve has raised and may continue to raise benchmark interest rates in 2023 in an effort to curb inflationary pressure on the costs of goods and services across the U.S., which could have the effects of raising the cost of capital and depressing economic growth, either of which—or the combination thereof—could negatively impact the financial and operating results of our business. To the extent elevated inflation remains, we may experience additional cost increases for our operations, including services, labor costs and equipment if our operating activity increases.

Higher oil and natural gas prices may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflation and a significant increase in inflation, to the extent we are unable to recover higher costs through higher prices and revenues, would negatively impact our business, financial condition and results of operations.

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

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

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

payment obligations with respect to our Credit Agreement, and if so accelerated, we would be required to pay all of our outstanding obligations under our Credit Agreement. We may not be able to repay or repurchase our First Lien Notes and Second Lien Notes at that time because we may not have available funds to repay the debt or pay the repurchase price as applicable. Any requirement to repay or to offer to purchase any outstanding First Lien Notes and Second Lien Notes may result in us having to refinance our outstanding indebtedness, which we may not be able to do. In addition, even if we were able to refinance our outstanding indebtedness, such financing may be on terms unfavorable to us. A change of control under the indentures governing our First Lien Notes and Second Lien Notes could have a material adverse effect on our business, results of operations, and financial condition.

Our current capital structure, along with current debt and equity market conditions, may continue to limit our ability to obtain financing to pursue business growth opportunities.

Conditions in the markets for debt and equity securities in the energy sector have increased the difficulty of obtaining debt and equity financing to grow our business. We expect that the stock market volatility, which started in March 2020 and continued throughout 2021 and into 2022, may make it more difficult to obtain debt and equity financing in the near future. As of December 31, ~~2021,~~2022, the market price for our common units was ~~$1.19~~$1.33 per common unit, down from the ~~2020~~2022 high of ~~$2.70~~$1.57 per common unit. The closing price of our common units was ~~$1.46~~$1.45 as of March ~~10, 2022.~~9, 2023. The issuance of new common units or debt convertible into common units in the future, could be significantly dilutive to current common unitholders. In addition, as of December 31, ~~2021,~~2022, we had approximately ~~$632.6~~$634.9 million aggregate principal amount of debt outstanding, including ~~the~~borrowings under our credit agreements, the First Lien Notes and the Second Lien Notes. Obtaining equity or debt financing in the current market environment is particularly difficult for us, given our current levels of long-term debt.

During the year ended December 31, ~~2021,~~2022, our aggregate capital expenditures totaled ~~$43.4~~$52.1 million, which were primarily growth capital expenditures to increase our compression services equipment fleet. The majority of these capital expenditures were funded from our operating cash. As of December 31, ~~2021,~~2022, our total cash balance was ~~$6.6~~$8.5 million. We expect capital expenditures in ~~2022~~2023 to range from ~~$50.0~~$43.0 million to ~~$60.0~~$48.0 million. These capital expenditures include approximately ~~$18.0~~$17.0 million to ~~$22.0~~$19.0 million of maintenance capital expenditures, approximately ~~$24.0~~$23.0 million to ~~$28.0~~$25.0 million of capital expenditures primarily associated with the expansion of our contract services fleet, and ~~$8.0~~$3.0 million to ~~$10.0~~$4.0 million of capital expenditures related to investments in technology ~~primarily software~~ and ~~systems.~~facilities. We will continue to monitor such estimates going forward. We expect that the combination of ~~$6.6~~$8.5 million of cash on hand at the beginning of ~~2022~~2023 and operating cash flows expected to be generated during the year will be sufficient to fund these capital expenditures without having to incur additional long-term debt and without having to access the equity markets. While we do not expect to have to incur additional long-term debt, we may elect to enter into capital lease transactions and/or raise additional equity. However, our ability to grow our business through capital expenditures or acquisitions beyond these sources of financing may be significantly limited or curtailed. Without the ability to increase our compression equipment fleet or otherwise grow our operations, our ability to continue to retain customers whose compression services needs are expanding and to increase distributions to our common unitholders in the future may be limited.

Our long-term debt levels result in a significant amount of our operating cash flows being used to fund debt service requirements.

The aggregate carrying value of our First Lien Notes and Second Lien Notes as of December 31, ~~2021~~2022 are ~~$399.8~~$400.3 million and ~~$173.0~~$172.5 million, respectively. In addition, we have an aggregate carrying value of ~~$58.0~~$54.9 million and ~~$0.3~~$6.3 million outstanding on our Spartan Credit Agreement and our CSI Credit Agreement, respectively, as of December 31, ~~2021.~~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.

We may not have sufficient cash from operations following the establishment of cash reserves and payment of debt service and other contractual obligations, fees and expenses, including cost reimbursements to our general partner, to enable us to increase cash distributions to our common unitholders.

Beginning with the first quarter of 2019, our common unit distributions decreased from $0.75 per unit per year (or $0.1875 per quarter) to $0.04 per unit per year (or $0.01 per quarter). Our Second Lien Notes indenture further restricts our ability to make distributions in respect of our common units in any amount exceeding $0.04 per common unit per year, unless such increased distribution is funded by proceeds from an equity offering. Under the terms of our partnership agreement, the amount of cash otherwise available for distribution is reduced by our operating expenses and the amount of cash reserves that our general partner establishes to provide for future operations, future capital expenditures, future debt service requirements, and future cash distributions to our common unitholders. In order to make cash distributions at this current distribution rate of $0.01 per common unit per quarter, or $0.04 per common unit per year, we will require available cash of approximately $1.4 million per quarter, or ~~$5.6~~$5.7 million per year, based on the number of common units outstanding as of March ~~10, 2022.~~9, 2023. We may not have sufficient available cash each quarter to enable us to increase cash distributions or make any distribution at all. To the extent we issue additional partnership units in connection with our growth, the payment of distributions on those additional partnership units may further increase the risk that we will be unable to increase our per-unit distribution. There are no limitations in our partnership agreement or our Loan and Security Agreement (the "Credit Agreement") on our ability to issue additional common units. The amount of cash we can distribute to our common unitholders principally depends upon the amount of cash we generate from our operations, which fluctuates from quarter to quarter based on, among other things, the market conditions described in these ~~Risk~~“Risk Factors.”

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

Our long-term debt agreements contain covenants and other provisions that restrict our ability to take certain actions and may limit our ability to grow our business in the future.

Our Credit Agreement includes a maximum credit commitment of $35.0 million, which is available for loans, letters of credit (with a sublimit of $25.0 million), and swingline loans (with a sublimit of ~~$5.0~~$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 $5$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.

In addition, the indentures governing our First Lien Notes and Second Lien Notes contain customary covenants restricting our ability and the ability of our restricted subsidiaries to: (i) pay distributions on, purchase, or redeem our common units, make certain investments and other restricted payments, or purchase or redeem any subordinated debt; (ii) incur or guarantee additional indebtedness or issue certain kinds of preferred equity securities; (iii) create or incur certain liens securing indebtedness; (iv) sell assets, including dispositions of the collateral securing our First Lien Notes and Second Lien Notes; (v) consolidate, merge, or transfer all or substantially all of our assets; (vi) enter into transactions with affiliates; and (vii) enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us. Our Second Lien Notes indenture further restricts our ability to make distributions in respect of our common units in any amount exceeding $0.04 per common unit per year, unless such increased distribution is funded by proceeds from an equity offering. These covenants are subject to a number of important limitations and exceptions, including certain provisions permitting us, subject to the satisfaction of certain conditions, to transfer assets to certain of our unrestricted subsidiaries. The indentures also contain customary events of default and acceleration provisions relating to events of default, which provide that upon an event of default under the indentures, the Trustee or the holders of at least 25% in aggregate principal amount of the then outstanding First Lien Notes and Second Lien Notes may declare all of the First Lien Notes and Second Lien Notes to be due and payable immediately.

The loss of any of our most significant customers would result in a decline in our revenue and cash available to pay distributions to our common unitholders.

Our five most significant customers collectively accounted for approximately ~~30%~~28% of our ~~2021~~2022 revenues. Our services and products are provided to these customers pursuant to short-term contract compression services agreements, many of which are cancellable with 30 days’ notice. The loss of all or even a portion of the services we

provide to these customers, as a result of competition or otherwise, could have a material adverse effect on our business, results of operations, financial condition, and our ability to make cash distributions to our unitholders.

The credit and risk profile of Spartan could adversely affect our business and our ability to make distributions to our common 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.

Further changes in the economic environment, including any future supply disruptions, could result in further significant impairments of certain of our long-lived assets.

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 ofunits 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.

Further, insurance covering the risks we face or in the amounts we desire may not be available in the future, or, if available, the premiums may not be commercially feasible. If we were to incur substantial liability and such damages were not covered by insurance or were in excess of policy limits, or if we were to incur liability at a time when we did not maintain liability insurance, our business, results of operations, and financial condition could be adversely affected. In addition, our business interruption insurance does not cover all potential losses. Please read “Health, Safety, and Environmental Affairs Regulations” for a description of how we are subject to federal, state, and local laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of human health and environment.

Our sales to and operations in non-U.S. markets exposes us to additional risks and uncertainties, including with respect to U.S. trade and economic sanctions, export control laws, and the Foreign Corrupt Practices Act

(“FCPA”), and similar anti-bribery laws. If we are not in compliance with applicable legal requirements, we may be subject to civil or criminal penalties and other remedial measures that could have a material impact on our business.

We have operations in Mexico, Canada, Argentina, Chile and Egypt as well as a number of other non-U.S. markets. A portion of our expected future growth could include expansion in these and other non-U.S. markets. Non-U.S. operations carry special risks. Our operations in the countries in which we currently operate and those countries in which we may operate in the future, could be adversely affected by:

•government controls and actions, such as expropriation of assets and changes in legal and regulatory environments;

•import and export license requirements;

•political, social, or economic instability;

•trade restrictions;

•changes in tariffs and taxes;

•currency exposure;

•restrictions on repatriating foreign profits back to the United States; and

•the impact of anti-corruption laws.

Sanctions imposed by the U.S. Office of Foreign Assets Control (“OFAC”) prohibit our operations in or sales to customers in certain 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.

Security disruptions in regions of Mexico served by us could adversely affect our Mexican operations, and, as a result, the levels of revenue and operating cash flow from our Mexican operations could be reduced.

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

Our operations in Argentina, Chile and Egypt expose us to the changing economic, legal, and political environment in those countries, including changing regulations governing the repatriation of cash generated from our operations in Argentina.

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

As a result of our operations in Argentina, consolidated revenues and operating cash flow generated in Argentina have 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 Chilean government is currently attempting to address the current high rate of inflation and the continuing currency devaluation pressure. The government has raised borrowing costs, higher commodity prices are keeping consumer prices under pressure and the central bank has begun to withdraw monetary stimulus by raising the benchmark interest rate.

Operations in Egypt can be a challenge due to the country’s complex regulatory and operating environment. In addition, tight government control of political discourse, increasing poverty and rising costs of living, could increase the risk of social unrest and political instability. The military’s role in the economy has continued to expand in recent years, which has dampened private sector business confidence.

The employees conducting our operations in Mexico and Argentina are party to collective labor agreements, and a prolonged work stoppage of our operations in Mexico or Argentina could adversely impact our revenues, cash flows and net income.

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

A terrorist attack, armed conflict or political or civil unrest could harm our business.

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

Our exposure to currency exchange rate fluctuations may result in fluctuations in our cash flows and could have an adverse effect on our results of operations.

Because we have operations in Mexico, Canada, Argentina, Chile and 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.

Environmental and Technology Risks

We are subject to environmental regulations, and changes in these regulations could increase our costs or liabilities.

We are subject to federal, state, local, and foreign laws and regulatory standards, including laws and regulations regarding the discharge of materials into the environment, emission controls, and other environmental protection and occupational health and safety concerns. Environmental laws and regulations may, in certain circumstances, impose strict and joint and several liability for environmental contamination, rendering us liable for remediation costs, natural resource damages, and other damages resulting from our ownership of property or conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior owners or operators or other third parties. In addition, where contamination may be present, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury, property damage, and recovery of response costs. Remediation costs and other damages arising as a result of environmental laws and regulations, and costs associated with new information, changes in existing environmental laws and regulations or the adoption of new environmental laws and regulations could be substantial and could adversely affect our financial condition or results of operations. Moreover, failure to comply with these environmental laws and regulations may result in the imposition of administrative, civil and criminal penalties, and the issuance of injunctions delaying or prohibiting operations.

We routinely deal with natural gas, oil, and other petroleum products. Hydrocarbons or other hazardous wastes may have been released during our operations or by third parties on wellhead sites where we provide services or store our equipment or on or under other locations where wastes have been taken for disposal. These properties may be subject to investigatory, remediation, and monitoring requirements under foreign, federal, state, and local environmental laws and regulations.

The modification or interpretation of existing environmental laws or regulations, the more vigorous enforcement of existing environmental laws or regulations, or the adoption of new environmental laws or regulations may also adversely affect oil and natural gas exploration and production, which in turn could have an adverse effect on us.

Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas our customers produce, while the physical effects of climate change could disrupt production and cause us to incur costs in preparing for or responding to those effects.

The EPA has adopted regulations to restrict emissions of GHGs under existing provisions of the CAA. Such EPA rules regulate GHG emissions under the CAA and require a reduction in emissions of GHGs from motor vehicles and from certain large stationary sources. 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 ~~plans to issue~~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 ~~contain proposed rule text, which was not included in the November 2021 proposed rule, and anticipates issuing a final rule by the end of 2022.~~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.

There are also increasing financial risks for fossil fuel producers as stockholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific

targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. In late 2020, the Federal Reserve announced that it had joined Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Subsequently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. The Federal Reserve has since announced that six of the largest banks in the United States will take part in a pilot climate scenario analysis, which is expected to conclude at the end of 2023. Although we cannot predict the effect of these actions, such limitation of investments in and financing for fossil fuel energy companies could adversely impact our customers and, therefore, our operations. Additionally, the SEC ~~announced its intention to promulgate rules requiring~~published a proposed rule that would require climate

~~disclosures.~~ disclosures from registrants, include data on Scope 1 and Scope 2 GHG emissions and, in some cases, Scope 3. Although the final form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements. Additionally, we cannot predict how financial institutions and investors might consider information disclosed under any final rule, and it is possible that as a result we could face increases with respect to the costs of, or restrictions imposed on, our access to capital.

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.~~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.

Regulatory initiatives related to hydraulic fracturing in the countries where we and our customers operate could result in operating restrictions or delays in the completion of oil and gas wells that may reduce demand for our services.

Although we do not directly engage in hydraulic fracturing, our operations support many of our exploration and production customers in such activities. The practice continues to be controversial in certain parts of the country, resulting in increased scrutiny and regulation of the hydraulic fracturing process, including by federal and state agencies and local municipalities.

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. ~~On January 20,~~In 2021, the ~~Acting Secretary of the U.S. Department of the Interior issued an order, effective immediately, that suspends~~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 ~~preliminary~~permanent injunction by a federal district judge in Louisiana ~~in June 2021,~~ effectively halting implementation of the leasing suspension. Relatedly, the Department of the Interior released its report on federal

gas leasing and permitting practices in November 2021, referencing a number of recommendations and an overarching intent to modernize the federal oil and gas leasing program, including by adjusting royalty and bonding rates, prioritizing leasing in areas with known resource potential, and avoiding leasing that conflicts with recreation, wildlife habitat, conservation, and historical and cultural resources. 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. On February 19, 2022, the Department of the Interior announced that decisions on permits to drill for oil and gas on federal lands will be delayed in response to a court ruling preventing agencies from using the social cost of carbon in their decision making. We cannot predict the extent to which the recommendations may be implemented now or in the future, but restrictions on federal oil and gas activities have the potential to result in increased costs on our customers, decreased demand for our services on federal lands, and an adverse impact on our business. ~~However, these orders do not apply to operations under existing leases and permits.~~

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

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

Increased attention to Environmental, Social, and Governance (“ESG”) matters and conservation measures may adversely impact our business.

Increasing attention to, and societal expectations on companies to address, climate change and other environmental and social impacts, investor and societal expectations regarding voluntary ESG disclosures, and consumer demand for alternative forms of energy may result in increased costs, reduced demand for fossil fuels and, consequently, demand for our services, reduced profits, increased risk of investigation and litigation, and negative impacts on the value of our services and access to capital. Increasing attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against our customers or us. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation or contribution to the asserted damage, or to other mitigating factors. While we may in the future participate in various voluntary frameworks and certification programs to improve the ESG profile of our operations

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

Moreover, while we may create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures will be based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith.] Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring, and reporting on many ESG matters. Additionally, while we may also announce various voluntary ESG targets in the future, such targets are aspirational. We may not be able to meet such targets in the manner or on such a timeline as initially contemplated, including, but not limited to as a result of unforeseen costs or technical difficulties associated with achieving such results. To the extent that we do meet such targets, it may be achieved through various contractual arrangements, including the purchase of various credits or

offsets that may be deemed to mitigate our ESG impact instead of actual changes in our ESG performance. Also, despite these aspirational goals, we may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.

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

The Inflation Reduction Act of 2021 could accelerate the transition to a low carbon economy and could impose new costs on our customers’ 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 operations and reputation may be impaired if certain information technology systems fail to perform adequately or if we are the subject of a data breach or cyberattack.

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.

Risks Inherent in an Investment in Us

The market price of our common units has been and may continue to be volatile.

The market price of our common units has fluctuated in the past and is subject to significant fluctuations in response to many factors, some of which are beyond our control, including the following:

•our operational performance;

•supply, demand, and prices of oil and natural gas;

•the activity levels of our customers;

•deviations in our earnings from publicly disclosed forward-looking guidance or analysts’ projections;

•recommendations by research analysts that cover us and other companies in our ~~industry:~~industry;

•risks related to acquisitions and our growth strategy;

•uncertainty about current global economic conditions; and

•other general economic conditions.

During ~~2021,~~2022, the market price for our common units ranged from a high of ~~$2.21~~$1.57 per common unit to a low of ~~$1.00~~$1.12 per common unit. In recent years, the stock market in general has experienced extreme price and volume

fluctuations that have affected the market price for many companies in industries similar to ours. Some of these fluctuations have been unrelated to operating performance and are attributable, in part, to outside factors such as the COVID-19 pandemic and its impact on the world economy. The volatility of our common units may make it difficult for investors to resell our common units at attractive prices.

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 ~~10, 2022,~~9, 2023, the trading price of our common units closed at ~~$1.46~~$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.

Our partnership agreement requires us to distribute all of the available cash that we generate each quarter after paying expenses and establishing prudent operating reserves, which could limit our ability to grow.

Our partnership agreement requires us to distribute all of the available cash we generate each quarter. Under the terms of our partnership agreement, the amount of cash otherwise available for distribution will be

reduced by our operating expenses and the amount of cash reserves that our general partner establishes to provide for future operations, future capital expenditures, future debt service requirements and future cash distributions to our common unitholders. As a result, our general partner relies primarily upon external financing sources, including existing debt arrangements and the issuance of additional debt and equity securities, as well as cash flows from operations to a certain extent, to fund our expansion capital expenditures. To the extent that we are unable to finance growth externally, this requirement significantly impairs our ability to grow. In addition, also as a result of this requirement, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent that we issue additional units in connection with any expansion of capital expenditures, the payment of distributions on those additional units may decrease the amount we distribute on each outstanding unit. Our Second Lien Notes indenture further restricts our ability to make distributions in respect of our common units in any amount exceeding $0.04 per common unit per year, unless such increased distribution is funded by proceeds from an equity offering. See also “—We may not have sufficient cash from operations following the establishment of cash reserves and payment of debt service and other contractual obligations, fees and expenses, including cost reimbursements to our general partner, to enable us to increase cash distributions to our common unitholders.”

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

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:

•neither our partnership agreement nor any other agreement requires Spartan to pursue a business strategy that favors us. The directors and officers of Spartan and its affiliates have a fiduciary duty to make these decisions in the best interests of Spartan, which may be contrary to our interests;

•our general partner controls the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and Spartan, on the other hand, including provisions governing administrative services, acquisitions, and non-competition provisions;

•our general partner is allowed to take into account the interests of parties other than us, including Spartan and its affiliates, in resolving conflicts of interest;

•our general partner has limited its liability and reduced its fiduciary duties to our common unitholders and us, and has also restricted the remedies available to our common unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

•our general partner will determine the amount and timing of asset purchases and sales, capital expenditures, borrowings, repayment of indebtedness, and issuances of additional partnership interests, each of which can affect the amount of cash that is available for distribution to our common unitholders;

•our general partner determines the amount and timing of any capital expenditures which can affect the amount of cash that is distributed to our common unitholders;

•our general partner may cause us to borrow funds in order to permit the payment of cash distributions;

•our general partner determines which costs incurred by it and its affiliates are reimbursable by us and Spartan will determine the allocation of shared overhead expenses;

•our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

•our general partner intends to limit its liability regarding our contractual and other obligations and, in some circumstances, is entitled to be indemnified by us;

•our general partner decides whether to retain separate counsel, accountants, or others to perform services for us; and

•our general partner determines the amount and timing of distributions to our unitholders.

Our partnership agreement limits our general partner’s fiduciary duties to our common unitholders and restricts the remedies available to our common unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty laws. For example, our partnership agreement:

•permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to consider any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, the exercise of its rights to transfer or vote the partnership units it owns, the exercise of its registration rights and its determination whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement;

•provides that our general partner will not have any liability to us or our common unitholders for decisions made in its capacity as a general partner so long as it acted in good faith, meaning it believed the decision was in the best interests of our partnership;

•generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner acting in good faith and not involving a vote of our common unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or must be “fair and reasonable” to us, as determined by our general partner in good faith and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to us;

•provides that our general partner and its executive officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

•provides that in resolving conflicts of interest, it will be presumed that in making its decision our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Our common unitholders have limited voting rights and are not entitled to elect our general partner or its directors.

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right to elect our general partner or its board of directors. The board of directors of our general partner will be chosen indirectly by Spartan through its subsidiary that is the sole shareholder of our general partner. Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The vote of the holders of at least 66.7% of all outstanding common units is required to remove our general partner. As of March ~~10, 2022,~~9, 2023, our general partner and its affiliates own ~~45.0%~~44.9% of our aggregate outstanding common units. Due to these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

We can issue an unlimited number of partnership units in the future, including units that are senior in right of distributions, liquidation and voting to the common units, without the approval of our common unitholders and without the approval of the conflicts committee of our general partner, which would dilute our common unitholders’ existing ownership interests.

Our partnership agreement does not limit the number of additional partnership units that we may issue at any time without the approval of our common unitholders. In addition, we may issue an unlimited number of partnership units that are senior to the common units in right of distribution, liquidation, or voting.

The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

•our previously existing common unitholders’ proportionate ownership interests in us will decrease;

•the amount of cash available for distribution on each common unit may decrease;

•the ratio of taxable income to distributions may increase;

•the relative voting strength of each previously outstanding common unitholders may be diminished; and

•the market price of the common units may decline.

Control of our general partner has been and may be transferred to a third party without common unitholder consent.

On January 29, 2021, control of our general partner was transferred from TETRA to Spartan. Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of Spartan or its subsidiaries from transferring all or a portion of its indirect ownership interest in our general partner to a third party. The new owners of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with its own choices and thereby influence the decisions taken by the board of directors and executive officers.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units, other than our general partner and its affiliates, including Spartan. Accordingly, such unitholders’ voting rights may be limited.

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any partnership units held by a person that owns 20% or more of any class of partnership units then outstanding, other than our general partner, its affiliates, including Spartan, its transferees and persons who acquired such partnership units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of our common unitholders to call meetings or to acquire information about our operations, as well as other provisions.

Our general partner has a limited call right that may require our unitholders to sell common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 90% of the common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than the then-current market price. As a result, our unitholders may be required to sell common units at an undesirable time or price and may not receive any return on their investment. Our unitholders may also incur a tax liability upon a sale of common units. As of March ~~10, 2022,~~9, 2023, our general partner and its affiliates own an aggregate of ~~45.0%~~44.9% of our common units.

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

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

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

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

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

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

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

While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including provisions requiring us to make cash distributions contained therein, may be amended. Our partnership agreement can be amended with the consent of our general partner and the approval of a majority of the outstanding common units (including common units held by affiliates of Spartan). As of March ~~10, 2022,~~9, 2023, our general partner and its affiliates own an aggregate of ~~45.0%~~44.9% of our common units.

We are exempt from certain corporate governance requirements that provide additional protection to stockholders of other public companies.

Companies listed on the NASDAQ are required to meet the high standards of corporate governance, as set forth in the NASDAQ Listing Rules. These requirements generally do not apply to limited partnerships or to a “controlled company,” within the meaning of the NASDAQ rules. We are a limited partnership and a “controlled company,” within the meaning of the NASDAQ rules, and, as a result, we rely on exemptions from certain corporate governance requirements that provide protection to stockholders of other public companies.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes. If the IRS were to treat us as a corporation for U.S. federal income tax purposes, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in 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 have subsidiaries that are treated as corporations for U.S. federal income tax purposes and are subject to corporate-level income taxes.

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

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

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial, or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial 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.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

Changes in current state law may subject us to additional entity-level taxation by individual states. Because of state budget deficits and other reasons, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, and other forms of taxation. For example, we are subject to an entity-level Texas franchise tax. Imposition of any such taxes may substantially reduce the cash available for distribution to our unitholders.

Although we are not subject to U.S. federal income tax other than with respect to our operating U.S. subsidiaries that are treated as corporations for U.S. federal income tax purposes, certain of our foreign operations are subject to certain non-U.S. taxes. If a taxing authority were to successfully assert that we have more tax liability than we anticipate or legislation were enacted that increased the taxes to which we are subject, our cash available for distribution to our unitholders could be further reduced.

Approximately ~~13.9%~~12.2% of our consolidated revenues for the year ended December 31, ~~2021,~~2022, were generated in non-U.S. jurisdictions, primarily Mexico, Canada, Argentina, Chile and Egypt. Our non-U.S. operations and subsidiaries are generally subject to income, withholding, and other taxes in the non-U.S. jurisdictions in which they are organized or from which they receive income, reducing the amount of cash available for distribution. In computing our tax obligation in these non-U.S. jurisdictions, we are required to take various tax accounting and reporting positions on matters that are not entirely free from doubt and for which we have not received rulings from the governing tax authorities, such as whether withholding taxes will be reduced by the application of certain tax treaties. Upon review of these positions the applicable authorities may not agree with our positions. A successful challenge by a tax authority could result in additional taxes being imposed on us, reducing the cash available for distribution to our unitholders. In addition, changes in our operations or ownership could result in higher than anticipated taxes being imposed in jurisdictions in which we are organized or from which we receive income and further reduce the cash available for distribution. Although these taxes may be properly characterized as foreign income taxes, our unitholders may not be able to credit them against the liability for U.S. federal income taxes on the unitholders’ share of our earnings. In addition, our operations in countries in which we operate now or in the future may involve risks associated with the legal structure used and the taxation on assets transferred into a particular country. Tax laws of non-U.S. jurisdictions are subject to potential legislative, judicial, or administrative

changes and differing interpretations, possibly on a retroactive basis. Any such changes may result in additional taxes above the amounts we currently anticipate and further reduce our cash available for distribution to our unitholders.

If the IRS contests the U.S. federal income tax positions we take, the market for our common units may be adversely impacted, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

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

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders may be substantially reduced.

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

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.

In response to current market conditions, we may engage in transactions to delever the Partnership and manage our liquidity that may result in income and gain to our unitholders without a corresponding cash distribution. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale without receiving a cash distribution. Further, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt, could result in “cancellation of indebtedness income” (also referred to as “COD income”) being allocated to our unitholders as taxable income. Unitholders may be allocated COD income, and income tax liabilities arising therefrom may exceed cash distributions. The ultimate effect of any such allocations will depend on the unitholder’s individual tax position with respect to its units. Unitholders are encouraged to consult their tax advisors with respect to the consequences to them of COD income.

Tax gain or loss on the disposition of our common units could be more or less than expected.

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

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

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

Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion to the extent such depreciation, amortization, or depletion is not capitalized into cost of goods sold with respect to inventory.

If our “business interest” is subject to limitation under these rules, our unitholders will be limited in their ability to deduct their share of any interest expense that has been allocated to them. As a result, unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.

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

Non-U.S. Unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the U.S. on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a Non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a Non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.

Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the “amount realized” by the transferor unless the transferor certifies that it is not a foreign person. While the determination of a partner’s “amount realized” generally includes any decrease of a partner’s share of the partnership’s liabilities, the Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership, such as our units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that partner’s share of a publicly traded partnership’s liabilities. The Treasury regulations and other guidance from the IRS provide that withholding on a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to January 1, 2023. Thereafter, the obligation to withhold on a transfer of interests in a publicly traded partnership that is effected through a broker is imposed on the

transferor’s broker. Current and prospective Non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.

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

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

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

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

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

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

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

We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates ourselves using a methodology based on the market value of our common units as a means to determine the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction for U.S. federal income tax purposes.

A successful IRS challenge to these methods or allocations could adversely affect the timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

Unitholders will likely be subject to non-U.S., state and local taxes, and return filing requirements in jurisdictions where they do not live as a result of investing in our common units.

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

Unitholders may be subject to tax in one or more non-U.S. jurisdictions, including Canada, Mexico, Argentina, Egypt and 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.

None.

Item 2. Properties.

As of December 31, ~~2021,~~2022, we owned ~~two facilities in Oklahoma City, Oklahoma, and additional~~four service facilities in North Dakota ~~Texas,~~ and ~~Utah.~~Texas. We lease 1822 additional service facilities in Alabama, Arkansas, California, Colorado, New Mexico, Oklahoma, Texas and West Virginia. We also lease service facilities and administrative offices in Argentina, Canada, Egypt and Mexico. We also lease a number of storage facilities located across the geographic markets we serve. ~~During 2021 we utilized a portion of TETRA’s headquarters in The Woodlands, Texas as our headquarters office.~~ As of January 2022, we are leasing our own office space in The Woodlands, Texas for our headquarters. We moved out of the TETRA’s headquarters in The Woodlands, Texas as of January 2022. Our primary assets include our fleet of compression and other equipment. See “Item 1 Business - Products and Services - Contract Services,” for a discussion and description of our compression fleet. All obligations under our First Lien Notes and our Second Lien Notes are secured by security interests in substantially all of our compression assets but excluding other real property assets. ~~As of~~In January 2022, we sold our facilities in Oklahoma City, and we currently do not own no real property in Oklahoma.

Item 3. Legal Proceedings.

From time to time, we may be involved in litigation relating to claims arising out of our operations in the normal course of business. While the outcome of lawsuits against us cannot be predicted with certainty, management does not consider it reasonably possible that a loss resulting from such lawsuits in excess of any amounts accrued has been incurred that is expected to have a material adverse effect on our financial condition, results of operations, or cash flows.

Item 4. Mine Safety Disclosures.

Not applicable.

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PART II

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

Market Information

Our common units are traded on NASDAQ under the symbol “CCLP.” As of March ~~10, 2022,~~9, 2023, there were 8455 holders of record of the common units. The actual number of common unitholders is greater than this number of record holders and includes common unitholders who are beneficial owners but whose shares are held in street name by banks, brokers and other nominees.

Distribution Policy

Our partnership agreement requires us to distribute, no later than 45 days after the end of each quarter, all of our available cash, as defined below, at the end of each quarter. There is no guarantee that we will pay any specific distribution in any quarter.

Definition of Available Cash. We define Available Cash in the partnership agreement, and it means, for any quarter, all cash on hand at the end of that quarter:

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

◦provide for the proper conduct of our business after the end of the quarter;

◦comply with applicable law, any of our future debt instruments or other agreements; or

◦provide funds for future distributions;

•plus, if our general partner so determines, all or any portion of any additional cash and cash equivalents on hand on the date of determination of Available Cash for the quarter resulting from working capital borrowings made after the end of the quarter.

Working capital borrowings are borrowings that are made under a credit agreement, commercial paper facility, or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months from sources other than additional working capital borrowings.

Common Units. We pay quarterly distributions to the holders of common units to the extent we have sufficient cash from our operations after establishment of cash reserves and payment of debt service and other contractual obligations, fees and expenses. Beginning with the distribution for the fourth quarter of 2018, we have paid a distribution of $0.01 per common unit, or $0.04 on an annualized basis. There is no guarantee that we will continue to pay the reduced current quarterly distribution on the common units or be able to increase it in the future. Our Second Lien Notes indenture further restricts our ability to make distributions in respect of our common units in any amount exceeding $0.04 per common unit per year, unless such increased distribution is funded by proceeds from an equity offering. Even if our cash distribution policy is not modified or revoked, the amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Distributions attributable to the year ended ~~2021~~2022 totaled $0.04 per common unit. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources - Cash Flows - Financing Activities” for a discussion of restrictions on our ability to make distributions.

General Partner Interest. Initially, our general partner was entitled to approximately 2.0% of all distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its initial 2.0% general partner interest. Our general partner’s initial 2.0% interest in our distributions has been decreased to approximately 0.5% and may be reduced further if we issue additional limited partner units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its current general partner interest.

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Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Period

Total Number of Units Purchased

Average Price Paid per Unit

Total Number of Units
Purchased as Part of
Publicly Announced
Plans or Programs

Maximum Number (or
Approximate Dollar Value) of
Units that May Yet be
Purchased Under the Publicly Announced Plans or Programs

October 1 – October 31, ~~2021~~2022

—

N/A

November 1 – November 30, ~~2021~~2022

—

N/A

December 1 – December 31, ~~2021~~2022

—

N/A

Total

—

N/A

Securities Authorized for Issuance under Equity Compensation Plans.

See “Item 12. Security Ownership of Certain Beneficial Owners and Management” for information regarding our equity compensation plans as of December 31, ~~2021.~~2022.

Item 6. ~~Selected Financial Data.~~Reserved.

~~Not required.~~

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion is intended to analyze major elements of our consolidated financial statements and provide insight into important areas of management’s focus. This section should be read in conjunction with the Consolidated Financial Statements and accompanying Notes included elsewhere in this Annual Report. Statements in the following discussion may include forward-looking statements. These forward-looking statements involve risks and uncertainties. See “Item 1A. Risk Factors,” for additional discussion of these factors and risks.

Previously, our operations included our new unit sales business that consisted of the fabrication and sale of new standard and custom-designed, engineered compressor packages fabricated primarily at our facility in Midland, Texas. In the fourth quarter of 2020, we fully exited the new unit sales business. These operations were previously included in equipment sales revenues and are now reflected as discontinued operations for all periods presented.

On January 29, 2021, Spartan acquired from TETRA the Partnership’s general partner, IDRs and 10.95 million common units in the Partnership in the GP Sale. In connection with the GP Sale, on January 29, 2021, TETRA entered into the Transition Services Agreement with the Partnership, pursuant to which TETRA provided certain accounting, information technology and ~~back office~~back-office support services to the Partnership for a period of up to one year following closing. The Transition Services Agreement with TETRA expired on January 31, 2022.

On November 10, 2021, the Partnership entered into the Contribution Agreement with CSI Compressco GP, Spartan and Compressco Sub. Pursuant to the terms of the Contribution Agreement, Spartan contributed Spartan Treating to the Partnership. As the Partnership and Spartan Treating were under common control at the time of the Spartan Acquisition, the results of operations have been combined for the Partnership and Spartan Treating from the date common control began, January 29, 2021. See Note 4 - “Common Control Acquisition” in the Notes to Consolidated Financial Statements in this Annual Report for further information.

Business Overview

We ~~provide~~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 ~~4,800~~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 ~~2020, macroeconomic uncertainty in~~2021, our financial results were affected by the ~~oil and natural gas industry drove steep declines in~~economic impact of the COVID-19 pandemic. Reduced spending by oil and gas operators ~~which~~ led to a decline in our compression fleet utilization ~~and~~which impacted revenues and pricing. Oil ~~prices began to stabilize during the third~~ and ~~fourth quarters of 2020 and~~natural gas commodity prices gained strength throughout 2021 ~~reaching~~and increased significantly during 2022. West Texas Intermediate oil prices reached an average of ~~$77~~$83 per barrel in the fourth quarter of ~~2021.~~2022. This ~~improvement~~increase in commodity prices, ~~as well as~~coupled with the ~~beginning~~waning impact of ~~a recovery in~~ the ~~general~~COVID-19 pandemic on the economy, ~~and the energy sector, has~~ resulted in an increase in ~~activity levels from~~the demand for our contract services, ~~and~~ aftermarket services, ~~customers.~~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 ~~2021. In addition, we~~2022. We secured orders from key customers for high-horsepower and electric compressors that started generating revenues in the fourth quarter of ~~2021~~2022 and ~~will~~ continue to be deployed in ~~the first half of 2022.~~2023. Our customers ~~continue to be~~remain focused on capital discipline; however, ~~we continue to see improvement in~~ the levels of quote activity and ~~awards. As the~~awards remain strong. The strengthening market environment ~~continues to evolve,~~has increased, competition for field ~~employees has~~and corporate employees. Supply chain issues, increased commodity prices, and inflationary pressures have ~~driven certain~~increased costs ~~higher. In addition, supply chain disruptions have~~and impacted the availability of our parts and supplies. In ~~addition, war and other armed conflicts,~~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 ~~conflict related to~~ Russia’s invasion of Ukraine, inflationary pressures and ~~any resulting economic downturn~~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 ~~will~~ continue to monitor these risks and take the necessary actions to mitigate them. We have and will continue to

3334

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

In 2020, we took an aggressive approach towards cost management to improve our financial performance and liquidity. We implemented temporary and permanent cost reductions, including reductions in capital expenditures, workforce, and salaries. We also implemented furloughs, a reduction in the cash retainers for the directors of our general partner, the suspension of 401(k) matching contributions for our employees, targeted reduction in selling, general and administrative expenses, rationalization of our real estate facilities, and negotiated reductions in expenditures with many of our suppliers. In 2021, with the improvement in market conditions, we have reversed most of the cost-reduction actions taken in 2020 and have increased capital allocated to growth. With the rapidly changing market environment, we will continue to proactively manage our capital allocation strategies, our liquidity requirements and monitor our expenses and financial performance.

While we are not able to predict how long the COVID-19 pandemic will continue to impact overall market conditions, the demand for oil and gas and the effect it will ultimately have on our business, we continued to see activity levels increase in the fourth quarter of 2021. We are encouraged by the strong oil and gas commodity prices and projections for demand recovery; however, the risk of additional strains of COVID-19, risk that developed vaccines may not be successful in preventing COVID-19 or its spread or the potential outbreak of a new or mutated virus, and the possibility of future lockdowns makes any forecast for improvement uncertain. In addition, continued capital discipline throughout the energy sector may limit production growth even ~~when~~as the economy recovers from ~~the pandemic.~~these external factors. Despite challenging and changing market conditions, we will continue to maintain our commitment to safety and service quality for our customers.

3435

Results of Operations

The following data should be read in conjunction with the Consolidated Financial Statements and the associated Notes contained elsewhere in this document. On November 10, 2021, Spartan contributed Spartan Treating to the Partnership. As the Partnership and Spartan Treating were under common control at the time of the Spartan Acquisition, the results of operations have been combined for the Partnership and Spartan Treating from the date common control began which was January 29, 2021. See Note 4 - “Common Control Acquisition” in the Notes to Consolidated Financial Statements in this Annual Report for further information. Previously, our equipment sales business included our new unit sales business that consisted of the fabrication and sale of new standard and custom-designed, engineered compressor packages fabricated primarily at our facility in Midland, Texas. We sold the Midland facility in July 2020. In the fourth quarter of 2020, we fully exited the new unit sales business and we have reflected these operations as discontinued operations for all periods presented. See Note 109 - “Discontinued Operations” in the Notes to Consolidated Financial Statements in this Annual Report for further information. Used equipment sales revenue continues to be included in equipment sales revenue.

~~2021~~2022 Compared to ~~2020~~2021


		Year Ended December 31,													Year Ended December 31,
						Period-to-Period Change			Percentage of Total Revenues					Period-to-Period Change									Period-to-Period Change			Percentage of Total Revenues			Period-to-Period Change
Consolidated Results of Operations	Consolidated Results of Operations	2021		2020			2021 vs. 2020			2021		2020				2021 vs. 2020		Consolidated Results of Operations	2022		2021			2022 vs. 2021			2022		2021		2021 vs. 2020
		(In Thousands)													(In Thousands)
Revenues:	Revenues:																	Revenues:
Contract services	Contract services	$	234,998	$	228,088		$	6,910		77.3	%	75.6	%			3.0	%	Contract services	$	263,241	$	234,998		$	28,243		74.5	%	77.3	%	12.0	%
Aftermarket services	Aftermarket services	53,534		60,290			(6,756)			17.6	%	20.0	%			(11.2)	%	Aftermarket services	72,928		53,534			19,394			20.6	%	17.6	%	36.2	%
Equipment rentals	Equipment rentals	12,903		—			12,903			4.2	%	—	%			100.0	%	Equipment rentals	14,865		12,903			1,962			4.2	%	4.2	%	15.2	%
Equipment sales	Equipment sales	2,736		13,209			(10,473)			0.9	%	4.4	%			(79.3)	%	Equipment sales	2,364		2,736			(372)			0.7	%	0.9	%	(13.6)	%
Total revenues	Total revenues	304,171		301,587			2,584			100.0	%	100.0	%			0.9	%	Total revenues	353,398		304,171			49,227			100.0	%	100.0	%	16.2	%
Cost of revenues:	Cost of revenues:																	Cost of revenues:
Cost of contract services	Cost of contract services	118,702		108,843			9,859			39.0	%	36.1	%			9.1	%	Cost of contract services	135,639		118,702			16,937			38.4	%	39.0	%	14.3	%
Cost of aftermarket services	Cost of aftermarket services	45,578		52,444			(6,866)			15.0	%	17.4	%			(13.1)	%	Cost of aftermarket services	58,199		45,578			12,621			16.5	%	15.0	%	27.7	%
Cost of equipment rentals	Cost of equipment rentals	1,065		—			1,065			0.4	%	—	%			100.0	%	Cost of equipment rentals	2,346		1,065			1,281			0.7	%	0.4	%	120.3	%
Cost of equipment sales	Cost of equipment sales	3,342		12,946			(9,604)			1.1	%	4.3	%			(74.2)	%	Cost of equipment sales	1,382		3,342			(1,960)			0.4	%	1.1	%	(58.6)	%
Total cost of revenues	Total cost of revenues	168,687		174,233			(5,546)			55.5	%	57.8	%			(3.2)	%	Total cost of revenues	197,566		168,687			28,879			55.9	%	55.5	%	17.1	%
Depreciation and amortization	Depreciation and amortization	78,234		80,007			(1,773)			25.7	%	26.5	%			(2.2)	%	Depreciation and amortization	78,231		78,234			(3)			22.1	%	25.7	%	—	%
Impairments and other charges	Impairments and other charges	—		15,367			(15,367)			—	%	5.1	%			(100.0)	%	Impairments and other charges	135		—			135			—	%	—	%	100.0	%
Insurance recoveries	Insurance recoveries	—		(517)			517			—	%	(0.2)	%			(100.0)	%	Insurance recoveries	—		—			—			—	%	—	%	100.0	%
Selling, general, and administrative expense	Selling, general, and administrative expense	43,299		34,295			9,004			14.2	%	11.4	%			26.3	%	Selling, general, and administrative expense	42,563		43,299			(736)			12.0	%	14.2	%	(1.7)	%

Interest expense, net	Interest expense, net	54,791		54,468			323			18.0	%	18.1	%			0.6	%	Interest expense, net	50,503		54,791			(4,288)			14.3	%	18.0	%	(7.8)	%

Other (income) expense, net	Other (income) expense, net	3,868		3,544			324			1.3	%	1.2	%			9.1	%	Other (income) expense, net	1,882		3,868			(1,986)			0.5	%	1.3	%	(51.3)	%
Loss before taxes and discontinued operations	Loss before taxes and discontinued operations	(44,708)		(59,810)			15,102			(14.7)	%	(19.8)	%			(25.2)	%	Loss before taxes and discontinued operations	(17,482)		(44,708)			27,226			(4.9)	%	(14.7)	%	(60.9)	%
Provision for income taxes	Provision for income taxes	4,952		3,144			1,808			1.6	%	1.0	%			57.5	%	Provision for income taxes	4,786		4,952			(166)			1.4	%	1.6	%	(3.4)	%
Loss from continuing operations	Loss from continuing operations	(49,660)		(62,954)			$	13,294		(16.3)	%	(20.9)	%			(21.1)	%	Loss from continuing operations	(22,268)		(49,660)			$	27,392		(6.3)	%	(16.3)	%	(55.2)	%
Loss from discontinued operations, net of taxes		(612)		(10,886)			$	10,274		(0.2)	%	(3.6)	%			(94.4)	%
Income (loss) from discontinued operations, net of taxes																		Income (loss) from discontinued operations, net of taxes	173		(612)			$	785		—	%	(0.2)	%	(128.3)	%
Net loss	Net loss	$	(50,272)	$	(73,840)		$	23,568		(16.5)	%	(24.5)	%			(31.9)	%	Net loss	$	(22,095)	$	(50,272)		$	28,177		(6.3)	%	(16.5)	%	(56.0)	%


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

1735 Hughes Landing Boulevard, Suite 200	The Woodlands,	Texas	77380
(Address of Principal Executive Offices)			(ZIP CODE)


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


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


	Part I
Item 1.	Business	1
Item 1A.	Risk Factors	9
Item 1B.	Unresolved Staff Comments	30
Item 2.	Properties	30
Item 3.	Legal Proceedings	3031
Item 4.	Mine Safety Disclosures	3031

	Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	3132
Item 6.	Selected Financial Data	3233
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3334
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	46
Item 8.	Financial Statements and Supplementary Data	46
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	46
Item 9A.	Controls and Procedures	46
Item 9B.	Other Information	4849
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	4849

	Part III
Item 10.	Directors, Executive Officers, and Corporate Governance	4849
Item 11.	Executive Compensation	5153
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	5657
Item 13.	Certain Relationships and Related Transactions, and Director Independence	5759
Item 14.	Principal Accounting Fees and Services	5960

	Part IV
Item 15.	Exhibits, Financial Statement Schedules	6061
Item 16.	Form 10-K Summary	64


Range of Horsepower Per Package	Range of Horsepower Per Package	Number of Packages	Aggregate Horsepower	% of Aggregate Horsepower		Range of Horsepower Per Package	Number of Packages	Aggregate Horsepower	% of Aggregate Horsepower

Low-horsepower (0-100)	Low-horsepower (0-100)	2,936	138,982	12	%	Low-horsepower (0-100)	2,693	127,289	11	%
Medium-horsepower (101-1,000)	Medium-horsepower (101-1,000)	1,438	409,290	34	%	Medium-horsepower (101-1,000)	1,426	407,428	34	%
High-horsepower (1,001 and over)	High-horsepower (1,001 and over)	459	648,570	54	%	High-horsepower (1,001 and over)	459	652,640	55	%
Total	Total	4,833	1,196,842	100	%	Total	4,578	1,187,357	100	%


		December 31,					December 31,
		2021		2020			2022		2021
Horsepower	Horsepower					Horsepower
Total horsepower in fleet	Total horsepower in fleet	1,196,842		1,175,075		Total horsepower in fleet	1,187,357		1,196,842
Total horsepower in service	Total horsepower in service	967,085		897,446		Total horsepower in service	1,030,571		967,085
Total horsepower utilization rate	Total horsepower utilization rate	80.8	%	76.4	%	Total horsepower utilization rate	86.8	%	80.8	%


December 31, 2021
(In Thousands)
	Issuers		Guarantor Subsidiaries		Other Subsidiaries		Eliminations		Consolidated
Revenues	$	—	$	424,599	$	64,157	$	(184,585)	$	304,171
Cost of revenues (excluding depreciation and amortization expense)	—		321,454		31,818		(184,585)		168,687
Depreciation and amortization	—		69,954		8,280		—		78,234


Selling, general, and administrative expense	2,286		35,807		5,304		(98)		43,299

Interest expense, net	58,229		(2,472)		(966)		—		54,791

Other expense, net	38		5,442		(1,508)		(104)		3,868
Equity in net (income) loss of subsidiaries	(10,281)		(17,433)		—		27,714		—
Income (loss) before taxes and discontinued operations	(50,272)		11,847		21,229		(27,512)		(44,708)
Provision for income taxes	—		954		3,796		202		4,952
Income (loss) from continuing operations	(50,272)		10,893		17,433		(27,714)		(49,660)
Loss from discontinued operations, net of taxes	—		(612)		—		—		(612)
Net income (loss)	(50,272)		10,281		17,433		(27,714)		(50,272)
Other comprehensive income	(11)		(11)		(11)		22		(11)
Comprehensive income (loss)	$	(50,283)	$	10,270	$	17,422	$	(27,692)	$	(50,283)


Year Ended December 31, 2022
(In Thousands)
	Issuers		Guarantor Subsidiaries		Other Subsidiaries		Eliminations		Consolidated
Revenues	$	—	$	387,170	$	76,548	$	(110,320)	$	353,398
Cost of revenues (excluding depreciation and amortization expense)	—		277,030		30,856		(110,320)		197,566
Depreciation and amortization	—		67,117		11,114		—		78,231


Selling, general, and administrative expense	1,622		36,740		4,201		—		42,563

Interest (income) expense, net	55,813		(5,310)		—		—		50,503

Other (income) expense, net	(356)		1,840		398		—		1,882
Equity in net (income) loss of subsidiaries	(34,984)		(26,363)		—		61,347		—
Income (loss) before taxes and discontinued operations	(22,095)		35,981		29,979		(61,347)		(17,482)
Provision for income taxes	—		1,170		3,616		—		4,786
Income (loss) from continuing operations	(22,095)		34,811		26,363		(61,347)		(22,268)
Income from discontinued operations, net of taxes	—		173		—		—		173
Net income (loss)	(22,095)		34,984		26,363		(61,347)		(22,095)
Other comprehensive income	(2)		(2)		(2)		4		(2)
Comprehensive income (loss)	$	(22,097)	$	34,982	$	26,361	$	(61,343)	$	(22,097)


December 31, 2022
(In Thousands)
		Issuers		Guarantor Subsidiaries		Other Subsidiaries		Eliminations		Consolidated
ASSETS
Current assets		$	—	$	88,098	$	40,217	$	—	$	128,315






Total non-current assets	170,960,000	559,335		556,888		112,444		(634,579)		594,088
Total assets		$	559,335	$	644,986	$	152,661	$	(634,579)	$	722,403

LIABILITIES AND PARTNERS’ CAPITAL
Other current liabilities		$	11,818	$	62,419	$	10,018	$	—	$	84,255


Long-term debt		572,791		6,313		54,912		—		634,016

Operating lease liabilities		—		17,800		1,619		—		19,419
Intercompany payables		—		349,743		9,319		(359,062)		—

Other long-term liabilities		—		8,438		1,549		—		9,987
Total liabilities		584,609		444,713		77,417		(359,062)		747,677
Total partners’ capital		(25,274)		200,273		75,244		(275,517)		(25,274)
Total liabilities and partners’ capital		$	559,335	$	644,986	$	152,661	$	(634,579)	$	722,403


Name and Principal Position	Year	Salary(1)		Bonus		Unit Awards(2)		Non-Equity Incentive Plan Compensation		All Other Compensation(3)		Total(5)
		($)		($)		($)		($)		($)		($)
Brady Murphy(4)	2021	$	—	$	—	$	—	$	—	$	—	$	—
Former President, Chief Executive Officer, Director	2020	$	—	$	—	$	523,837	$	—	$	—	$	523,837

John E. Jackson	2021	$	439,167	$	—	$	900,000	$	489,167	$	10,700	$	1,839,034
Chief Executive Officer, Director

Jonathan W. Byers	2021	$	355,833	$	—	$	900,000	$	234,167	$	10,700	$	1,500,700
Chief Financial Officer, Director

Robert W. Price	2021	$	355,833	$	—	$	900,000	$	234,167	$	10,700	$	1,500,700
Chief Operations Officer


Name and Principal Position	Year	Salary (1)		Bonus		Unit Awards (2)		Non-Equity Incentive Plan Compensation (3)(4)		All Other Compensation (5)		Total (6)
		($)		($)		($)		($)		($)		($)
John E. Jackson	2022	$	516,202	$	—	$	—	$	660,000	$	19,623	$	1,195,825
Chief Executive Officer, Director	2021	$	439,167	$	—	$	900,000	$	489,167	$	10,700	$	1,839,034

Jonathan W. Byers	2022	$	412,962	$	—	$	—	$	330,000	$	16,373	$	759,335
Chief Financial Officer, Director	2021	$	355,833	$	—	$	900,000	$	234,167	$	10,700	$	1,500,700

Robert W. Price	2022	$	412,962	$	—	$	—	$	330,000	$	19,623	$	762,585
Chief Operations Officer, Director	2021	$	355,833	$	—	$	900,000	$	234,167	$	10,700	$	1,500,700


	Unit Awards
	Number of Units that Have Not Vested(1)	Market Value of Units that Have Not Vested(2)
Name
	(#)	($)
John E. Jackson	459,184	$	546,429
Jonathan W. Byers	459,184	$	546,429
Robert W. Price	459,184	$	546,429


Name	Fees Earned or Paid in Cash(1)		Unit Awards(2)		All Other Compensation(3)		Total
Denise Essenberg	$	60,000	$	60,000	$	1,225	$	121,225
Ted Gardner	$	60,000	$	60,000	$	1,225	$	121,225
Stephen Gill	$	60,000	$	60,000	$	1,225	$	121,225
James R. Larson(4)	$	70,000	$	60,000	$	1,225	$	131,225
Michael Tucker	$	15,000	$	—	$	—	$	15,000


Name	Fees Earned or Paid in Cash(1)(2)		Unit Awards(3)		Total

Denise Essenberg	$	70,467	$	60,000	$	130,467
Ted Gardner	$	53,267	$	60,000	$	113,267
Stephen Gill	$	73,267	$	60,000	$	133,267
James R. Larson(4)	$	84,500	$	70,000	$	154,500
Paul D. Coombs(5)	$	3,887	$	—	$	3,887
D. Frank Harrison(5)	$	3,887	$	—	$	3,887
William D. Sullivan(5)	$	3,887	$	—	$	3,887
Elijio V. Serrano(5)	$	—	$	—	$	—


Name and Business Address of Beneficial Owner	Common Units Beneficially Owned		Percentage of Class(1)

Spartan Energy Partners LP 1735 Hughes Landing Blvd., Suite 200 The Woodlands, Texas 77380	63,824,877	(2)	45.4	%


Hill City Capital Mast Fund LP 89 Nexus Way Camara Bay, Grand Cayman KY1-9009	7,407,407		5.3	%


Brady M. Murphy (3)	195,121		*
John E. Jackson	594,476		*
Jonathan W. Byers	443,450		*
Denise Essenberg	31,475		*
Ted Gardner	1,207,586		*
James R. Larson	154,069		*
Stephen R. Gill	370,370
Robert W. Price	326,209		*

Director and executive officers as a group (11 persons)	3,234,250		2.3	%


Name and Business Address of Beneficial Owner	Common Units Beneficially Owned		Percentage of Class(1)
Spartan Energy Partners LP 1735 Hughes Landing, Boulevard, Suite 200 The Woodlands, Texas 77380	63,824,877	(2)	45.2	%

Invesco Ltd. 1555 Peachtree Street, NE, Suite 1800 Atlanta, GA 30309	10,731,105	(3)	7.6	%

Merced Capital, L.P. 601 Carlson Parkway, Suite 200 Minnetonka, MN 55305	7,736,528	(4)	5.5	%

Hill City Capital Master Fund LP 89 Nexus Way Camara Bay, Grand Cayman KY1-9009	7,459,259	(5)	5.3	%

John E. Jackson	871,211		*
Jonathan W. Byers	769,607		*
Denise Essenberg	74,640		*
Ted Gardner	1,250,751		*
James R. Larson	204,387		*
Stephen R. Gill	244,640		*
Robert W. Price	592,944		*
Michael J. Tucker	4,299,150	(6)	3.0	%
Director and executive officers as a group (13 persons)	8,744,443		6.2	%


Plan Category	Plan Category	Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants or Rights	Weighted Average Exercise Price of Outstanding Options, Warrants, or Rights			Number of Securities Remaining Available for Future Issuance under Equity Comp. Plans (Excluding Securities Shown in the First Column)	Plan Category	Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants or Rights	Weighted-Average Exercise Price of Outstanding Options, Warrants or Rights			Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Shown in the First Column)
Equity compensation plans approved by security holders(1)	Equity compensation plans approved by security holders(1)	2,275,622	$	—	(2)	1,000,492	Equity compensation plans approved by security holders(1)	1,880,842	$	—	(2)	575,140
Equity compensation plans not approved by security holders	Equity compensation plans not approved by security holders	—	$	—		—	Equity compensation plans not approved by security holders	—	$	—		—
Total:		2,275,622	$	—		1,000,492
Total							Total	1,880,842	$	—		575,140


1.	Financial Statements of the Partnership
		Page
	Report of Independent Registered Public Accounting Firms (PCAOB ID Number 248); 700 Milam St, Ste. 300, Houston, TX 77002	F-1
	Consolidated Balance Sheets at December 31, ~~2021~~2022 and ~~2020~~2021	F-4
	Consolidated Statements of Operations for the years ended December 31, ~~2021~~2022 and ~~2020~~2021	F-5
	Consolidated Statements of Comprehensive Income for the years ended December 31, ~~2021~~2022 and ~~2020~~2021	F-6
	Consolidated Statements of Partners’ Capital for the years ended December 31, ~~2021~~2022 and ~~2020~~2021	F-7
	Consolidated Statements of Cash Flows for the years ended December 31, ~~2021~~2022 and ~~2020~~2021	F-8
	Notes to Consolidated Financial Statements	F-9
2.	Financial statement schedules have been omitted as they are not required, are not applicable, or the required information is included in the financial statements or notes thereto.
3.	List of Exhibits


2.1			Contribution Agreement, dated November 10, 2021, by and among CSI Compressco ~~lP,~~LP, CSI Compressco GP LLC, Spartan Energy Partners LP,, and CSI Compressco Sub Inc. ~~(incorporated~~(incorporated by reference to Exhibit 2.1 to the Partnership’s Current Report on Form 8-K filed on November 16, 2021 (SEC File No. 001-35195)).
3.1			Certificate of Limited Partnership of Compressco Partners, L.P., dated October 31, 2008 (incorporated by reference to Exhibit 3.1 to the Partnership’s Registration Statement on Form S-1 filed on November 10, 2008 (SEC File No. 333-155260)).

3.3			Certificate of Correction of the Certificate of Limited Partnership of Compressco Partners, L.P. (incorporated by reference to Exhibit 3.5 to Amendment No.1 to the Partnership’s Registration Statement on Form S-1/A filed on December 19, 2008 (SEC File No. 333-155260)).
3.4			Amendment to the Certificate of Limited Partnership of Compressco Partners, L.P., dated November 19, 2014 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on December 1, 2014 (SEC File No. 001-35195)).


3.7			Third Amended and Restated Agreement of Limited Partnership of CSI Compressco LP, dated as of January 6, 2022 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on January11, 2022 (SEC File No. 001-35195)).


3.8			Certificate of Conversion of CSI Compressco GP LLC, dated January 27, 2021 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K filed on January 29, 2021 (SEC File No. 001-35195)).
3.9			Certificate of Formation of CSI Compressco GP LLC, dated January 27, 2021 (incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K filed on January 29, 2021 (SEC File No. 001-35195)).
3.10			Limited Liability Company Agreement of CSI Compressco GP LLC, dated as of January 27, 2021 (incorporated by reference to Exhibit 3.3 to the Current Report on Form 8-K filed on January 29, 2021 (SEC File No. 001-35195)).
4.1			Specimen Unit Certificate representing Common Units (incorporated by reference to Exhibit 4.1 to Amendment No. 3 to the Partnership’s Registration Statement on Form S-1/A filed on April 12, 2011 (SEC File No. 333-155260)).
~~4.2~~			Indenture, dated as of August 4, 2014, by and among Compressco Partners, L.P., Compressco Finance Inc., the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K filed on August 4, 2014 (SEC File No. 001-35195)).
~~4.3~~4.2			Indenture, dated as of March 22, 2018, by and among CSI Compressco LP, CSI Compressco Finance Inc., the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Partnership’s Form 8-K filed on March 27, 2018 (SEC File No. 001-35195)).
~~4.4~~4.3			Form of 7.500% Senior Secured First Lien Note due 2025 (incorporated by reference to Exhibit 4.1 to the Partnership’s Form 8-K filed on March 27, 2018 (SEC File No. 001-35195)).
~~4.5~~4.4			First Supplemental Indenture, dated as of June 12, 2020, by and among CSI Compressco LP, CSI Compressco Finance, Inc., the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Partnership’s Form 8-K filed on June 12, 2020 (SEC File No. 001-35195)).
~~4.6~~4.5			First Lien Supplemental Indenture, dated as of June 12, 2020, by and among CSI Compressco LP, CSI Compressco Finance, Inc., the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 to the Partnership’s Form 8-K filed on June 12, 2020 (SEC File No. 001-35195)).
~~4.7~~4.6			10.000%/10.750% Senior Secured Second Lien Notes due 2026 Indenture, dated as of June 12, 2020, by and among CSI Compressco LP, CSI Compressco Finance, Inc., the Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 to the Partnership’s Form 8-K filed on June 12, 2020 (SEC File No. 001-35195).


~~4.8~~4.7			Form of 10.000%/10.750% Senior Secured Second Lien Note due 2026 (incorporated by reference to Exhibit 4.3 to the Partnership’s Form 8-K filed on June 12, 2020 (SEC File No. 001-35195)).
~~4.9~~4.8			Second Lien Supplemental Indenture, dated as of November 16, 2021, by and among CSI Compressco LP, CSI Compressco Finance, Inc., the Guarantors named therein, U.S. Bank National Association, as trustee, and U.S. Bank National Association, as collateral trustee (incorporated by reference to Exhibit 4.2 to the Partnership’s Current Report on Form 8-K filed November 16, 2021 (SEC File No. 001-35195)).
~~4.10~~4.9			Registration Rights Agreement, dated November 10, 2021, by and among CSI Compressco LP and each of the holders party thereto (incorporated by reference to Exhibit 4.1 to the Partnership’s Current Report on Form 8-K filed November 16, 2021 (SEC File No. 001-35195)).
~~4.11~~4.10			Description of the Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934
10.1			Contribution, Conveyance and Assumption Agreement, dated June 20, 2011, by and among Compressco, Inc., Compressco Field Services, Inc., Compressco Canada, Inc., Compressco de Mexico, S. de R.L. de C.V., Compressco Partners GP Inc., Compressco Partners, L.P., Compressco Partners Operating, LLC, Compressco Netherlands B.V., Compressco Holdings, LLC, Compressco Netherlands Coöperatief U.A., Compressco Partners Sub, Inc., TETRA International Incorporated, Production Enhancement Mexico, S. de R.L. de C.V. and TETRA Technologies, Inc. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 24, 2011 (SEC File No. 001-35195)).
~~10.2~~			Omnibus Agreement, dated June 20, 2011, by and among Compressco Partners, L.P., TETRA Technologies, Inc. and Compressco Partners GP Inc. (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed on June 24, 2011 (SEC File No. 001-35195)).
~~10.3~~10.2			Form of Indemnification Agreement (incorporated by reference to Exhibit 10.5 to Amendment No. 4 to the Partnership’s Registration Statement on Form S-1/A filed on May 27, 2011 (SEC File No. 333-155260)).
10.4***			~~Change of Control Agreement with Ronald J. Foster (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 4, 2013 (SEC File No. 001-35195)).~~
10.5***			First Amendment to Change of Control Agreement, dated June 23, 2019, by and between CSI Compressco GP Inc. and Ronald J. Foster (incorporated by reference to Exhibit 10.2 to the Partnership’s Quarterly Report on Form 10-Q filed on August 8, 2019 (SEC File No. 001-35195)).
10.6***			Change of Control Agreement dated August 10, 2020 by and between CSI Compressco GP Inc. and Roy E. McNiven (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on August 11, 2020 (SEC File No. 001-35195)).


10.7***			First Amendment to Change of Control Agreement, dated as of March 11, 2021, by and between Roy E. McNiven and CSI Compressco GP LLC (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on March 12, 2021 (SEC File No. 001-35195)).
10.810.3**			Form of Cash Retention Award Agreement under the CSI Compressco LP Second Amended and Restated 2011 Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q filed on November 2, 2020 (SEC File No. 001-35195)).


~~10.9~~10.4			First Amendment to Omnibus Agreement, dated June 20, 2014, by and among TETRA Technologies, Inc., Compressco Partners, L.P., and Compressco Partners GP Inc. (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed on June 26, 2014 (SEC File No. 001-35195)).
10.1010.5**			CSI Compressco LP Second Amended and Restated 2011 Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on December 4, 2018 (SEC File No. 001-35195)).
10.1110.6**			Form of Director Restricted Unit Agreement under the CSI Compressco LP Second Amended and Restated 2011 Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q filed on May 9, 2019 (SEC File No. 001-35195)).
10.1210.7**			Form of Performance Phantom Unit Agreement under the CSI Compressco LP Second Amended and Restated 2011 Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Partnership’s Quarterly Report on Form 10-Q filed on May 9, 2019 (SEC File No. 001-35195)).
10.1310.8**			Form of Phantom Unit Agreement under the CSI Compressco LP Second Amended and Restated 2011 Long Term Incentive Plan (incorporated by reference to Exhibit 10.3 to the Partnership’s Quarterly Report on Form 10-Q filed on May 9, 2019 (SEC File No. 001-35195)).
10.1410.9**			Form of Performance Phantom Unit Agreement under the CSI Compressco LP Second Amended and Restated 2011 Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Partnership’s Quarterly Report on Form 10-Q filed on May 7, 2020 (SEC File No. 001-35195)).
10.1510.10**			Form of Non-Employee Director Phantom Unit Agreement under the CSI Compressco LP Second Amended and Restated 2011 Long Term Incentive Plan (incorporated by reference to Exhibit 10.4 to the Partnership’s Quarterly Report on Form 10-Q filed on May 9, 2019 (SEC File No. 001-35195)).
~~10.16~~10.11			Loan and Security Agreement, dated as of June 29, 2018, by and among CSI Compressco LP, CSI Compressco Sub Inc., CSI Compressco Operating LLC, as borrowers, certain subsidiaries the borrowers named as guarantors therein, the lenders from time to time party thereto, and Bank of America, N.A., as administrative agent, collateral agent, letter of credit issuer and swing line issuer (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on July 3, 2018 (SEC File No. 001-35195)).
~~10.17~~10.12			First Amendment to Loan and Security Agreement, dated June 26, 2019, by and among CSI Compressco LP, CSI Compressco Sub Inc., and CSI Compressco Operating LLC, as borrowers, and Bank of America, N.A., as administrative agent, collateral agent, letter of credit issuer and swing line issuer (incorporated by reference to Exhibit 10.1 to the Partnership’s Quarterly Report on Form 10-Q filed on August 8, 2019 (SEC File No. 001-35195)).
~~10.18~~10.13			Second Amendment to Loan and Security Agreement, dated June 11, 2020, by and among CSI Compressco LP, CSI Compressco Sub, Inc. and Bank of America, N.A., in its capacity administrative agent, issuing bank and swing line issuer, and the other lenders and loan parties party thereto (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on June 12, 2020 (SEC File No. 001-35195)).
~~10.19~~10.14			Third Amendment to Loan and Security Agreement, dated January 29, 2021, by and among CSI Compressco LP, CSI Compressco Sub, Inc. and Bank of America, N.A., in its capacity administrative agent, issuing bank and swing line issuer, and the other lenders and loan parties party thereto (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on January 29, 2021 (SEC File No. 001-35195)).
~~10.20~~10.15			Fourth Amendment to Loan and Security Agreement, dated November 10, 2021, by and among CSI Compressco LP, certain of its subsidiaries, Bank of America, N.A., as administrative agent, issuing bank and swing line lender, and the lenders party thereto (incorporated by reference to Exhibit 10.3 to the Partnership’s Form 8-K filed on November 16, 2021 (SEC File No. 001-35195)).


~~10.21+~~10.16			Loan, Security and Guaranty Agreement, dated January 29, 2021, by and among Spartan Energy Partners LP, Spartan Energy Services LLC, Spartan Terminals Operating, Inc., Spartan Operating Company LLC, Treating Holdco LLC, Bank of America, N.A., as agent for the lenders, and the lenders party thereto.
~~10.22~~10.17			First Amendment to Loan, Security and Guaranty Agreement, dated November 10, 2021, by and among Spartan Energy Services LLC, Treating Holdco LLC, Spartan Energy Partners LP, Spartan Terminals Operating, Inc., Spartan Operating Company LLC, Bank of America, N.A., as agent for the lenders, and the lenders party thereto (incorporated by reference to Exhibit 10.4 to the Partnership’s Form 8-K filed on November 16, 2021 (SEC File No. 001-35195)).
~~10.23~~			Purchase Agreement, dated as of March 8, 2018, by and among CSI Compressco LP, CSI Compressco Finance Inc., the guarantors named therein and the initial purchasers named therein (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on March 13, 2018 (SEC File No. 001-35195)).
~~10.24~~10.18			Collateral Trust Agreement, dated as of March 22, 2018, by and among CSI Compressco LP, CSI Compressco Finance Inc., the other Grantors from time to time party thereto, U.S. Bank National Association, as Trustee, the other Priority Lien Representatives from time to time party thereto, and U.S. Bank National Association, as Collateral Trustee (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on March 27, 2018 (SEC File No. 001-35195)).
~~10.25~~10.19			Collateral Trust Agreement, dated June 12, 2020, by and among CSI Compressco LP, CSI Compressco Finance Inc., the other Grantors from time to time party thereto, U.S. Bank National Association, as Trustee, the other Junior Lien Representatives from time to time party thereto, and U.S. Bank National Association, as Collateral Trustee (incorporated by reference to Exhibit 10.2 to the Partnership’s Form 8-K filed on June 12, 2020 (SEC File No. 001-35195)).
~~10.26~~10.20			Transition Services Agreement, dated January 29, 2021, by and among TETRA Technologies, Inc. and CSI Compressco LP (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on January 29, 2021 (SEC File No. 001-35195)).


~~10.27~~10.21			Management Services Agreement, dated November 10, 2021, by and among CSI Compressco LP, CSI Compressco GP LLC, Spartan Energy Partners LP, Spartan Energy Partners GP LLC and Spartan Operating Company LLC (incorporated by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on November 16, 2021 (SEC File No. 001-35195)).
~~10.28~~			Common Unit Purchase Agreement, dated November 10, 2021, by among CSI Compressco LP and the purchasers party thereto (incorporated by reference to Exhibit 10.2 to the Partnership’s Form 8-K filed on November 16, 2021 (SEC File No. 001-35195)).
21+			Subsidiaries of the Partnership
22+			List of Subsidiary Guarantors
23.1+			Consent of Grant Thornton LLP

31.1+			Certification of Principal Executive Officer Pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2+			Certification of Principal Financial Officer Pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act, As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**			Certification of Principal Executive Officer Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2**			Certification of Principal Financial Officer Furnished Pursuant to 18 U.S.C. Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS++			XBRL Instance Document
101.SCH++			XBRL Taxonomy Extension Schema Document
101.CAL++			XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF++			XBRL Taxonomy Extension Definition Linkbase Document
101.LAB++			XBRL Taxonomy Extension Label Linkbase Document
101.PRE++			XBRL Taxonomy Extension Presentation Linkbase Document
104++			Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).


		CSI COMPRESSCO LP
		By:	CSI Compressco GP LLC,
			its general partner
Date:	March ~~14, 2022~~13, 2023	By:	/s/John E. Jackson
			John E. Jackson, Chief Executive Officer
			(Principal Executive Officer)


Signature	Title	Date
/s/Ted A. Gardner	Chairman of the Board of Directors	March ~~14, 2022~~13, 2023
Ted A. Gardner

/s/John E. Jackson	Chief Executive Officer and Director	March ~~14, 2022~~13, 2023
John E. Jackson	(Principal Executive Officer)

/s/Jonathan W. Byers	Chief Financial Officer and Director	March ~~14, 2022~~13, 2023
Jonathan W. Byers	(Principal Financial Officer)

/s/~~Michael E. Moscoso~~Riplee L. Parkening	~~Vice President of Finance~~Controller	March ~~14, 2022~~13, 2023
~~Michael E. Moscoso~~Riplee L. Parkening	(Principal Accounting Officer)

/s/Denise G. Essenberg	Director	March ~~14, 2022~~13, 2023
Denise G. Essenberg

/s/Stephen R. Gill	Director	March ~~14, 2022~~13, 2023
Stephen R. Gill

/s/James R. Larson	Director	March ~~14, 2022~~13, 2023
James R. Larson

/s/Robert W. Price	Director	March ~~14, 2022~~13, 2023
Robert W. Price

/s/Michael J. Tucker	Director	March 13, 2023
Michael J. Tucker


		December 31, 2021		December 31, 2020			December 31, 2022		December 31, 2021
ASSETS	ASSETS					ASSETS
Current assets:	Current assets:					Current assets:
Cash and cash equivalents	Cash and cash equivalents	$	6,598	$	16,577	Cash and cash equivalents	$	8,475	$	6,598
Trade accounts receivable, net of allowance for doubtful accounts of $1,223 in 2021 and $1,333 in 2020		53,520		43,837
Trade accounts receivable, net of allowance for doubtful accounts of $736 in 2022 and $1,223 in 2021						Trade accounts receivable, net of allowance for doubtful accounts of $736 in 2022 and $1,223 in 2021	65,085		53,520
Trade receivable - affiliate						Trade receivable - affiliate	948		—
Inventories	Inventories	33,271		31,188		Inventories	45,902		33,271
Prepaid expenses and other current assets	Prepaid expenses and other current assets	7,390		5,184		Prepaid expenses and other current assets	7,905		7,390
Current assets associated with discontinued operations		—		39

Total current assets	Total current assets	100,779		96,825		Total current assets	128,315		100,779
Property, plant, and equipment:	Property, plant, and equipment:					Property, plant, and equipment:
Land and building	Land and building	13,409		13,259		Land and building	7,227		13,409
Compressors and equipment	Compressors and equipment	1,072,927		975,375		Compressors and equipment	1,103,657		1,072,927
Vehicles	Vehicles	8,469		7,692		Vehicles	8,640		8,469
Construction in progress	Construction in progress	31,968		12,763		Construction in progress	37,183		31,968
Total property, plant, and equipment	Total property, plant, and equipment	1,126,773		1,009,089		Total property, plant, and equipment	1,156,707		1,126,773
Less accumulated depreciation	Less accumulated depreciation	(556,311)		(457,688)		Less accumulated depreciation	(611,734)		(556,311)
Net property, plant, and equipment	Net property, plant, and equipment	570,462		551,401		Net property, plant, and equipment	544,973		570,462
Other assets:	Other assets:					Other assets:

Deferred tax assets	Deferred tax assets	5		10		Deferred tax assets	3		5
Intangible assets, net of accumulated amortization of $33,672 in 2021 and $30,711 in 2020		22,095		25,057
Intangible assets, net of accumulated amortization of $36,627 in 2022 and $33,672 in 2021						Intangible assets, net of accumulated amortization of $36,627 in 2022 and $33,672 in 2021	19,140		22,095
Operating lease right-of-use assets	Operating lease right-of-use assets	25,898		32,637		Operating lease right-of-use assets	27,205		25,898
Other assets	Other assets	3,122		4,036		Other assets	2,767		3,122

Total other assets	Total other assets	51,120		61,740		Total other assets	49,115		51,120
Total assets	Total assets	$	722,361	$	709,966	Total assets	$	722,403	$	722,361
LIABILITIES AND PARTNERS’ CAPITAL	LIABILITIES AND PARTNERS’ CAPITAL					LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:	Current liabilities:					Current liabilities:
Accounts payable	Accounts payable	$	28,958	$	19,766	Accounts payable	$	34,589	$	28,958
Unearned income	Unearned income	2,187		269		Unearned income	2,590		2,187
Accrued liabilities and other	Accrued liabilities and other	39,888		35,801		Accrued liabilities and other	47,076		39,888
Amounts payable to affiliates		—		3,234

Current liabilities associated with discontinued operations	Current liabilities associated with discontinued operations	262		345		Current liabilities associated with discontinued operations	—		262
Total current liabilities	Total current liabilities	71,295		59,415		Total current liabilities	84,255		71,295
Other liabilities:	Other liabilities:					Other liabilities:
Long-term debt, net	Long-term debt, net	631,141		638,631		Long-term debt, net	634,016		631,141
Deferred tax liabilities	Deferred tax liabilities	819		1,478		Deferred tax liabilities	1,245		819

Operating lease liabilities	Operating lease liabilities	17,648		24,059		Operating lease liabilities	19,419		17,648
Other long-term liabilities	Other long-term liabilities	299		11,716		Other long-term liabilities	8,742		299
Total other liabilities	Total other liabilities	649,907		675,884		Total other liabilities	663,422		649,907
Commitments and contingencies	Commitments and contingencies	0		0		Commitments and contingencies
Partners’ capital:	Partners’ capital:					Partners’ capital:
General partner interest	General partner interest	(1,486)		(885)		General partner interest	(1,618)		(1,486)
Common units (140,386,811 units issued and outstanding at December 31, 2021 and 47,352,291 units issued and outstanding at December 31, 2020)		17,049		(10,055)
Accumulated other comprehensive income (loss)		(14,404)		(14,393)
Common units (141,237,462 units issued and outstanding at December 31, 2022 and 140,386,811 units issued and outstanding at December 31, 2021)						Common units (141,237,462 units issued and outstanding at December 31, 2022 and 140,386,811 units issued and outstanding at December 31, 2021)	(9,250)		17,049
Accumulated other comprehensive loss						Accumulated other comprehensive loss	(14,406)		(14,404)
Total partners’ capital (deficit)	Total partners’ capital (deficit)	1,159		(25,333)		Total partners’ capital (deficit)	(25,274)		1,159
Total liabilities and partners’ capital	Total liabilities and partners’ capital	$	722,361	$	709,966	Total liabilities and partners’ capital	$	722,403	$	722,361


		Partners’ Capital						Accumulated Other Comprehensive Income (Loss)			Total Partners’ Capital (Deficit)				Partners’ Capital							Accumulated Other Comprehensive Income (Loss)				Total Partners’ Capital (Deficit)
				Limited Partners												Limited Partners
		General Partner		Common Unitholders			Accumulated Other Comprehensive Income (Loss)							General Partner	Common Unitholders					Accumulated Other Comprehensive Income (Loss)	Total Partners’ Capital (Deficit)
		Amount		Units	Amount										Amount		Units	Amount

Balance as of December 31, 2019		$	180	47,079	$	63,384							$	(14,573)	$	48,991
Net loss for 2020		(1,037)		—	(72,803)					—				(73,840)
Balance as of December 31, 2020														Balance as of December 31, 2020	$	(885)	47,352	$	(10,055)					$	(14,393)			$	(25,333)
Net loss for 2021														Net loss for 2021	(573)		—	(49,699)				—				(50,272)
Distributions ($0.04 per unit)	Distributions ($0.04 per unit)	(28)		—	(1,890)			—			(1,918)			Distributions ($0.04 per unit)	(28)		—	(1,917)				—				(1,945)
Equity compensation		—		—	1,254			—			1,254
Equity compensation, net														Equity compensation, net	—		—	1,954				—				1,954
Vesting of Phantom Units														Vesting of Phantom Units	—		626	—				—				—
Consideration for the drop down of entities														Consideration for the drop down of entities	—		48,400	19,111				—				19,111
Proceeds from issuance of common units, net of issuance costs														Proceeds from issuance of common units, net of issuance costs	—		44,008	57,796				—				57,796
Other														Other	—		—	(141)				—				(141)
Translation adjustment, net of taxes of $0														Translation adjustment, net of taxes of $0	—		—	—				(11)				(11)
Balance as of December 31, 2021														Balance as of December 31, 2021	$	(1,486)	140,386	$	17,049			$	(14,404)			$	1,159
Net loss for 2022														Net loss for 2022	(104)		—	(21,991)				—				(22,095)

Distributions ($0.04 per unit)														Distributions ($0.04 per unit)	(28)		—	(5,641)				—				(5,669)
Equity compensation, net														Equity compensation, net	—		—	1,333				—				1,333
Vesting of Phantom Units	Vesting of Phantom Units	—		273	—			—			—			Vesting of Phantom Units	—		851	—				—				—

Translation adjustment, net of taxes of $0		—		—	—			180			180
Balance as of December 31, 2020		$	(885)	47,352	$	(10,055)		$	(14,393)		$	(25,333)
Net loss for 2021		(573)		—	(49,699)			—			(50,272)

Distributions ($0.04 per unit)		(28)		—	(1,917)			—			(1,945)
Equity compensation		—		—	1,954			—			1,954
Vesting of Phantom Units		—		626	—			—			—
Consideration for the Spartan acquisition		—		48,400	19,111			—			19,111
Proceeds from issuance of common units, net of issuance costs		—		44,008	57,796			—			57,796

Translation adjustment, net of taxes of $0	Translation adjustment, net of taxes of $0	—		—	—			(11)			(11)			Translation adjustment, net of taxes of $0	—		—	—				(2)				(2)
Other		$	—	—	$	(141)		$	—		$	(141)
Balance as of December 31, 2021		$	(1,486)	140,386	$	17,049		$	(14,404)		$	1,159

Balance as of December 31, 2022														Balance as of December 31, 2022	$	(1,618)	141,237	$	(9,250)			$	(14,406)			$	(25,274)


Buildings						15 – 30 years
Compressors, Amine plants, and Production equipment						12 – 25 years
Other equipment						2 – 8 years
Vehicles						3 – 5 years
Information systems						7 years


	2022		2023		2024		2025		2026		Total
	(In Thousands)
Contract services contracts remaining performance obligations	$	76,218	$	11,908	$	1,806	$	28	$	—	$	89,960







Current assets	$	6,616



Property, plant, and equipment	112,972
Less accumulated depreciation	(53,039)
Net property, plant, and equipment	59,933



Other assets	1,245
Total assets	67,794








Current liabilities	7,597
Long-term debt, net	32,590
Other liabilities	239
Total liabilities	40,426

Net assets	$	27,368


	Year Ended December 31, 2021
	CSI Compressco LP		Spartan Treating		Total
	(In Thousands, Unaudited)
Revenue	$	281,146	$	25,181	$	306,327
Income (loss) from continuing operations	$	(60,537)	$	11,666	$	(48,871)
Net income (loss)	$	(61,149)	$	11,666	$	(49,483)


	Year Ended December 31, 2020
	CSI Compressco LP		Spartan Treating		Total
	(In Thousands, Unaudited)
Revenue	$	301,587	$	32,315	$	333,902
Income (loss) from continuing operations	$	(62,954)	$	8,075	$	(54,879)
Net income (loss)	$	(73,840)	$	8,075	$	(65,765)


		Operating Leases			Operating Leases
		(In Thousands)			(In Thousands)
2022		$	9,594
2023	2023	7,391		2023	$	10,244
2024	2024	4,898		2024	6,788
2025	2025	4,240		2025	5,792
2026	2026	3,460		2026	5,149
2027				2027	2,346
Thereafter	Thereafter	1,122		Thereafter	2,772
Total lease payments	Total lease payments	30,705		Total lease payments	33,091
Less imputed interest	Less imputed interest	(5,341)		Less imputed interest	(6,052)
Total lease liabilities	Total lease liabilities	$	25,364	Total lease liabilities	$	27,039


	~~December 31, 2021~~		~~December 31, 2020~~
	~~(In Thousands)~~
~~Equipment rentals~~	$	~~12,903~~	$	—