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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements, the notes thereto, and the other financial information appearing elsewhere in this report. The following discussion includes forward-looking statements that involve certain risks and uncertainties. See Part I “Disclosure Regarding Forward-Looking Statements” and Part I, Item 1A “Risk Factors”.

Discussion and analysis of our operating highlights and financial results of operations for the year ended December 31, 2020 compared to the year ended December 31, 2019 is included under the headings in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Operating Highlights, Financial Results of Operations, Liquidity and Capital Resources, and Critical Accounting Policies and Estimates” in our Annual Report on Form 10-K filed for the year ended December 31, 2020 with the SEC on February 16, 2021.

Overview

We provide compression services in a number of shale plays throughout the U.S., including the Utica, Marcellus, Permian Basin, Delaware Basin, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, Haynesville, Niobrara and Fayetteville shales. Demand for our services is driven by the domestic production of natural gas and crude oil. As such, we have focused our activities in areas of attractive natural gas and crude oil production, which are generally found in these shale and unconventional resource plays. According to studies promulgated by the EIA, the production and transportation volumes in these shale plays are expected to collectively increase over the long term. Furthermore, the changes in production volumes and pressures of shale plays over time require a wider range of compression than in conventional basins. We believe we are well-positioned to meet these changing operating conditions due to the operational design flexibility inherit in our compression units.

While our business focuses largely on compression services serving infrastructure applications, including centralized natural gas gathering systems and processing facilities, which utilize large horsepower compression units, typically in shale plays, we also provide compression services in more mature conventional basins, including gas lift applications on crude oil wells targeted by horizontal drilling techniques. Gas lift, a process by which natural gas is injected into the production tubing of an existing producing well, in order to reduce the hydrostatic pressure and allow the oil to flow at a higher rate, and other artificial lift technologies are critical to the enhancement of oil production from horizontal wells operating in tight shale plays.

Recent Developments

Seventh Amended and Restated Credit Agreement

On December 8, 2021, we amended and restated our existing credit agreement by entering into the Credit Agreement. The Credit Agreement matures on December 8, 2026, except that if any portion of the Senior Notes 2026 are outstanding on December 31, 2025, the Credit Agreement will mature on December 31, 2025.

Please see Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Revolving Credit Facility” for additional information regarding our Credit Agreement.

General Trends and Outlook

A significant amount of our assets are utilized in natural gas infrastructure applications typically located in shale plays, primarily in centralized gathering systems and processing facilities utilizing large horsepower compression units. Given the infrastructure nature of these applications and long-term investment horizon of our customers, we have generally experienced stability in service rates and higher sustained utilization relative to other businesses more directly tied to drilling activity and wellhead economics. In addition to our natural gas infrastructure applications, a portion of our fleet is used in connection with gas lift applications on crude oil production targeted by horizontal drilling techniques and can be accomplished by both small and large horsepower compression equipment.

Domestic natural gas production generally occurs in either primarily natural gas basins, such as the Marcellus, Utica and Haynesville Shales, or in basins where natural gas is produced alongside crude oil, also known as “associated” gas, such as the Permian and Delaware Basins, Eagle Ford and the Mid-Continent. Relative stability in commodity prices over much of the past

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decade encouraged investment in domestic exploration and production and midstream infrastructure across the energy industry, particularly in the low-cost basins characterized by associated gas and crude oil production. The development of these basins producing both commodities has created additional incremental demand for natural gas compression over the recent past as it is a critical method to transport associated gas volumes or enhance crude oil production through gas lift.

Following this period of general stability and moderate growth for both the midstream energy industry and the broader energy industry, the events of 2020—including the COVID-19 pandemic and the crude oil price wars— impacted participants across the energy industry, including us and our customers. The significant price volatility in both crude oil and natural gas had an impact on energy companies’ financial performance, and combined with reduced and uncertain future demand, created a market environment that saw numerous corporate restructurings in the energy industry as companies worked to adjust to a vastly different marketplace than prior to Spring of 2020. This included a focus on rebuilding balance sheet strength, driven in part by meaningful reductions in capital investment.

During 2021, the general energy industry in large part recovered from the low commodity prices and reduced activity of 2020, driven by continued, and growing, demand for both crude oil and natural gas as countries across the world emerged from COVID-19 lock-downs and economies began to recover. As the demand for hydrocarbons generally follows economic growth, 2021 saw strong demand growth coupled with constrained supply, due in part to the effects of reduced capital investment across the energy sector. This has driven commodity prices to meaningfully higher levels, and has helped the energy industry further recover from the lows of 2020. Members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC and other allied producing countries, “OPEC+”) have increased production moderately, but continue to be focused on supply and demand dynamics. In addition, some members of OPEC+ may not be able to increase production to the level of their agreed-to supply amounts.

While the ongoing COVID-19 pandemic continues to create economic uncertainty, many economies and industries that directly or indirectly use crude oil and natural gas have begun to recover, resulting in increased demand. According to the EIA, global consumption of petroleum and liquids fuels increased over 5% in 2021 and the EIA estimates that U.S. gross domestic product increased 5.7% in 2021, both illustrating the continued demand recovery in the U.S. as well as globally.

While overall, economies are working to return to pre-pandemic levels, since the Spring of 2020, the domestic oil and gas industry has been characterized by robust capital discipline, even in the face of the increasing commodity prices witnessed during 2021. Greatly moderated levels of production, exploration and capital investment activity in the upstream sector has trickled down through the midstream sector, and during 2021, we experienced more reduced demand for our compression services than we had anticipated, given the constructive broader commodity environment and increasing demand for crude oil and natural gas. Although our business is focused on providing compression services and does not have any direct exposure to commodity prices, we have indirect exposure to commodity prices as overall levels of activity across the energy industry are influenced by the commodity price environment. And given the level of capital discipline exhibited during 2021, our customers saw generally lower levels of new drilling activity, and instead producers sought alternative paths to maintaining production levels to meet demand, including by working off inventory of drilled-but-uncompleted wells as well as using smaller booster compression units in lieu of drilling new wells.

The EIA’s January 2022 Short-Term Energy Outlook (“EIA Outlook”) estimates that annual U.S. crude oil production averaged 11.2 million barrels per day (“bpd”) in 2021, down just 0.1 million bpd from 2020, primarily due to well freeze-offs during February 2021 and well shut-ins during Hurricane Ida in August and September 2021. In 2022 and 2023, the EIA Outlook expects U.S. crude oil production growth to resume, with 11.8 million bpd in 2022 and 12.4 million bpd in 2023, which would reflect the highest annual average on record, surpassing 2019’s level of production. The expected increase in production is in part due to increased crude oil rig activity, which was up 80% over the past year, according to Baker Hughes, driven by higher crude oil prices, which averaged above $75 per barrel in the fourth quarter of 2021, compared to $58 per barrel in the first quarter of 2021. We expect this increased activity in crude oil and natural gas production throughout 2021 to translate into increased demand for our compression services, particularly in associated gas basins like the Permian Basin, Delaware Basin and Eagle Ford Shale.

While metrics such as monthly crude oil production, rig counts and prices would suggest a positive environment for natural gas producers, variables including takeaway capacity, flaring considerations, reservoir pressure and flow rates, high switching costs associated with large horsepower compressors (borne by our customers), and specific company dynamics may all factor into producers’ decisions with respect to their existing production. For example, as wells age, and the reservoir pressures naturally continue to decline, more horsepower may be required to meet the customer’s operational needs. In contrast, small horsepower gas lift applications have historically been more susceptible to commodity price swings, and we have experienced, and may continue to experience, some pressure on service rates and utilization in small horsepower gas lift applications. We cannot predict with reasonable certainty the effect on utilization of our assets servicing existing production in these regions.

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Unlike crude oil, natural gas production and prices have been influenced by different drivers over the recent past, as there is no OPEC+ equivalent in the global natural gas market and therefore the price of natural gas is generally determined by market forces of supply and demand rather than by a centralized market coordinator. Over the past several years, increased gas production in the U.S. driven by large volumes of gas produced from shale sources has been a main driver of an overall drop in natural gas prices. Domestic power generation and industrial uses such as chemical plants have benefited from this low-price environment. These low prices, combined with a general move away from coal-fired power plants due to emissions concerns, has resulted in power generation becoming, and remaining, the largest use of natural gas in the U.S. This low natural gas price environment helped create relatively resilient baseload demand for natural gas. Also, the development of long-term liquefied natural gas (“LNG”) export infrastructure has continued to occur, driven in part by attractive global prices, and according to the EIA, estimates are that the U.S. set a record for LNG exports during December 2021. The EIA Outlook expects U.S. natural gas consumption to remain consistent in 2022 and 2023, reflecting a decrease in the usage of natural gas in the electric power generation sector, as a result of relatively higher natural gas prices (versus coal) and increased power generation from renewables, which decreases are expected to be partially offset by other uses, including increased LNG exports as well as increased pipeline exports to Mexico. While natural gas prices were volatile in 2021, during the second half of the year they were relatively higher compared with recent years, which the EIA Outlook expects to last into 2022 and 2023. However, we expect the baseload natural gas demand previously described will continue to support long-term domestic natural gas production.

On the whole, we believe the longer-term outlook for natural gas fundamentals remains positive, as market signs, including natural gas futures market, point to a more balanced natural gas market through 2022 and beyond.

In summary, the broader outlook for commodity prices improved considerably during 2021. While continuing uncertainty with respect to demand may have a varying impact on our business and the ultimate timing of a recovery in utilization metrics, we believe the outlook for the natural gas industry in the U.S. is positive. The overall outlook for our compression services will depend, in part, on the strength and duration of the ongoing recovery in the commodity markets. While we anticipate that the combination of commodity prices and demand may likely have a positive impact on activity levels in both the upstream and midstream sectors, we cannot predict the ultimate magnitude of that impact on our business and expect it to be varied across our operations, depending on the region, customer, nature of our services, contract term and other factors.

Ultimately, the extent to which our business will be impacted by the factors described above, as well as future developments beyond our control, cannot be predicted with reasonable certainty. However, we continue to believe that overall the long-term demand for our compression services will continue given the necessity of compression in facilitating the transportation and processing of natural gas as well as the production of crude oil.

COVID-19 Update

Beginning in the first quarter of 2020, the COVID-19 pandemic prompted several states and municipalities in which we operate to take extraordinary and wide-ranging actions to contain and combat the outbreak and spread of the virus, including mandates for many individuals to substantially restrict daily activities and for many businesses to curtail or cease normal operations. These mandates and restrictions have varied across jurisdictions and, over time, have been rescinded and reinstated as the severity of the pandemic fluctuated. For as long as COVID-19 continues or worsens, governments may impose additional similar restrictions or reinstate previously lifted ones. To date, our field operations have continued largely uninterrupted as the U.S. Department of Homeland Security designated our industry part of our country’s critical infrastructure. Thus far, remote work and other COVID-19 related conditions have not significantly impacted our ability to maintain operations or caused us to incur significant additional expenses; however, we are unable to predict the duration or ultimate impact of current and potential future COVID-19 mitigation measures.

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Operating Highlights

The following table summarizes certain horsepower and horsepower utilization percentages for the periods presented and excludes certain gas treating assets for which horsepower is not a relevant metric.

Year Ended December 31, Percent

Revenue generating compression units (at period end) 3,942 3,968 (0.7 %)

Average horsepower per revenue generating compression unit (6) 750 746 0.5 %

Horsepower utilization (7):

Average for the period (8) 82.7 % 86.8 % (4.7 %)

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(1)Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order). As of December 31, 2021, we had 25,000 large horsepower on order for delivery during 2022. Subsequent to December 31, 2021, we ordered an additional 50,000 large horsepower for delivery during 2022.

(2)Total available horsepower is revenue generating horsepower under contract for which we are billing a customer, horsepower in our fleet that is under contract but is not yet generating revenue, horsepower not yet in our fleet that is under contract but not yet generating revenue and that is subject to a purchase order, and idle horsepower. Total available horsepower excludes new horsepower on order for which we do not have an executed compression services contract.

(3)Revenue generating horsepower is horsepower under contract for which we are billing a customer.

(4)Calculated as the average of the month-end revenue generating horsepower for each of the months in the period.

(5)Calculated as the average of the result of dividing the contractual monthly rate, excluding standby or other temporary rates, for all units at the end of each month in the period by the sum of the revenue generating horsepower at the end of each month in the period.

(6)Calculated as the average of the month-end revenue generating horsepower per revenue generating compression unit for each of the months in the period.

(7)Horsepower utilization is calculated as (i) the sum of (a) revenue generating horsepower, (b) horsepower in our fleet that is under contract, but is not yet generating revenue and (c) horsepower not yet in our fleet that is under contract, not yet generating revenue and that is subject to a purchase order, divided by (ii) total available horsepower less idle horsepower that is under repair. Horsepower utilization based on revenue generating horsepower and fleet horsepower was 80.4% at December 31, 2021 and 2020.

(8)Calculated as the average utilization for the months in the period based on utilization at the end of each month in the period. Average horsepower utilization based on revenue generating horsepower and fleet horsepower was 79.8% and 84.5% for the years ended December 31, 2021 and 2020, respectively.

The 1.0% decrease in fleet and total available horsepower as of December 31, 2021 compared to December 31, 2020 was primarily due to the exercise of a purchase option on certain compression units by a customer during the current period as well as compression units impaired since the previous period. The exercise of this purchase option also drove a 1.1% decrease in revenue generating horsepower and a 0.7% decrease in revenue generating compression units as of December 31, 2021 compared to December 31, 2020.

The 6.0% decrease in average revenue generating horsepower for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to returns of compression units from our customers. We believe the returns of compression units from our customers were primarily due to continued optimization of existing compression service requirements by those customers.

The 0.7% decrease in average revenue per revenue generating horsepower per month for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to reduced pricing in our small horsepower fleet. The 0.5% increase in average horsepower per revenue generating compression unit was primarily due to a greater number of compression unit returns related to our small horsepower fleet than related to our large horsepower fleet.

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Horsepower utilization was consistent period over period at 82.7% as of December 31, 2021 compared to 82.8% as of December 31, 2020. Average horsepower utilization decreased to 82.7% during the year ended December 31, 2021 compared to 86.8% during the year ended December 31, 2020. The 4.7% decrease in average horsepower utilization for the year ended December 31, 2021 is primarily due to an increase in our average idle horsepower from compression units returned to us, which we believe is primarily due to continued optimization of existing compression service requirements by our customers.

Horsepower utilization based on revenue generating horsepower and fleet horsepower was consistent period over period at 80.4% as of December 31, 2021 and 2020. Average horsepower utilization based on revenue generating horsepower and fleet horsepower decreased to 79.8% for the year ended December 31, 2021 compared to 84.5% for the year ended December 31, 2020. The 5.6% decrease in average horsepower utilization based on revenue generating horsepower and fleet horsepower for the year ended December 31, 2021 is primarily due to an increase in our average idle horsepower from compression units returned to us, which we believe is primarily due to continued optimization of existing compression service requirements by our customers.

Financial Results of Operations

Year ended December 31, 2021 compared to the year ended December 31, 2020

The following table summarizes our results of operations for the periods presented (dollars in thousands):

Year Ended December 31, Percent

Revenues:

Costs and expenses:

Loss (gain) on disposition of assets (2,588) 146 *

Impairment of compression equipment 5,121 8,090 (36.7) %

Impairment of goodwill — 619,411 *

Other income (expense):

Net income (loss) before income tax expense 11,153 (593,399) *

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*Not meaningful.

Contract operations revenue. The $34.7 million decrease in contract operations revenue for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to returns of compression units from our customers, which we believe is primarily due to continued optimization of existing compression service requirements by those customers which resulted in a 6.0% decrease in average revenue generating horsepower and a 0.7% decrease in average revenue per revenue generating horsepower per month which decreased to $16.60 for the year ended December 31, 2021 compared to $16.71 for the year ended December 31, 2020. These decreases were partially offset by compression units moving from standby to full billing rate since the previous period.

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Our contract operations revenue was not materially impacted by any renegotiations of our contracts during the period with our customers. Additionally, average revenue per revenue generating horsepower per month associated with our compression services provided on a month-to-month basis did not significantly differ from the average revenue per revenue generating horsepower per month associated with our compression services provided under contracts in their primary term during the period.

Parts and service revenue. Parts and service revenue was consistent period over period and is related to maintenance work performed on units at our customers’ locations that are outside the scope of our core maintenance activities and offered as a courtesy to our customers, and freight and crane charges that are directly reimbursable by customers. Demand for retail parts and services fluctuates from period to period based on the varying needs of our customers.

Related party revenue. Related party revenue was earned through related party transactions in the ordinary course of business with various affiliated entities of Energy Transfer and was consistent period over period.

Cost of operations, exclusive of depreciation and amortization. The $11.6 million decrease in cost of operations for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to (i) an $8.0 million decrease in direct labor expenses, (ii) a $5.2 million decrease in non-income taxes, primarily due to sales tax refunds received in the current period related to prior periods, (iii) a $2.7 million decrease in direct expenses, driven by fluids and parts, and (iv) a $0.6 million decrease in training and other indirect expenses, partially offset by (v) a $3.9 million increase in outside maintenance expenses due to greater use of third-party labor during the current period and (vi) a $1.3 million increase in expenses related to our vehicle fleet, primarily due to increased fuel costs.

The decreases in direct labor, fluids and parts, training and other indirect expenses were primarily driven by the decrease in average revenue generating horsepower and reduced headcount during the current period.

Depreciation and amortization expense. The $0.2 million decrease in depreciation and amortization expense for the year ended December 31, 2021 compared to the year ended December 31, 2020 was due to a decrease in non-compression unit depreciation, driven by lower vehicle depreciation related to a reduction in our vehicle fleet in the current period, partially offset by increased compression unit depreciation related to compression unit overhauls and new compression units placed in service throughout 2020 to meet then existing demand by customers.

Selling, general and administrative expense. The $3.9 million decrease in selling, general and administrative expense for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to (i) a $6.4 million decrease in the provision for expected credit losses, (ii) a $2.4 million decrease in employee-related expenses, and (iii) a $1.9 million decrease in severance charges primarily due to the departure of one of our executives during the prior period, partially offset by (iv) a $7.1 million increase in unit-based compensation expense.

The change to the provision for expected credit losses is related to improved market conditions for customers due to the recovery in commodity prices in the current period as compared to the prior period, where we made a provision for the potential negative impact to our customers of low commodity prices driven by decreased demand due to the COVID-19 pandemic and the global oversupply of crude oil during that time. The decrease in employee-related expenses is primarily due to reduced headcount during the current period and cost saving measures. The increase in unit-based compensation expense is primarily due to the overall change in our unit price as of December 31, 2021, and the related mark-to-market change to our unit-based compensation liability.

Loss (gain) on disposition of assets. The $2.6 million gain on disposition of assets for the year ended December 31, 2021 was primarily due to the exercise of a purchase option on certain compression units by a customer.

Impairment of compression equipment. The $5.1 million and $8.1 million impairments of compression equipment during the years ended December 31, 2021 and 2020, respectively, were primarily the result of our evaluations of the future deployment of our idle fleet under current market conditions. The primary causes for these impairments were: (i) units were not considered marketable in the foreseeable future, (ii) units were subject to excessive maintenance costs or (iii) units were unlikely to be accepted by customers due to certain performance characteristics of the unit, such as the inability to meet current quoting criteria without excessive retrofitting costs. These compression units were written down to their respective estimated salvage values, if any.

As a result of our evaluations during the years ended December 31, 2021 and 2020, we determined to retire 26 and 37 compression units, respectively, with a total of approximately 11,000 and 15,000 horsepower, respectively, that had been previously used to provide compression services in our business.

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Impairment of goodwill. During the first quarter of 2020 certain potential impairment indicators were identified, specifically (i) the decline in the market price of our common units, (ii) the decline in global commodity prices, and (iii) the COVID-19 pandemic; which together indicated the fair value of the reporting unit was less than its carrying amount as of March 31, 2020. We performed a quantitative goodwill impairment test as of March 31, 2020 and determined fair value using a weighted combination of the income approach and the market approach and, as a result, recognized a goodwill impairment of $619.4 million for the year ended December 31, 2020.

Interest expense, net. The $1.2 million increase in interest expense, net for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to (i) increased borrowings under our credit agreement and (ii) increased amortization of debt issuance costs related to the amendment and restatement of our credit agreement in the current period, partially offset by (iii) lower weighted average interest rates under our credit agreement.

Average outstanding borrowings under our credit agreement were $491.5 million for the year ended December 31, 2021 compared to $455.7 million for the year ended December 31, 2020. The weighted average interest rate applicable to borrowings under our credit agreement was 2.98% for the year ended December 31, 2021 compared to 3.27% for the year ended December 31, 2020.

Income tax expense. The $0.5 million decrease in income tax expense for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily related to deferred taxes associated with the Texas Margin Tax.

Other Financial Data

The following table summarizes other financial data for the periods presented (dollars in thousands):

Year Ended December 31, Percent

Adjusted gross margin percentage (2) 69.3 % 69.2 % 0.1 %

Adjusted EBITDA percentage (2) 63.0 % 62.0 % 1.6 %

Cash Coverage Ratio 1.03 x 1.10 x (6.4) %

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(1)Adjusted gross margin, Adjusted EBITDA, DCF, DCF Coverage Ratio and Cash Coverage Ratio are all non-GAAP financial measures. Definitions of each measure, as well as reconciliations of each measure to its most directly comparable financial measure(s) calculated and presented in accordance with GAAP, can be found below under the caption “Non-GAAP Financial Measures”.

(2)Adjusted gross margin percentage and Adjusted EBITDA percentage are calculated as a percentage of revenue.

Gross margin. The $23.3 million decrease in gross margin for the year ended December 31, 2021 compared to the year ended December 31, 2020 was due to (i) a $35.0 million decrease in revenues, offset by (ii) an $11.6 million decrease in cost of operations, exclusive of depreciation and amortization and (iii) a $0.2 million decrease in depreciation and amortization.

Adjusted gross margin. The $23.5 million decrease in Adjusted gross margin for the year ended December 31, 2021 compared to the year ended December 31, 2020 was due to a $35.0 million decrease in revenues, partially offset by an $11.6 million decrease in cost of operations, exclusive of depreciation and amortization.

Adjusted EBITDA. The $15.5 million decrease in Adjusted EBITDA for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to a $23.5 million decrease in Adjusted gross margin, partially offset by a $9.0 million decrease in selling, general and administrative expenses, excluding unit-based compensation expense, severance charges and transaction expenses.

DCF. The $11.6 million decrease in DCF during the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to (i) a $23.5 million decrease in Adjusted gross margin, partially offset by (ii) a $9.0 million decrease in selling, general and administrative expenses, excluding unit-based compensation expense, severance charges and transaction expenses and (iii) a $3.8 million decrease in maintenance capital expenditures.

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Coverage Ratios. The decreases in DCF Coverage Ratio and Cash Coverage Ratio for the year ended December 31, 2021 compared to the year ended December 31, 2020 were primarily due to the decrease in DCF.

Liquidity and Capital Resources

Overview

We operate in a capital-intensive industry, and our primary liquidity needs are to finance the purchase of additional compression units and make other capital expenditures, service our debt, fund working capital, and pay distributions. Our principal sources of liquidity include cash generated by operating activities, borrowings under the Credit Agreement and issuances of debt and equity securities, including common units under the DRIP.

We typically utilize cash generated by operating activities and, where necessary, borrowings under the Credit Agreement to service our debt, fund working capital, fund our estimated expansion capital expenditures, fund our maintenance capital expenditures and pay distributions to our unitholders. Covenants in the Credit Agreement and other debt instruments require that we maintain certain leverage ratios, and if we predict that we may violate those covenants in the future we could: (i) delay discretionary capital spending and reduce operating expenses; (ii) request an amendment to the Credit Agreement; (iii) reduce or suspend distributions to our unitholders; or (iv) issue equity securities, including under the DRIP.

On December 8, 2021, the Partnership amended and restated its existing credit agreement by entering into the Credit Agreement. Please see “Revolving Credit Facility” below for additional information regarding the Credit Agreement.

Because we distribute all of our available cash, which excludes prudent operating reserves, we expect to fund any future expansion capital expenditures or acquisitions primarily with capital from external financing sources, such as borrowings under the Credit Agreement and issuances of debt and equity securities, including under the DRIP.

We are not aware of any regulatory changes or environmental liabilities that we currently expect to have a material impact on our current or future operations. Please see “Capital Expenditures” below.

Capital Expenditures

The compression services business is capital intensive, requiring significant investment to maintain, expand and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate that our capital requirements will continue to consist primarily of, the following:

•maintenance capital expenditures, which are capital expenditures made to maintain the operating capacity of our assets and extend their useful lives, to replace partially or fully depreciated assets, or other capital expenditures that are incurred in maintaining our existing business and related operating income; and

•expansion capital expenditures, which are capital expenditures made to expand the operating capacity or operating income capacity of assets, including by acquisition of compression units or through modification of existing compression units to increase their capacity, or to replace certain partially or fully depreciated assets that were not currently generating operating income.

We classify capital expenditures as maintenance or expansion on an individual asset basis. Over the long term, we expect that our maintenance capital expenditure requirements will continue to increase as the overall size and age of our fleet increases. Our aggregate maintenance capital expenditures for the years ended December 31, 2021 and 2020 were $19.5 million and $23.3 million, respectively. We currently plan to spend approximately $23.0 million in maintenance capital expenditures during 2022, including parts consumed from inventory.

Without giving effect to any equipment we may acquire pursuant to any future acquisitions, we currently have budgeted between $110.0 million and $120.0 million in expansion capital expenditures during 2022. Our expansion capital expenditures for the years ended December 31, 2021 and 2020 were $40.2 million and $95.6 million, respectively.

As of December 31, 2021, we had binding commitments to purchase $19.3 million of additional compression units and serialized parts, all of which is expected to be settled within the next twelve months. Subsequent to December 31, 2021, we ordered an additional 50,000 horsepower for delivery during 2022 which will cost an additional $43.7 million, which is also expected to be settled within the next twelve months.

Other Commitments

As of December 31, 2021, other commitments include operating and finance lease payments totaling $27.4 million, of which we expect to make payments of $4.8 million to be settled in the next twelve months. For a more detailed description of

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our lease obligations, please refer to Note 7 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.

Cash Flows

The following table summarizes our sources and uses of cash for the years ended December 31, 2021 and 2020 (in thousands):

Year Ended December 31,

Net cash provided by operating activities $ 265,425 $ 293,198

Net cash used in investing activities (39,188) (105,099)

Net cash provided by operating activities. The $27.8 million decrease in net cash provided by operating activities for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to a $18.8 million decrease in net income, as adjusted for non-cash items, and changes in other working capital.

Net cash used in investing activities. The $65.9 million decrease in net cash used in investing activities for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to a $63.9 million decrease in capital expenditures for purchases of new compression units, related equipment and reconfiguration costs and a $1.8 million increase in proceeds from disposition of property and equipment.

Net cash used in financing activities. The $38.1 million increase in net cash used in financing activities for the year ended December 31, 2021 compared to the year ended December 31, 2020 was primarily due to (i) a $28.6 million decrease in net borrowings under our credit agreement, (ii) a $6.1 million increase in financing costs, due primarily to costs incurred related to the amendment and restatement of our credit agreement in the current period, (iii) a $2.0 million increase in cash paid related to the net settlement of unit-based awards and (iv) a $1.7 million increase in cash distributions paid on common units solely due to increased unit count.

Revolving Credit Facility

As of December 31, 2021, we were in compliance with all of our covenants under the Credit Agreement. As of December 31, 2021, we had outstanding borrowings under the Credit Agreement of $516.3 million, $1.1 billion of borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of $261.9 million.

As of February 10, 2022, we had outstanding borrowings under the Credit Agreement of $549.9 million.

On December 8, 2021, the Partnership amended and restated its existing credit agreement by entering into the Credit Agreement. The Credit Agreement matures on December 8, 2026, except that if any portion of the Senior Notes 2026 are outstanding on December 31, 2025, the Credit Agreement will mature on December 31, 2025.

The Credit Agreement provides for an asset-based revolving credit facility to be made available to the Partnership in an aggregate amount of $1.6 billion. The Partnership’s obligations under the Credit Agreement are guaranteed by the Guarantors, which currently consists of all of the Partnership’s existing subsidiaries. In addition, the Partnership’s obligations under the Credit Agreement are secured by: (i) substantially all of the Partnership’s assets and substantially all of the assets of the Guarantors, excluding real property and other customary exclusions; and (ii) all of the equity interests of the Partnership’s U.S. restricted subsidiaries (subject to customary exceptions).

Borrowings under the Credit Agreement bear interest at a per annum interest rate equal to, at the Partnership’s option, either the Alternate Base Rate or SOFR plus the applicable margin. “Alternate Base Rate” means the greatest of (i) the prime rate, (ii) the applicable federal funds effective rate plus 0.50% and (iii) one-month SOFR rate plus 1.00%. The applicable margin for borrowings varies (a) in the case of SOFR loans, from 2.00% to 2.75% per annum and (b) in the case of Base Rate loans, from 1.00% to 1.75% per annum, and are determined based on a total leverage ratio pricing grid. In addition, the Borrower is required to pay commitment fees based on the daily unused amount of the Credit Agreement in an amount per annum equal to 0.375%. Amounts borrowed and repaid under the Credit Agreement may be re-borrowed, subject to borrowing base availability.

The Credit Agreement contains various covenants with which the Partnership and its restricted subsidiaries must comply, including, but not limited to, limitations on the incurrence of indebtedness, investments, liens on assets, repurchasing equity and making distributions, transactions with affiliates, mergers, consolidations, dispositions of assets and other provisions customary

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in similar types of agreements. The Partnership must also maintain, on a consolidated basis, as of the last day of each fiscal quarter a Total Leverage Ratio (as defined in the Credit Agreement) of not greater than 5.75 to 1.00 through the second fiscal quarter of 2022; 5.50 to 1.00 from the third fiscal quarter of 2022 through the third fiscal quarter of 2023; and 5.25 to 1.00 thereafter (except that the Partnership may increase the applicable Total Leverage Ratio by 0.25 for any fiscal quarter during which a Specified Acquisition (as defined in the Credit Agreement) occurs and the following two fiscal quarters, but in no event shall the maximum Total Leverage Ratio exceed 5.50 to 1.00 for any fiscal quarter as a result of such increase), an Interest Coverage Ratio (as defined in the Credit Agreement) of not less than 2.50 to 1.00 and a Secured Leverage Ratio (as defined in the Credit Agreement) of not greater than 3.00 to 1.00 or less than 0.00 to 1.00. The Credit Agreement also contains various customary representations and warranties, affirmative covenants and events of default.

We expect to remain in compliance with our covenants under the Credit Agreement throughout 2022. If our current cash flow projections prove to be inaccurate, we expect to be able to remain in compliance with such financial covenants by taking one or more of the following actions: issue debt and equity securities in conjunction with the acquisition of another business; issue equity in a public or private offering; request a modification of our covenants from our bank group; reduce distributions from our current distribution rate or obtain an equity infusion pursuant to the terms of the Credit Agreement.

For a more detailed description of the Credit Agreement including the covenants and restrictions contained therein, please refer to Note 9 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.

Senior Notes

As of December 31, 2021, we had $725.0 million and $750.0 million aggregate principal amount outstanding on our Senior Notes 2026 and Senior Notes 2027, respectively.

The Senior Notes 2026 are due on April 1, 2026 and accrue interest at the rate of 6.875% per year. Interest on the Senior Notes 2026 is payable semi-annually in arrears on each of April 1 and October 1.

The Senior Notes 2027 are due on September 1, 2027 and accrue interest at the rate of 6.875% per year. Interest on the Senior Notes 2027 is payable semi-annually in arrears on each of March 1 and September 1.

For more detailed descriptions of the Senior Notes 2026 and Senior Notes 2027, please refer to Note 9 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.

DRIP

During the years ended December 31, 2021 and 2020, distributions of $1.8 million and $1.9 million, respectively, were reinvested under the DRIP resulting in the issuance of 118,399 and 188,695 common units, respectively.

Such distributions are treated as non-cash transactions in the accompanying Consolidated Statements of Cash Flows included in Part II, Item 8 “Financial Statements and Supplementary Data” of this report.

See Note 11 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for more information regarding the DRIP.

Non-GAAP Financial Measures

Adjusted Gross Margin

Adjusted gross margin is a non-GAAP financial measure. We define Adjusted gross margin as revenue less cost of operations, exclusive of depreciation and amortization expense. We believe that Adjusted gross margin is useful as a supplemental measure to investors of our operating profitability. Adjusted gross margin is impacted primarily by the pricing trends for service operations and cost of operations, including labor rates for service technicians, volume and per unit costs for lubricant oils, quantity and pricing of routine preventative maintenance on compression units and property tax rates on compression units. Adjusted gross margin should not be considered an alternative to, or more meaningful than, gross margin or any other measure of financial performance presented in accordance with GAAP. Moreover, Adjusted gross margin as presented may not be comparable to similarly titled measures of other companies. Because we capitalize assets, depreciation and amortization of equipment is a necessary element of our costs. To compensate for the limitations of Adjusted gross margin as a measure of our performance, we believe that it is important to consider gross margin determined under GAAP, as well as Adjusted gross margin, to evaluate our operating profitability.

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The following table reconciles Adjusted gross margin to gross margin, its most directly comparable GAAP financial measure, for each of the periods presented (in thousands):

Year Ended December 31,

Adjusted EBITDA

We define EBITDA as net income (loss) before net interest expense, depreciation and amortization expense, and income tax expense (benefit). We define Adjusted EBITDA as EBITDA plus impairment of compression equipment, impairment of goodwill, interest income on capital lease, unit-based compensation expense, severance charges, certain transaction expenses, loss (gain) on disposition of assets and other. We view Adjusted EBITDA as one of management’s primary tools for evaluating our results of operations, and we track this item on a monthly basis both as an absolute amount and as a percentage of revenue compared to the prior month, year-to-date, prior year and budget. Adjusted EBITDA is used as a supplemental financial measure by our management and external users of our financial statements, such as investors and commercial banks, to assess:

•the financial performance of our assets without regard to the impact of financing methods, capital structure or historical cost basis of our assets;

•the viability of capital expenditure projects and the overall rates of return on alternative investment opportunities;

•the ability of our assets to generate cash sufficient to make debt payments and to pay distributions; and

•our operating performance as compared to those of other companies in our industry without regard to the impact of financing methods and capital structure.

We believe that Adjusted EBITDA provides useful information to investors because, when viewed with our GAAP results and the accompanying reconciliations, it may provide a more complete understanding of our performance than GAAP results alone. We also believe that external users of our financial statements benefit from having access to the same financial measures that management uses in evaluating the results of our business.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP as measures of operating performance and liquidity. Moreover, our Adjusted EBITDA as presented may not be comparable to similarly titled measures of other companies.

Because we use capital assets, depreciation, impairment of compression equipment, loss (gain) on disposition of assets and the interest cost of acquiring compression equipment are also necessary elements of our costs. Unit-based compensation expense related to equity awards to employees is also a necessary component of our business. Therefore, measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income (loss) and net cash provided by operating activities determined under GAAP, as well as Adjusted EBITDA, to evaluate our financial performance and our liquidity. Our Adjusted EBITDA excludes some, but not all, items that affect net income (loss) and net cash provided by operating activities, and these measures may vary among companies. Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating this knowledge into their decision making processes.

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The following table reconciles Adjusted EBITDA to net income (loss) and net cash provided by operating activities, its most directly comparable GAAP financial measures, for each of the periods presented (in thousands):

Year Ended December 31,

Interest income on capital lease 48 383

Transaction expenses (2) 34 136

Loss (gain) on disposition of assets (2,588) 146

Impairment of compression equipment (3) 5,121 8,090

Impairment of goodwill (4) — 619,411

Interest income on capital lease (48) (383)

Transaction expenses (34) (136)

Changes in operating assets and liabilities (8,702) 283

Net cash provided by operating activities $ 265,425 $ 293,198

________________________

(1)For the years ended December 31, 2021 and2020, unit-based compensation expense included $4.2 million and $3.2 millionof cash payments related to quarterly payments of DERs on outstanding phantom unit awards, respectively, and $0.3 million and $0.5 million related to the cash portion of any settlement of phantom unit awards upon vesting, respectively. The remainder of the unit-based compensation expense for all periods was related to non-cash adjustments to the unit-based compensation liability.

(2)Represents certain expenses related to potential and completed transactions and other items. We believe it is useful to investors to exclude these expenses.

(3)Represents non-cash charges incurred to write down long-lived assets with recorded values that are not expected to be recovered through future cash flows.

(4)For further discussion on our goodwill impairment recorded for the year ended December 31, 2020, see below under the caption “Critical Accounting Estimates – Goodwill – Impairment Assessments”.

Distributable Cash Flow

We define DCF as net income (loss) plus non-cash interest expense, non-cash income tax expense (benefit), depreciation and amortization expense, unit-based compensation expense, impairment of compression equipment, impairment of goodwill, certain transaction expenses, severance charges, loss (gain) on disposition of assets, proceeds from insurance recovery and other, less distributions on Preferred Units and maintenance capital expenditures.

We believe DCF is an important measure of operating performance because it allows management, investors and others to compare basic cash flows we generate (after distributions on the Preferred Units but prior to any retained cash reserves established by the General Partner and the effect of the DRIP) to the cash distributions we expect to pay our common unitholders. Using DCF, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions.

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DCF should not be considered an alternative to, or more meaningful than, net income (loss), operating income (loss), cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP as measures of operating performance and liquidity. Moreover, our DCF as presented may not be comparable to similarly titled measures of other companies.

Because we use capital assets, depreciation, impairment of compression equipment, loss (gain) on disposition of assets, the interest cost of acquiring compression equipment and maintenance capital expenditures are necessary elements of our costs. Unit-based compensation expense related to equity awards to employees is also a necessary component of our business. Therefore, measures that exclude these elements have material limitations. To compensate for these limitations, we believe that it is important to consider both net income (loss) and net cash provided by operating activities determined under GAAP, as well as DCF, to evaluate our financial performance and our liquidity. Our DCF excludes some, but not all, items that affect net income (loss) and net cash provided by operating activities, and these measures may vary among companies. Management compensates for the limitations of DCF as an analytical tool by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating this knowledge into their decision making processes.

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The following table reconciles DCF to net income (loss) and net cash provided by operating activities, its most directly comparable GAAP financial measures, for each of the periods presented (in thousands):

Year Ended December 31,

Non-cash income tax expense (benefit) (42) 530

Transaction expenses (2) 34 136

Loss (gain) on disposition of assets (2,588) 146

Impairment of compression equipment (3) 5,121 8,090

Impairment of goodwill (4) — 619,411

Proceeds from insurance recovery — 336

Transaction expenses (34) (136)

Changes in operating assets and liabilities (8,702) 283

Net cash provided by operating activities $ 265,425 $ 293,198

________________________

(1)For the years ended December 31, 2021 and2020, unit-based compensation expense included $4.2 million and $3.2 million of cash payments related to quarterly payments of DERs on outstanding phantom unit awards, respectively, and $0.3 million and $0.5 million related to the cash portion of any settlement of phantom unit awards upon vesting, respectively. The remainder of the unit-based compensation expense for all periods was related to non-cash adjustments to the unit-based compensation liability.

(2)Represents certain expenses related to potential and completed transactions and other items. We believe it is useful to investors to exclude these expenses.

(3)Represents non-cash charges incurred to write down long-lived assets with recorded values that are not expected to be recovered through future cash flows.

(4)For further discussion on our goodwill impairment recorded for the year ended December 31, 2020, see below under the caption “Critical Accounting Estimates – Goodwill – Impairment Assessments”.

(5)Reflects actual maintenance capital expenditures for the period presented. Maintenance capital expenditures are capital expenditures made to maintain the operating capacity of our assets and extend their useful lives, replace partially or fully depreciated assets, or other capital expenditures that are incurred in maintaining our existing business and related cash flow.

Coverage Ratios

DCF Coverage Ratio is defined as DCF divided by distributions declared to common unitholders in respect of such period. Cash Coverage Ratio is defined as DCF divided by cash distributions expected to be paid to common unitholders in respect of such period, after taking into account the non-cash impact of the DRIP. We believe DCF Coverage Ratio and Cash Coverage Ratio are important measures of operating performance because they allow management, investors and others to gauge our ability to pay cash distributions to common unitholders using the cash flows that we generate. Our DCF Coverage Ratio and Cash Coverage Ratio as presented may not be comparable to similarly titled measures of other companies.

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The following table summarizes certain coverage ratios for the periods presented (dollars in thousands):

Year Ended December 31,

Distributions reinvested in the DRIP (2) $ 1,828 $ 2,064

DCF Coverage Ratio 1.03 x 1.09 x

Cash Coverage Ratio 1.03 x 1.10 x

________________________

(1)Represents distributions to the holders of our common units as of the record date.

(2)Represents distributions to holders enrolled in the DRIP as of the record date.

(3)Represents cash distributions declared for common units not participating in the DRIP.

Critical Accounting Estimates

The discussion and analysis of our financial condition and results of operations is based upon our financial statements. These financial statements were prepared in conformity with GAAP. As such, we are required to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenue and expenses during the periods presented. We base our estimates on historical experience, available information and various other assumptions we believe to be reasonable under the circumstances. On an ongoing basis, we evaluate our estimates; however, actual results may differ from these estimates under different assumptions or conditions. The accounting estimates that we believe require management’s most difficult, subjective or complex judgments and are the most critical to its reporting of results of operations and financial position are as follows:

Business Combinations and Goodwill

Goodwill acquired in connection with business combinations represents the excess of consideration over the fair value of net assets acquired. Certain assumptions and estimates are employed in determining the fair value of assets acquired and liabilities assumed. Goodwill is not amortized, but is reviewed for impairment annually based on the carrying values as of October 1, or more frequently if impairment indicators arise that suggest the carrying value of goodwill may not be recovered.

Goodwill – Impairment Assessments

We evaluate goodwill for impairment annually on October 1 and whenever events or changes indicate that it is more likely than not that the fair value of our single business reporting unit could be less than its carrying value (including goodwill).

We estimate the fair value of our reporting unit based on a number of factors, including the potential value we would receive if we sold the reporting unit, enterprise value, discount rates and projected cash flows. Estimating projected cash flows requires us to make certain assumptions as it relates to future operating performance. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. Due to the imprecise nature of these projections and assumptions, actual results can, and often do, differ from our estimates.

During the first quarter of 2020 certain potential impairment indicators were identified, specifically (i) the decline in the market price of our common units, (ii) the decline in global commodity prices and (iii) the COVID-19 pandemic; which together indicated the fair value of the reporting unit was less than its carrying amount as of March 31, 2020.

We performed a quantitative goodwill impairment test as of March 31, 2020 and determined fair value using a weighted combination of the income approach and the market approach. Determining fair value of a reporting unit requires judgment and use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, EBITDA margins,

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weighted average costs of capital and future market conditions, among others. We believe the estimates and assumptions used were reasonable and based on available market information, but variations in any of the assumptions could have resulted in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the income approach, we determined fair value based on estimated future cash flows, including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflects the overall level of inherent risk of the Partnership. Cash flow projections were derived from four-year operating forecasts plus an estimate of later period cash flows, all of which were developed by management. Subsequent period cash flows were developed using growth rates that management believed were reasonably likely to occur. Under the market approach, we determined fair value by applying valuation multiples of comparable publicly-traded companies to the projected EBITDA of the Partnership and then averaging that estimate with similar historical calculations using a three-year average. In addition, we estimated a reasonable control premium representing the incremental value that would accrue to us if we were to be acquired.

Based on the quantitative goodwill impairment test described above, our carrying amount exceeded fair value and as a result, we recognized a goodwill impairment of $619.4 million for the year ended December 31, 2020.

Long-Lived Assets

Long-lived assets, which include property and equipment, and intangible assets, comprise a significant amount of our total assets. Long-lived assets to be held and used by us are reviewed to determine whether any events or changes in circumstances indicate the carrying amount of the asset may not be recoverable. For long-lived assets to be held and used, we base our evaluation on impairment indicators such as the nature of the assets, the future economic benefit of the assets, the consistency of performance characteristics of compression units in our idle fleet with the performance characteristics of our revenue generating horsepower, any historical or future profitability measurements and other external market conditions or factors that may be present. If such impairment indicators are present or other factors exist that indicate the carrying amount of the asset may not be recoverable, we determine whether an impairment has occurred through the use of an undiscounted cash flows analysis. If an impairment has occurred, we recognize a loss for the difference between the carrying amount and the estimated fair value of the asset. The fair value of the asset is measured using quoted market prices or, in the absence of quoted market prices, is based on an estimate of discounted cash flows, the expected net sale proceeds compared to other similarly configured fleet units we recently sold, a review of other units recently offered for sale by third parties, or the estimated component value of similar equipment we plan to continue to use.

Potential events or circumstances that could reasonably be expected to negatively affect the key assumptions we used in estimating whether or not the carrying value of our long-lived assets are recoverable include the consolidation or failure of crude oil and natural gas producers, which may result in a smaller market for services and may cause us to lose key customers, and cost-cutting efforts by crude oil and natural gas producers, which may cause us to lose current or potential customers or achieve less revenue per customer. If our projections of cash flows associated with our units decline, we may have to record an impairment of compression equipment in future periods.

For the years ended December 31, 2021 and 2020, we evaluated the future deployment of our idle fleet under current market conditions and determined to retire 26 and 37 compressor units, respectively, for a total of approximately 11,000 and 15,000 horsepower, respectively, that were previously used to provide compression services in our business. As a result, we recorded impairments of compression equipment of $5.1 million and $8.1 million for the years ended December 31, 2021 and 2020, respectively. The primary causes for these impairments were: (i) units were not considered marketable in the foreseeable future, (ii) units were subject to excessive maintenance costs or (iii) units were unlikely to be accepted by customers due to certain performance characteristics of the unit, such as the inability to meet current quoting criteria without excessive retrofitting costs. These compression units were written down to their respective estimated salvage values, if any.

Estimated Useful Lives of Property, Plant and Equipment

Property, plant and equipment is carried at cost. Depreciation is computed on a straight-line basis using useful lives that are estimated based on assumptions and judgments that reflect both historical experience and expectations regarding future use of our assets. The use of different assumptions and judgments in the calculation of depreciation, especially those involving useful lives, would likely result in significantly different net book values of our assets and results of operations.

Commitments and Contingencies

From time to time, we and our subsidiaries may be involved in various claims and litigation arising in the ordinary course of business. Additionally, our compliance with state and local sales tax regulations is subject to audit by various taxing authorities. Certain taxing authorities have either claimed or issued an assessment that specific operational processes, which we and others in our industry regularly conduct, result in transactions that are subject to state sales taxes. We and others in our

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industry have disputed these claims and assessments based on either existing tax statutes or published guidance by the taxing authorities.

We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. While we are unable to predict the ultimate outcome of these actions, the accounting standard for contingencies requires management to make judgments about future events that are inherently uncertain. We are required to record a loss during any period in which we believe a contingency is probable and can be reasonably estimated. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. We expense legal costs as incurred, and all recorded legal liabilities are revised, as required, as better information becomes available to us.

We are currently protesting certain assessments made by the Oklahoma Tax Commission (“OTC”). We believe it is reasonably possible that we could incur losses related to this assessment depending on whether the administrative law judge assigned by the OTC accepts our position that the transactions are not taxable and we ultimately lose any and all subsequent legal challenges to such determination. We estimate that the range of losses we could incur is from $0 to approximately $19.5 million, including penalty and interest.

As of December 31, 2021 and 2020, we have recorded a $44.9 million accrued liability and $44.9 million related party receivable from Energy Transfer related to open audits with the Office of the Texas Comptroller of Public Accounts (the “Comptroller”), wherein the Comptroller has challenged the applicability of the manufacturing exemption.

Allowance for Credit Losses

We maintain an allowance for credit losses for our two financial assets, (i) trade accounts receivable and (ii) net investment in lease related to our sales-type lease, based on specific customer collection issues and historical experience.

Our determination of the allowance for credit losses requires us to make estimates and judgments regarding our customers’ ability to pay amounts due. We continuously evaluate the financial strength of our customers and the overall business climate in which our customers operate, and make adjustments to the allowance for credit losses as necessary. We evaluate the financial strength of our customers by reviewing the aging of their receivables, our collection experience with the customer, correspondence, financial information and third-party credit ratings. We evaluate the business climate in which our customers operate by reviewing various publicly available materials regarding our customers’ industry, including the solvency of various companies in the industry.

For the year ended December 31, 2021, we recognized a reversal of $2.7 million of our provision for expected credit losses. Improved market conditions for customers due to the recovery in commodity prices was the primary factor contributing to the decrease to the allowance for credit losses for the year ended December 31, 2021.

For the year ended December 31, 2020, we recognized a $3.7 million provision for expected credit losses. Low commodity prices, driven by decreased demand for and global oversupply of crude oil as a result of the COVID-19 pandemic, was the primary factor contributing to the higher allowance for credit losses for the year ended December 31, 2020.

Recent Accounting Pronouncements

Please see Part II, Item 8 “Financial Statements and Supplementary Data”, Note 17 for other specific recent accounting pronouncements affecting us.

ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. We do not take title to any natural gas or crude oil in connection with our services and, accordingly, have no direct exposure to fluctuating commodity prices. However, the demand for our compression services depends upon the continued demand for, and production of, natural gas and crude oil. Sustained low natural gas or crude oil prices over the long term could result in a decline in the production of natural gas or crude oil, which could result in reduced demand for our compression services. We do not intend to hedge our indirect exposure to fluctuating commodity prices. A one percent decrease in average revenue generating horsepower during the year ended December 31, 2021 would have resulted in a decrease of approximately $5.9 million and $4.0 million in our revenue and Adjusted gross margin, respectively. Adjusted gross margin is a non-GAAP financial measure. For a reconciliation of Adjusted gross margin to gross margin, its most directly comparable financial measure, calculated and presented in accordance with GAAP, please read Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Non-GAAP Financial Measures”. Please also read Part I, Item 1A “Risk Factors – Risks Related to Our Business – An

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extended reduction in the demand for, or production of, natural gas or crude oil could adversely affect the demand for our services or the prices we charge for our services, which could result in a decrease in our revenues and cash available for distribution to unitholders.”

Interest Rate Risk

We are exposed to market risk due to variable interest rates under our Credit Agreement.

As of December 31, 2021, we had $516.3 million of variable-rate outstanding indebtedness at a weighted-average interest rate of 2.68%. A one percent increase or decrease in the effective interest rate on our variable-rate outstanding debt as of December 31, 2021 would result in an annual increase or decrease in our interest expense of approximately $5.2 million.

For further information regarding our exposure to interest rate fluctuations on our debt obligations, see Note 9 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”. Although we do not currently hedge our variable rate debt, we may, in the future, hedge all or a portion of such debt.

Credit Risk

Our credit exposure generally relates to receivables for services provided. If any significant customer of ours should have credit or financial problems resulting in a delay or failure to pay the amount it owes us, it could have a material adverse effect on our business, financial condition, results of operations and cash flows. Please see Part II, Item 1A. “Risk Factors – Risk Related to Our Business – We are exposed to counterparty credit risk. Nonpayment and nonperformance by our customers, suppliers or vendors could reduce our revenues, increase our expenses and otherwise have a negative impact on our ability to conduct our business, operating results, cash flows and ability to make distributions to our unitholders.”

ITEM 8. Financial Statements and Supplementary Data

The financial statements and supplementary information specified by this Item are presented in Part IV, Item 15 “Exhibits and Financial Statement Schedules”.

ITEM 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

ITEM 9A. Controls and Procedures

Disclosure Controls and Procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures, and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of December 31, 2021 at the reasonable assurance level.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting for us. Our internal control system was designed to provide reasonable assurance regarding the preparation and fair presentation of our published financial statements.

There are inherent limitations to the effectiveness of any control system, however well designed, including the possibility of human error and the possible circumvention or overriding of controls. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Management must make judgments with respect to the relative cost and expected benefits of any specific control measure. The design of a control system also is based in part upon assumptions and judgments made by management about the likelihood of future events, and there can be no assurance that a control will be effective under all potential future conditions. As a result, even an effective system of internal control over financial reporting can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared.

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Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2021. In making this assessment, management used the criteria set forth by the 2013 Committee of Sponsoring Organizations of the Treadway Commission in Internal Control – Integrated Framework. Based on this assessment, our management believes that, as of December 31, 2021, our internal control over financial reporting was effective. Grant Thornton LLP, an independent registered public accounting firm that audited our consolidated financial statements included herein, has also audited the effectiveness of our internal control over financial reporting as of December 31, 2021, as stated in their report, which is included herein.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors of USA Compression GP, LLC and

Unitholders of USA Compression Partners, LP

Opinion on internal control over financial reporting

We have audited the internal control over financial reporting of USA Compression Partners, LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 2021, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Partnership as of and for the year ended December 31, 2021, and our report dated February 15, 2022 expressed an unqualified opinion on those financial statements.

Basis for opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and limitations of internal control over financial reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

/s/ GRANT THORNTON LLP

Houston, Texas

February 15, 2022

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Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the last fiscal quarter that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. Other Information

None.

ITEM 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

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PART III

ITEM 10. Directors, Executive Officers and Corporate Governance

Board of Directors

Our general partner, USA Compression GP, LLC (the “General Partner”), manages our operations and activities. The General Partner is wholly owned by Energy Transfer LP (“Energy Transfer”). The General Partner has a board of directors (the “Board”) that manages our business. The Board is not elected by our unitholders and is not subject to re-election on a regular basis in the future. As the sole member of the General Partner, Energy Transfer is entitled under the limited liability company agreement of the General Partner (the “GP LLC Agreement”) to appoint all directors of the General Partner, subject to rights and restrictions contained in other agreements. The GP LLC Agreement provides that the Board shall consist of between two and eleven persons.

The Board is comprised of ten members, nine of whom were designated by Energy Transfer and one of whom was designated by EIG Management Company, LLC (“EIG Management”) pursuant to that certain Board Representation Agreement (the “Board Representation Agreement”) among us, the General Partner, Energy Transfer and EIG Veteran Equity Aggregator, L.P. (along with its affiliated funds, “EIG”) entered into on April 2, 2018 (the “Transactions Date”) in connection with our private placement to EIG and FS Energy and Power Fund (“FS Energy”) of Preferred Units and warrants to purchase common units of the Partnership (the “Warrants”). Under the Board Representation Agreement, EIG Management has the right to designate one member of the Board for so long as EIG and FS Energy own, in the aggregate, more than 5% of the Partnership’s outstanding common units (taking into account the common units issuable upon conversion of the Preferred Units and exercise of the Warrants). EIG Management has designated Matthew S. Hartman to serve on the Board. Four members of the Board are independent as defined under the independence standards established by the NYSE and the SEC. Although the NYSE does not require a publicly traded limited partnership like us to have a majority of independent directors on the Board or to establish a compensation committee or a nominating committee, the Board has elected to have a standing compensation committee (the “Compensation Committee”). We do not have a nominating committee in light of the fact that Energy Transfer and EIG currently collectively appoint all of the members of the Board.

Eric D. Long, our President and Chief Executive Officer (“CEO”), is currently the only management member of the Board. The non-management members of the Board meet in executive session without any members of management present at least twice a year. Mr. William S. Waldheim presides at such meetings. Interested parties can communicate directly with non-management members of the Board by mail in care of the General Counsel and Secretary at USA Compression Partners, LP, 111 Congress Avenue, Suite 2400, Austin, Texas 78701. Such communications should specify the intended recipient or recipients. Commercial solicitations or similar communications will not be forwarded to the Board.

As a limited partnership, NYSE rules do not require us to seek unitholder approval for the election of any of our directors. We do not have a formal process for identifying director nominees, nor do we have a formal policy regarding consideration of diversity in identifying director nominees. We believe, however, that the individuals appointed as directors have experience, skills and qualifications relevant to our business and have a history of service in senior leadership positions with the qualities and attributes required to provide effective oversight of the Partnership.

Independent Directors. The Board has determined that Matthew S. Hartman, Glenn E. Joyce, W. Brett Smith and William S. Waldheim are independent directors under the standards established by the NYSE and the Exchange Act. The Board considered all relevant facts and circumstances and applied the independence guidelines of the NYSE and the Exchange Act in determining that none of these directors has any material relationship with us, our management, the General Partner or its affiliates or our subsidiaries.

Mr. Hartman is a Managing Director at EIG, and, since the Transactions Date, EIG owns over 80% of the Preferred Units and Warrants in the Partnership. The Board determined that EIG’s ownership of Preferred Units and Warrants did not preclude the independence of Mr. Hartman because (i) the Preferred Units and Warrants do not confer voting rights sufficient to participate in the control of the Partnership or influence its management, (ii) the Board Representation Agreement does not grant to EIG a sufficient number of seats on the Board to significantly influence or control its decision making or materially influence the management or operation of the Partnership and (iii) the Board has determined that ownership of even a significant amount of the Partnership’s securities does not, by itself, preclude a finding of independence.

Mr. Smith is President of, and owns limited partnership interests in, Promontory Exploration, LP, Rubicon Oil & Gas II LP and Quientesa Royalty LP, which entities own non-operating working or royalty interests in wells and receive proceeds from liquids production purchased by a subsidiary of Energy Transfer under agreements with well operators. The Board determined that Mr. Smith’s association with these entities did not preclude the independence of Mr. Smith.

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The Board’s Role in Risk Oversight

The Board administers its risk oversight function as a whole and through its committees. It does so in part through discussion and review of our business, financial reporting and corporate governance policies, procedures and practices, with opportunity to make specific inquiries of management. In addition, at each regular meeting of the Board, management provides a report of the Partnership’s operational and financial performance, which often prompts questions and feedback from the Board. The audit committee of the Board (the “Audit Committee”) provides additional risk oversight through its quarterly meetings, where it discusses policies with respect to risk assessment and risk management, reviews contingent liabilities and risks that may be material to the Partnership and assesses major legislative and regulatory developments that could materially impact the Partnership’s contingent liabilities and risks. The Audit Committee is also required to discuss any material violations of our policies brought to its attention on an ad hoc basis. Additionally, the Compensation Committee reviews our overall compensation program and its effectiveness at both linking executive pay to performance and aligning the interests of our executives and our unitholders.

Committees of the Board of Directors

Audit Committee. The Board appoints the Audit Committee, which is comprised solely of directors who meet the independence and experience standards established by the NYSE and the Exchange Act. The Audit Committee consists of Messrs. Hartman, Joyce, Smith and Waldheim, and Mr. Waldheim serves as chairman of the Audit Committee. The Board determined that Mr. Waldheim is an “audit committee financial expert” as defined in Item 407(d)(5)(ii) of SEC Regulation S-K, and that each of Messrs. Hartman, Joyce, Smith and Waldheim is “independent” within the meaning of the applicable NYSE and Exchange Act rules governing audit committee independence. The Audit Committee assists the Board in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements as well as the effectiveness of our corporate policies and internal controls. The Audit Committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The Audit Committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the Audit Committee.

The charter of the Audit Committee (the “Audit Committee Charter”) is available under the Investor Relations tab on our website at usacompression.com. We will provide a copy of the Audit Committee Charter to any of our unitholders without charge upon written request to Investor Relations, 111 Congress Avenue, Suite 2400, Austin, TX 78701.

Compensation Committee. The NYSE does not require a listed limited partnership like us to have a compensation committee. However, the Board established the Compensation Committee to, among other things, oversee our compensation program described below in Part III, Item 11 “Executive Compensation.” The Compensation Committee consists of Messrs. Joyce, Smith and Waldheim and is chaired by Mr. Joyce. The Compensation Committee establishes and reviews general policies related to our compensation and benefits and is responsible for making recommendations to the Board with respect to the compensation and benefits of the Board. In addition, the Compensation Committee administers the USA Compression Partners, LP 2013 Long-Term Incentive Plan, as amended and as may be further amended or replaced from time to time (the “LTIP”).

Under the charter of the Compensation Committee (the “Compensation Committee Charter”), a director serving as a member of the Compensation Committee may not be an officer of or employed by the General Partner, us or our subsidiaries. During 2021, none of Mr. Joyce, Mr. Smith or Mr. Waldheim was an officer or employee of Energy Transfer or any of its affiliates, or served as an officer of any company with respect to which any of our executive officers served on such company’s board of directors. In addition, none of Mr. Joyce, Mr. Smith or Mr. Waldheim is a former employee of Energy Transfer or any of its affiliates.

The Compensation Committee Charter is available under the Investor Relations tab on our website at usacompression.com. We will provide a copy of the Compensation Committee Charter to any of our unitholders without charge upon written request to Investor Relations, 111 Congress Avenue, Suite 2400, Austin, TX 78701.

Conflicts Committee. As set forth in the GP LLC Agreement, the General Partner may, from time to time, establish a conflicts committee to which the Board will appoint independent directors and which may be asked to review specific matters that the Board believes may involve conflicts of interest between us, our limited partners and Energy Transfer. Such conflicts committee will determine the resolution of the conflict of interest in any matter referred to it in good faith. The members of the conflicts committee may not be officers or employees of the General Partner or directors, officers or employees of its affiliates, including Energy Transfer, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on the Audit Committee, and certain other requirements. Any matters approved by the conflicts

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committee in good faith will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by the General Partner of any duties it may owe us or our unitholders.

Corporate Governance Guidelines and Code of Ethics

The Board has adopted Corporate Governance Guidelines (the “Guidelines”) that outline important policies and practices regarding our governance and provide a framework for the function of the Board and its committees. The Board has also adopted a Code of Business Conduct and Ethics (the “Code”) that applies to the General Partner and its subsidiaries and affiliates, including us, and to all of its and their directors, employees and officers, including its principal executive officer, principal financial officer and principal accounting officer. We intend to post any amendments to the Code, or waivers of its provisions applicable to our directors or executive officers, including our principal executive officer and principal financial officer, on our website. The Guidelines and the Code are available under the Investor Relations tab on our website at usacompression.com. We will provide copies of the Guidelines and the Code to any of our unitholders without charge upon written request to Investor Relations, 111 Congress Avenue, Suite 2400, Austin, TX 78701.

Note that the preceding internet addresses are for informational purposes only and are not intended to be hyperlinked. Accordingly, no information found on or provided at those internet addresses or on our website in general is intended or deemed to be incorporated by reference herein.

Directors and Executive Officers

The following table shows information as of February 10, 2022 regarding the current directors and executive officers of USA Compression GP, LLC.

Name Age Position with USA Compression GP, LLC

Eric D. Long 63 President and Chief Executive Officer and Director

Matthew C. Liuzzi 47 Vice President, Chief Financial Officer and Treasurer

Eric Scheller 58 Vice President and Chief Operating Officer

Christopher W. Porter 38 Vice President, General Counsel and Secretary

Sean T. Kimble 57 Vice President, Human Resources

Christopher R. Curia 66 Director

Matthew S. Hartman 41 Director

Glenn E. Joyce 64 Director

Thomas E. Long 65 Director

Thomas P. Mason 65 Director

Matthew S. Ramsey 66 Director

W. Brett Smith 62 Director

William S. Waldheim 65 Director

Bradford D. Whitehurst 47 Director

The directors of the General Partner hold office until the earlier of their death, resignation, removal or disqualification or until their successors have been elected and qualified. Officers serve at the discretion of the Board. There are no family relationships among any of the directors or executive officers of the General Partner.

Eric D. Long has served as our President and CEO since September 2002 and has served as a director of the General Partner since June 2011. Mr. Long co-founded USA Compression in 1998 and has over 40 years of experience in the oil and gas industry. From 1980 to 1987, Mr. Long served in a variety of technical and managerial roles for several major pipeline and oil and natural gas producing companies, including Bass Enterprises Production Co. and Texas Oil & Gas. Mr. Long then served in a variety of senior officer level operating positions with affiliates of Hanover Energy, Inc., a company primarily engaged in the business of gathering, compressing and transporting natural gas. In 1993, Mr. Long co-founded Global Compression Services, Inc., a compression services company. Mr. Long was formerly on the board of directors of the Wiser Oil Company, an NYSE listed company from May 2001 until it was sold to Forest Oil Corporation in May 2004. Mr. Long received his bachelor’s degree, with honors, in Petroleum Engineering from Texas A&M University. He is a registered Professional Engineer in the state of Texas.

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As a result of his professional background, Mr. Long brings to us executive level strategic, operational and financial skills. These skills, combined with his over 40 years of experience in the oil and natural gas industry, including in particular his experience in the compression services sector, make Mr. Long a valuable member of the Board.

Matthew C. Liuzzi has served as our Vice President, Chief Financial Officer and Treasurer since January 2015. Prior to such time, Mr. Liuzzi served as our Senior Vice President – Strategic Development since joining us in April 2013. Mr. Liuzzi joined us after nine years in investment banking, since 2008 at Barclays, where he was most recently a Director in the Global Natural Resources Group in Houston. At Barclays, Mr. Liuzzi worked primarily with midstream clients on a variety of investment banking assignments, including initial public offerings, public and private debt and equity offerings, as well as strategic advisory assignments. He holds a B.A. and an M.B.A., both from the University of Virginia.

Eric A. Scheller has served as our Vice President, Chief Operating Officer since June 2020. Prior to that, Mr. Scheller served as our Vice President—Fleet Operations since April 2018, and prior to that was our Vice President, Operations & Performance Management beginning in August 2015. Prior to joining us, Mr. Scheller was a Director at Sapient Global Markets since August 2013. Before Sapient, Mr. Scheller was a consultant in private practice advising midstream and chemicals firms from January 2012 to July 2013. Prior to that, he held several positions with Enterprise Products Partners LP from November 2004 to December 2011, most recently as Regional Director, Pipeline & Storage Services. Mr. Scheller holds a B.S. in Chemical Engineering (Math minor), a Masters of Chemical Engineering and an M.B.A., all from the University of Houston. Mr. Scheller is also a CFA ® charterholder.

Christopher W. Porter has served as our Vice President, General Counsel and Secretary since January 2017, and, prior to that, had served as our Associate General Counsel and Assistant Secretary since October 2015. From January 2010 through October 2015, Mr. Porter practiced corporate and securities law at Hunton Andrews Kurth LLP, representing public and private companies, including master limited partnerships, in capital markets offerings and mergers and acquisitions. Mr. Porter holds a B.B.A. degree in accounting from Texas A&M University, a M.S. degree in finance from Texas A&M University, and a J.D. degree from The George Washington University.

Sean T. Kimble has served as our Vice President, Human Resources since June 2014. Mr. Kimble brings to us over twenty-five years of human resources leadership experience. Prior to joining us, he was most recently the Senior Vice President of Human Resources at Millard Refrigerated Services from January 2011 to May 2014 where he led all aspects of human resources. Before joining Millard, he was the Chief Administrative Officer and Executive Vice President of Human Resources at MV Transportation from March 2005 to February 2009 where he led human resources, safety, labor relations and various other operating support functions. Mr. Kimble holds a B.S. in marketing from Sacramento State University and an M.B.A. from Saint Mary’s College of California. Mr. Kimble also completed the University of Michigan’s Strategic HR and Strategic Collective Bargaining Programs.

Christopher R. Curia has served on the Board since April 2018. Mr. Curia has also served as a director on the board of directors of the general partner of Sunoco LP, a subsidiary of Energy Transfer LP, since August 2014 and as its Executive Vice President-Human Resources since April 2015. Mr. Curia was appointed the Executive Vice President and Chief Human Resources Officer of the general partner of Energy Transfer LP in January 2015. Mr. Curia joined Energy Transfer Operating, L.P. (“ETO”), a subsidiary of Energy Transfer LP which has since merged with Energy Transfer LP, in July 2008. Prior to joining ETO, Mr. Curia held HR leadership positions at both Valero Energy Corporation and Pennzoil and has more than three decades of Human Resources experience in the oil and gas field. Mr. Curia holds a master’s degree in Industrial Relations from the University of West Virginia.

Mr. Curia was selected to serve on the Board due to the valuable perspective he brings from his extensive experience working as a human resources professional in the energy industry, and the insights he brings to the Board on matters such as succession planning, compensation, employee management and acquisition evaluation and integration.

Matthew S. Hartman has served on the Board since April 2018. Mr. Hartman is a Managing Director at EIG Global Energy Partners and leads EIG’s infrastructure investment team, where he invests in and monitors energy infrastructure investments. Prior to joining EIG in 2014, Mr. Hartman served in various roles within the Citigroup and UBS investment banking divisions, where he advised on mergers as well as equity and debt financings for midstream energy companies. Mr. Hartman also previously worked in Ernst & Young’s tax practice. Mr. Hartman received a B.B.A. and B.P.A. from Oklahoma Baptist University and an M.B.A. from the University of Texas.

Mr. Hartman was selected to serve on the Board because of his financial and investment acumen and experience with the midstream and infrastructure energy sectors.

Glenn E. Joyce has served on the Board since April 2018. Mr. Joyce has served as Chief Administrative Officer of Apex International Energy (“Apex”) since January 2017. He previously served as Director – HR and Administration since he joined

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Apex in April 2016. Prior to joining Apex, he spent over 17 years with Apache Corporation where his last position was Director of Global Human Resources in which he managed the HR functions of the international regions of Apache (Australia, Argentina, UK, Egypt). Previously, he worked for Amoco and was involved in international operations in many different countries. Mr. Joyce received his bachelor’s degree in accounting from Texas A&M University.

Mr. Joyce was selected to serve on the Board due to his extensive experience in senior human resources leadership positions in the energy industry.

Thomas E. Long has served on the Board since April 2018. Mr. Long was appointed as Co-Chief Executive Officer of the general partner of Energy Transfer LP effective January 2021. Mr. Long previously served as their Chief Financial Officer from February 2016 until January 2021. Mr. Long has also served as a director of the general partner of Energy Transfer LP since April 2019. Mr. Long served as Co-Chief Executive Officer of ETO’s general partner from January 2021 until its merger into Energy Transfer LP in April 2021 and was previously its Chief Financial Officer. He also served on the board of directors of the general partner of Sunoco LP from May 2016 until May 2021. Mr. Long also served as the Chief Financial Officer and as a director of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Long also served as Executive Vice President and Chief Financial Officer of Regency GP LLC from November 2010 to April 2015.

Mr. Long was selected to serve on the Board because of his understanding of energy-related corporate finance gained through his extensive experience in the energy industry.

Thomas P. Mason has served on the Board since April 2018. Mr. Mason became Executive Vice President and General Counsel of the general partner of Energy Transfer LP in December 2015, and has also served as the Executive Vice President, General Counsel and President - LNG of the general partner of Energy Transfer LP since October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. In February 2021, Mr. Mason assumed leadership responsibility over Energy Transfer LP’s new Alternative Energy Group, which focuses on the development of alternative energy projects aimed at continuing to reduce Energy Transfer LP’s environmental footprint throughout its operations. Mr. Mason previously served as Senior Vice President, General Counsel and Secretary of ETO’s general partner from April 2012 to December 2015, as Vice President, General Counsel and Secretary from June 2008 and as General Counsel and Secretary from February 2007. Prior to joining ETO, he was a partner in the Houston office of Vinson & Elkins L.L.P. Mr. Mason has specialized in securities offerings and mergers and acquisitions for more than 25 years. Mr. Mason also previously served on the Board of Directors of the general partner of Sunoco Logistics Partners L.P. from October 2012 to April 2017 and also served on the Board of Directors of the general partner of PennTex Midstream Partners, LP from November 2016 to July 2017.

Mr. Mason was selected to serve on the Board because of his decades of legal experience in securities, mergers and acquisitions and corporate governance in the energy sector.

Matthew S. Ramsey has served on the Board since April 2018. Mr. Ramsey currently serves as the Chief Operating Officer of the general partner of Energy Transfer LP, a position he has held since October 2018 following the merger of Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. Since July 2012, Mr. Ramsey has also been a member of the board of directors of the general partner of Energy Transfer LP. Additionally, Mr. Ramsey serves as Chairman of the Board of Directors of the general partner of Sunoco, LP. Mr. Ramsey previously served as President, Chief Operating Officer and as a member of the Board of Directors of Energy Transfer Partners, L.P. Mr. Ramsey also served as President and Chief Operating Officer and Chairman of the board of directors of PennTex Midstream Partners, LP’s general partner from November 2016 to July 2017. Mr. Ramsey also served as the President and Chief Operating Officer of the general partner of ETO since November 2015, and was a member of their board since November 2015, each until its merger into Energy Transfer LP in April 2021. Mr. Ramsey formerly served as a board member of RSP Permian, Inc. and on its audit and compensation committees. Prior to joining management at Energy Transfer, Mr. Ramsey served as President of RPM Exploration, Ltd., a private oil and gas partnership. In addition to his work in the energy business, Mr. Ramsey serves on the board of directors of the National Association of Manufacturers, and as a Trustee of the Southwestern Medical Foundation. He is the former Chairman of the University of Texas Chancellor’s Council. Mr. Ramsey holds a B.B.A. in Marketing from the University of Texas at Austin and a J.D. from South Texas College of Law.

Mr. Ramsey was selected to serve on the Board in recognition of his vast knowledge of the energy space and valuable industry, operational and management experience.

W. Brett Smith has served on the Board since April 2021. Mr. Smith has also served as President and Managing Partner of Rubicon Oil & Gas, LLC since October 2000, President of Rubicon Oil & Gas II, LP since May 2005, President of Quientesa Royalty LP since February 2005, President of Acton Energy LP since October 2008 and President of Promontory Exploration, LP since 2017. Mr. Smith was President of Rubicon Oil & Gas, LP from October 2000 to May 2005. For more than 30 years Mr. Smith has been active in assembling exploration prospects in the Permian Basin, Oklahoma, New Mexico and the Rocky Mountain areas. Mr. Smith served on the board of directors of the general partner of ETO and on its audit committee from

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February 2018 through April 2021. Mr. Smith also previously served on the board of directors of Sunoco LP and was a member of its audit and compensation committees.

Mr. Smith was selected to serve on the Board based on his experience as an executive in the oil and gas industry, as well as his recent experience on the board of another publicly traded limited partnership.

William S. Waldheimhas served on the Board since April 2018. Mr. Waldheim has also served on the board of directors of Southcross Energy Partners GP, LLC since February 2020. Mr. Waldheim served as a director and a member of the Audit, Finance & Risk Committee of Enbridge Energy Company, Inc. and Enbridge Energy Management, L.L.C. from February 2016 through December 2018. He previously served as President of DCP Midstream LP where he had overall responsibility for DCP Midstream’s affairs including commercial, trading and business development until his retirement in 2015. Prior to this, Mr. Waldheim was President of Midstream Marketing and Logistics for DCP Midstream and managed natural gas, crude oil and natural gas liquids marketing and logistics. From 2005 to 2008, he was Group Vice President of Commercial for DCP Midstream, managing its upstream and downstream commercial business. Mr. Waldheim started his professional career in 1978 with Champlin Petroleum as an auditor and financial analyst and served in roles involving NGL and crude oil distribution and marketing. He served as Vice President of NGL and Crude Oil Marketing for Union Pacific Fuels from 1987 until 1998 at which time it was acquired by DCP Midstream.

Mr. Waldheim was selected to serve on the Board because of his broad and extensive experience in senior leadership roles in the energy industry and his financial and accounting expertise.

Bradford D. Whitehurst has served on the Board since April 2019. Mr. Whitehurst currently serves as the Chief Financial Officer of the general partner of Energy Transfer LP, a position he has held since January 2021. Prior to that, Mr. Whitehurst served as their Executive Vice President – Head of Tax since August 2014. Mr. Whitehurst also served as the Chief Financial Officer of the general partner of ETO from January 2021 until its merger into Energy Transfer LP in April 2021, and prior to that was their Executive Vice President—Head of Tax since August 2014. Prior to joining Energy Transfer LP, Mr. Whitehurst was a partner in the Washington, DC office of Bingham McCutchen LLP and an attorney in the Washington, DC offices of both McKee Nelson LLP and Hogan & Hartson. Mr. Whitehurst has specialized in partnership taxation and has advised Energy Transfer LP in his role as outside counsel since 2006.

Mr. Whitehurst was selected to serve on the Board because of his strong background in the energy sector and specialized knowledge of the taxation structure and issues unique to partnerships.

Delinquent Section 16(a) Reports

Section 16(a) of the Exchange Act requires that the members of the Board, our executive officers and persons who own more than 10 percent of a registered class of our equity securities file initial reports of ownership and reports of changes in ownership of our common units and other equity securities with the SEC and any exchange or other system on which such securities are traded or quoted. To our knowledge and based solely on a review of Section 16(a) forms filed electronically with the SEC, we believe that all reporting obligations of the members of the Board, our executive officers and greater than 10 percent unitholders under Section 16(a) were satisfied during the year ended December 31, 2021.

Common Unit Ownership by Directors and Executive Officers

We encourage our directors and executive officers to invest in and retain ownership of our common units, but we do not require such individuals to establish and maintain a particular level of ownership.

Reimbursement of Expenses of the General Partner

The General Partner does not receive any management fee or other compensation for its management of us, but we reimburse the General Partner and its affiliates for all expenses incurred on our behalf, including the compensation of employees of the General Partner or its affiliates that perform services on our behalf. These expenses include all expenditures necessary or appropriate to the conduct of our business and that are allocable to us. The Partnership Agreement provides that the General Partner will determine in good faith the expenses that are allocable to us. There is no cap on the amount that may be paid or reimbursed to the General Partner or its affiliates for compensation or expenses incurred on our behalf.

ITEM 11. Executive Compensation

As is commonly the case with publicly traded limited partnerships, we have no officers, directors or employees. Under the terms of the Partnership Agreement, we are ultimately managed by the General Partner, which is controlled by Energy Transfer. All of our employees, including our executive officers, are employees of USA Compression Management Services, LLC

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(“USAC Management”), a wholly owned subsidiary of the General Partner. References to “our officers” and “our directors” refer to the officers and directors of the General Partner.

Compensation Discussion & Analysis

Named Executive Officers

The following disclosure describes the executive compensation program for the named executive officers identified below (the “NEOs”). For the year ended December 31, 2021, the NEOs were:

•Eric D. Long, President and CEO;

•Matthew C. Liuzzi, Vice President, Chief Financial Officer and Treasurer;

•Eric A. Scheller, Vice President and Chief Operating Officer;

•Christopher W. Porter, Vice President, General Counsel and Secretary; and

•Sean T. Kimble, Vice President, Human Resources.

Compensation Philosophy and Objectives

Since our initial public offering in 2013, we have consistently based our compensation philosophy and objectives on the premise that a significant portion of each NEO’s total compensation should be incentive-based or “at-risk” compensation. We share Energy Transfer’s philosophy that the NEOs’ total compensation levels should be competitive in the marketplace for executive talent and abilities. The Compensation Committee generally targets a competitive range at or near the 50th percentile of the market for aggregate compensation consisting of the three main components of our compensation program: base salary, annual discretionary cash bonus and long-term equity incentive awards. The Compensation Committee believes that a desirable balance of incentive-based compensation is achieved by: (i) the payment of annual discretionary cash bonuses that consider (a) the achievement of the financial and operational performance objectives for a fiscal year set at the beginning of such fiscal year and (b) the individual contributions of each NEO to our level of success in achieving the annual financial and operational performance objectives, and (ii) the annual grant of time-based restricted phantom unit awards under the LTIP, which awards are intended to incentivize and retain our key employees for the long-term and motivate them to focus their efforts on increasing the market price of our common units and the level of cash distributions we pay to our common unitholders.

The following charts illustrate the level of at-risk incentive compensation we awarded in 2021 to our CEO and, on an averaged basis, the other NEOs. “Variable/at-risk” compensation is comprised of long-term equity incentive awards and annual discretionary cash bonuses, and “fixed” compensation is comprised of base salary.

Our compensation program is structured to achieve the following:

•compensate executive officers with an industry-competitive total compensation package of competitive base salaries and significant incentive opportunities yielding a total compensation package in a competitive range at or near the 50th percentile of the market;

•attract, retain and reward talented executive officers and key members of management by providing a total compensation package competitive with those of their counterparts at similarly situated companies;

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•motivate executive officers and key employees to achieve strong financial and operational performance;

•ensure that a significant portion of each executive officer’s compensation is performance-based or “at risk” compensation; and

•reward individual performance.

Methodology to Setting Compensation Packages

Our executive compensation program is administered by the Compensation Committee. The Compensation Committee considers market trends in compensation, including the practices of identified competitors, and the alignment of the compensation program with the Partnership’s compensation philosophy described above. Specifically, for the NEOs, the Compensation Committee:

•establishes and approves target compensation levels for each NEO;

•approves Partnership performance measures and goals;

•determines the mix between cash and equity compensation, short-term and long-term incentives and benefits;

•verifies the achievement of previously established performance goals; and

•approves the resulting cash or equity awards to the NEOs.

The Compensation Committee also considers other factors such as the role, contribution, skills, experience and performance of an individual relative to his or her peers at the Partnership. The Compensation Committee does not assign a specific weight to these factors, but rather makes a subjective judgment taking all of these factors into account.

The Compensation Committee reviews and approves all compensation for the NEOs. In determining the compensation for the NEOs, the Compensation Committee takes into account input from the CEO, for the compensation of the other NEOs. The CEO considers comparative compensation data and evaluates the individual performance of each NEO and their respective contributions to the Partnership. The recommendations are then reviewed by the Compensation Committee, which may accept the recommendations or make adjustments to the recommended compensation based on the Compensation Committee’s assessment of the individual’s performance and contributions to the Partnership. The CEO’s compensation is reviewed and approved by the Compensation Committee based on comparative compensation data and the Compensation Committee’s independent evaluation of the CEO’s contributions to the Partnership’s performance.

The Compensation Committee regularly compares results for the annual base salary, annual short-term cash bonus and long-term equity incentive awards of the NEOs against data for compensation levels for specific executive positions reported in published executive compensation surveys within each of the (i) energy industry and (ii) overall market. The Compensation Committee also reviews publicly filed peer group executive compensation disclosures pertaining to certain executive roles, but because of limited sample size due to the relatively small number of publicly traded natural gas compression companies, the Compensation Committee uses this data as a reference point rather than a primary data source.

Periodically, we engage a third-party consultant to provide the Compensation Committee with market information about compensation levels at peer companies to assist in evaluating compensation levels for our executives, including the NEOs. In 2019, Longnecker & Associates (“Longnecker”), who was also the independent compensation advisor to Energy Transfer in 2019, was engaged to provide an updated targeted market review and benchmarking for certain members of our senior leadership team (the “2019 Longnecker Report”). In 2020, the Compensation Committee determined that the 2019 Longnecker Report was completed recently enough to be utilized as a data source in reviewing and setting 2021 NEO compensation levels. As a result, the Compensation Committee relied on the results of the 2019 Longnecker Report for information on base salary, bonus and general compensation items for 2021 for the NEOs (as discussed below, our Compensation Committee utilized another report in determining the number of equity awards that should be granted to our NEOs in December 2021).

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For purposes of the 2019 Longnecker Report, our peer group, as selected by the Compensation Committee in consultation with Longnecker, included the following companies:

Company Ticker

1. Antero Midstream Corporation AM

2. Archrock, Inc. AROC

3. Crestwood Equity Partners LP CEQP

4. Genesis Energy, L.P. GEL

5. Holly Energy Partners, L.P. HEP

6. Martin Midstream Partners L.P. MMLP

7. NuStar Energy, L.P. NS

8. SemGroup Corporation SEMG

9. Summit Midstream Partners, LP SMLP

10. Tallgrass Energy, LP TGE

During 2021, Meridian Compensation Partners, LLC (“Meridian”), the independent compensation advisor to Energy Transfer, was engaged to conduct a new report on market information and compensation levels of our peer companies that provided the Compensation Committee with assistance in setting NEO compensation for the 2022 year (the “2021 Meridian Report”). The Compensation Committee also utilized the 2021 Meridian Report when determining the number of equity awards that should be granted to our NEOs in December 2021, which were based on the then-determined 2022 base salaries of the NEOs. In connection with the engagement of Meridian, based on the information presented to it, the Compensation Committee assessed the independence of Meridian under applicable SEC and NYSE rules and concluded that Meridian’s work for the Compensation Committee did not raise any conflicts of interest.

For purposes of the 2021 Meridian Report, our peer group included the following companies:

Company Ticker

1. Antero Midstream Corporation AM

2. Archrock, Inc. AROC

3. Crestwood Equity Partners LP CEQP

4. DCP Midstream, LP DCP

5. Enerflex Ltd. ENRFF

6. Enlink Midstream, LLC ENLC

7. Equitrans Midstream Corporation ETRN

8. Exterran Corporation EXTN

9. Genesis Energy, L.P. GEL

10. Holly Energy Partners, L.P. HEP

11. Martin Midstream Partners L.P. MMLP

12. NuStar Energy, L.P. NS

13. Summit Midstream Partners, LP SMLP

14. TETRA Technologies, Inc. TTI

15. Western Midstream Partners, LP WES

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Elements of the Compensation Program

Compensation for the NEOs consists primarily of the following elements and corresponding objectives:

Compensation Element Primary Objective

Base Salary for 2021

Base salaries for the NEOs have generally been set at a level deemed appropriate by the Compensation Committee to attract and retain individuals with superior talent. Base salary increases are determined based upon the job responsibilities, demonstrated proficiency and performance of the NEO and market conditions. In connection with determining base salaries for each of the NEOs for 2021, the Compensation Committee and CEO utilized the 2019 Longnecker Report to determine comparable salaries for such executive roles within our peer group, and determined that the NEOs’ base salaries were generally in line with the market, and provided a merit increase for certain NEOs for the 2021 year.

The 2021 base salaries and 2020 base salaries for the NEOs, including our CEO, are set forth in the following table:

Name and Principal Position 2021 Base Salary ($) 2020 Base Salary ($)

Eric D. Long, President and Chief Executive Officer 664,050 664,050

Eric A. Scheller, Vice President and Chief Operating Officer 350,000 331,500 (1)

Sean T. Kimble, Vice President, Human Resources 325,000 316,900

________________________

(1)The amount above reflects the base salary effective upon Mr. Scheller’s appointment as Vice President and Chief Operating Officer on June 2, 2020. Mr. Scheller’s base salary for 2020 in his prior position was $265,225. See “–Summary Compensation Table” below for the salary received by Mr. Scheller in 2020.

Annual Cash Incentive Compensation for 2021

Each of the NEOs is entitled to participate in the USA Compression Partners, LP Amended and Restated Annual Cash Incentive Plan (the “Bonus Plan”) and their potential bonus is governed by the Bonus Plan and, for Messrs. Porter and Kimble, also governed by their respective employment agreements. The Compensation Committee acts as the administrator of the Bonus Plan under the supervision of the full Board, and has the discretion to amend, modify or terminate the Bonus Plan at any time.

In February 2022, the Compensation Committee made the determination to pay annual cash bonus awards to executives, including the NEOs, under the Bonus Plan attributable to the year ended December 31, 2021. Although the Bonus Plan is generally based upon our satisfaction of certain performance measures that were previously established for the 2021 year, the Compensation Committee retains the authority to use its business judgement to make decisions or adjustments to the Bonus Plan’s funding pool or the individual bonus awards resulting from the guidelines set forth below. The Bonus Plan contains four

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payout factors and corresponding percentages that comprise the total annual target bonus for all eligible employees, including the NEOs (the “Annual Target Bonus Pool”), as shown in the following chart.

Bonus Plan Payout Factors

Payout Factor % of Total Annual Target Bonus

Adjusted EBITDA Budget Target Factor 30%

Distributable Cash Flow Budget Target Payout Factor 30%

Leverage Ratio Budget Target Factor 30%

Safety Budget Target Payout Factor 10%

Each of the Adjusted EBITDA Budget Target Factor (the “Adjusted EBITDA Factor”) and the Distributable Cash Flow Budget Target Payout Factor (the “DCF Factor”) assign payout factors from 0% to 120% based on the percentage of the Partnership’s budgeted Adjusted EBITDA and DCF, respectively, achieved for the year, as shown in the following chart.

Adjusted EBITDA and DCF Factors

% of Budget Target Bonus Pool Payout Factor

Greater than or equal to 110% 1.20x

For the 2021 year, the Compensation Committee set the Adjusted EBITDA Budget Target at $396.0 million and the DCF Budget Target at $203.0 million.

The Leverage Ratio Budget Target Factor (the “Leverage Ratio Factor”) assigns payout factors based on the Partnership’s achievement of its budgeted Leverage Ratio (as defined in the Partnership’s Credit Agreement, provided that, for purposes of calculating the Leverage Ratio for the Bonus Plan, EBITDA attributable to the full plan year is used in lieu of any other time period) for the year, as shown in the following chart.

Leverage Ratio Factor

Range within Budget Target Bonus Pool Payout Factor

More than 0.250 below budget target 1.20x

For the 2021 year, the Compensation Committee set the Leverage Ratio Budget Target at 5.21x.

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The Safety Budget Target Payout Factor (the “Safety Factor”) assigns payout factors based on the Partnership’s Total Recordable Incident Rate, or TRIR (as calculated by the U.S. Occupational Safety and Health Administration) against the Partnership’s TRIR target, as shown in the following chart.

Safety Factor

% of Target Bonus Pool Payout Factor

For the 2021 year, the Compensation Committee set the Safety Target at 0.80.

The establishment and amount of the bonus pool is 100% discretionary and subject to approval and/or adjustment by the Compensation Committee. In determining bonuses for the NEOs, the Compensation Committee takes into account whether the Partnership achieved or exceeded its targeted performance objectives. In the case of the NEOs, their bonus pool targets for the 2021 year range from 90% to 125% of their respective annual base earnings (which amount reflects the actual base salary earned during the calendar year to reflect periods before and after any base salary adjustment).

For the 2021 year, the Compensation Committee set a target bonus amount (the “Target Bonus”) for each NEO prior to the first quarter of the 2021 year, which was set as a percentage of the NEO’s base salary. For the bonus applicable to the 2021 year, the Target Bonus, as a percentage of base salary and as a dollar amount, is reflected in the table below.

Name Percentage of Base Salary Amount ($)

Eric D. Long, President and Chief Executive Officer 125 % 830,063

Eric A. Scheller, Vice President and Chief Operating Officer 90 % 315,000

Sean T. Kimble, Vice President, Human Resources 90 % 292,500

The annual cash bonus pool targets for 2021 were based on the determination of the Compensation Committee in consultation with Longnecker, and in consideration of the available compensation data and the role, contribution, skills, experience and performance of an individual relative to his or her peers at the Partnership.

Target Bonuses, if any, are paid within one week following delivery by our independent auditor of the audit of our financial statements for the year to which the Target Bonus relates, but in any case no later than March 15 of the year following the year to which the Target Bonus relates. For the year ended December 31, 2021, we achieved (i) Adjusted EBITDA of $398,379,812, resulting in an Adjusted EBITDA Bonus Pool Payout Factor of 1.00; (ii) DCF of $209,128,262, resulting in a DCF Bonus Pool Payout Factor of 1.00; (iii) Leverage Ratio, as calculated for the purposes of the Bonus Plan, of 5.07, resulting in a Leverage Ratio Bonus Pool Payout Factor of 1.10; and (iv) a TRIR of 0.75 resulting in a Safety Bonus Pool Payout Factor of 1.0. Based on these payout factors, the awards made pursuant to the Bonus Plan with respect to the year ended December 31, 2021 equal 103% of each NEOs Target Bonus and were as follows:

Name Bonus ($)

Eric D. Long, President and Chief Executive Officer 854,965

Matthew C. Liuzzi, Vice President, Chief Financial Officer and Treasurer 445,578

Eric A. Scheller, Vice President and Chief Operating Officer 324,450

Christopher W. Porter, Vice President, General Counsel and Secretary 305,910

Sean T. Kimble, Vice President, Human Resources 301,275

Long-Term Equity Incentive Awards

The LTIP, which has been in effect since 2013, is designed to promote our interests, as well as the interests of our unitholders, by rewarding our officers, directors and certain of our employees for delivering desired performance results, as

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well as by strengthening our ability to attract, retain and motivate qualified individuals to serve as officers, directors and employees. The LTIP provides for the grant, from time to time at the discretion of the Compensation Committee, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, DERs and other common unit-based awards, although since our initial public offering in 2013 the Board has only granted awards of phantom units with DERs under the LTIP. The Compensation Committee acts as the administrator of the LTIP. Each phantom unit (“Phantom Unit”) relates to one of our common units, and represents the right to receive (as applicable) a common unit or an amount of cash equal to the fair market value of a common unit (or a combination thereof) upon the vesting of such Phantom Unit pursuant to the LTIP, the applicable award agreement thereunder (“Phantom Unit Agreement”) and as determined by the Compensation Committee in its discretion. The outstanding, unvested Phantom Units granted under the LTIP and held by the NEOs are reflected below in “– Outstanding Equity Awards as of December 31, 2021.”

Our current Phantom Unit Agreement (i) provides for incremental vesting over five years in two tranches ((a) 60% on the third December 5 following the grant and (b) 40% on the fifth December 5 following the grant), (ii) provides for vesting of 100% of the outstanding, unvested Phantom Units in the event of (a) a Change in Control (as defined under the LTIP and set forth below under “Potential Payments upon Termination or Change in Control”) or (b) the death or Disability (as defined under the LTIP and set forth below under “Potential Payments upon Termination or Change in Control”) of the NEO, (iii) provides for vesting of 40% of the outstanding, unvested Phantom Units if the NEO voluntarily retires between the ages of 65-68 and has been employed by us, our General Partner, or our or its affiliates for at least 10 years (with the remaining 60% being forfeited), and (iv) provides for vesting of 50% of the outstanding, unvested Phantom Units if the NEO voluntarily retires over the age 68 and has been employed by us, our General Partner, or our or its affiliates for at least 10 years (with the remaining 50% being forfeited). The vesting of the Phantom Units are subject, in each case, to the NEO’s continued employment with us until the relevant vesting date.

The target level of annual long-term incentive awards for each of the NEOs is expressed as a percentage of the NEO’s base salary. In determining the level of the December 2021 grants of Phantom Units to the NEOs, the Compensation Committee, taking into account market data contained in the 2021 Meridian Report and the role, contribution, skills, experience and performance of an NEO relative to his or her peers at the Partnership, determined each of the NEOs’ long-term incentive targets. Due to the fact that determinations were made in late 2021, the base salaries used for these calculations were the then-determined base salaries set for the 2022 calendar year. Each NEO’s grant value is shown in the following table:

Long-Term Incentive Target Amounts for the Year Ended December 31, 2021

Name Percentage ofBase Salary Grant Date Amount ($)

Eric D. Long, President and Chief Executive Officer 400 % 2,735,886

Eric A. Scheller, Vice President and Chief Operating Officer 200 % 721,000

Sean T. Kimble, Vice President, Human Resources 175 % 568,750

Under the LTIP, the Compensation Committee has the discretion to determine whether any portion of Phantom Units should be settled in cash upon vesting. On October 28, 2020, the Compensation Committee approved the default settlement method for Phantom Units of 50% in cash (valued based on the closing price on the NYSE of the Partnership’s common units on the date of vesting) and 50% in common units for all vesting of Phantom Units occurring during 2021. However, the Compensation Committee also specified that if an employee affirmatively requests in writing that the percentage of cash settlement be set at a specific amount that is less than 50% (and such employee agrees to pay out of his or her own funds the amount of any required federal withholding to the extent that the cash portion is insufficient for the Partnership to withhold and pay such amounts on the employee’s behalf), the Board approves in advance such lesser cash settlement percentage.

Each Phantom Unit granted to an employee, including the NEOs, is granted in tandem with a corresponding DER, which entitles the recipient to receive an amount in cash on a quarterly basis equal to the product of (a) the number of Phantom Units granted to the grantee that remain outstanding and unvested as of the record date for the distribution on the Partnership’s common units for such quarter and (b) the quarterly distribution with respect to the Partnership’s common units.

Awards granted pursuant to the LTIP are subject to certain clawback features, and the award may not vest or settle if we determine that the recipient committed certain acts of misconduct, as more particularly described in the LTIP.

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Retention Phantom Unit Awards

In each of 2018 and 2019 the Compensation Committee approved an additional grant of Phantom Units to each of Messrs. Long and Liuzzi, in each case in recognition of the importance of such NEO to the Partnership’s long term success and to encourage their retention by providing additional time-based compensation. These Phantom Units are referred to as “Retention Units” and were issued pursuant to Retention Phantom Unit Agreements entered into between our General Partner and the applicable NEO on the grant date of the award (the “Retention Agreements”). The Compensation Committee did not award any Retention Units to our NEOs in 2020 or 2021. The Retention Units will vest incrementally, with 60% of the Retention Units vesting on the third December 5 following the grant and 40% on the fifth December 5 following the grant. The Retention Agreements also provide for the vesting of 100% of the then-unvested Retention Units upon (i) the NEO’s termination of employment without Cause or for Good Reason (each as defined in the Retention Agreement and set forth below under “Potential Payments upon Termination or Change in Control”), (ii) a Change in Control (as defined under the LTIP and set forth below under “Potential Payments upon Termination or Change in Control”) or (iii) the death or Disability (as defined under the LTIP and set forth below under “Potential Payments upon Termination or Change in Control”) of the NEO. In addition, Mr. Long’s Retention Agreement provides for vesting of 40% of the outstanding, unvested Phantom Units if Mr. Long voluntarily retires at age 65 or older and has been employed by us, our General Partner, or our or its affiliates for at least 10 years (with the remaining 60% being forfeited). The vesting of the Retention Units are subject, in each case, to the NEO’s continued employment with us until the relevant vesting date.

For additional information regarding the Retention Agreements, please see “– Potential Payments upon Termination or Change in Control-Retention Phantom Unit Agreements” below.

Benefit Plans and Perquisites

We provide the NEOs with certain other benefits and perquisites, which we do not consider to be a significant component of our overall executive compensation program, but which we recognize as an important factor in attracting and retaining talented executives. The NEOs are eligible under the same plans as all other employees with respect to our (i) medical, dental, vision, disability and life insurance benefits and (ii) a defined contribution plan that is tax-qualified under Section 401(k) of the Internal Revenue Code (the “401(k) Plan”). In addition, we currently provide one or more NEOs with an annual automobile allowance and club memberships. The Compensation Committee has determined it is appropriate to offer these perquisites in order to provide compensation opportunities competitive with those offered by similarly situated public companies. In determining the compensation payable to the NEOs, the Compensation Committee considers perquisites in the context of the total compensation the NEOs are eligible to receive. However, given the fact that perquisites represent a relatively small portion of the NEOs’ total compensation, the availability of these perquisites does not materially influence the Compensation Committee’s decision making with respect to other elements of the NEOs’ total compensation. The value of personal benefits and perquisites we provided to each of the NEOs in 2021 is set forth below in “– Summary Compensation Table.”

Employment Agreements

Each of Messrs. Porter and Kimble is party to an employment agreement with us (together, the “Employment Agreements”), each of which has been extended on a year-to-year basis and will be automatically extended for successive twelve month periods unless either party delivers written notice to the other at least 90 days prior to the end of the current employment term. Please see the description of the Employment Agreements under “Potential Payments upon Termination or Change in Control” for further details on the terms of the Employment Agreements.

Risk Assessment Related to Our Compensation Structure

We believe our compensation program for all of our employees, including the NEOs, is appropriately structured and not reasonably likely to result in material risk to us because it is structured in a manner that does not promote excessive risk-taking that could damage our reputation, negatively impact our financial results or reward poor judgment. We have also allocated our compensation among base salary and short and long-term compensation in such a way as to not encourage excessive risk-taking. Furthermore, all business groups and employees receive the similar compensation components of base pay and short-term incentives. We typically offer long-term equity incentives to employees at the director level or above, and we use Phantom Units rather than unit options for these equity awards because Phantom Units retain value even in a depressed market, so employees are less likely to take unreasonable risks to get or keep options “in-the-money.” Finally, the time-based vesting over three to five years for our currently outstanding long-term incentive awards ensures that our employees’ interests align with those of our unitholders with respect to our long-term performance.

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Accounting and Tax Considerations

We account for the equity compensation expense for equity awards granted under our LTIP in accordance with GAAP, which requires us to estimate and record an expense for each equity award over the vesting period of the award. For employees, Phantom Units are accounted for as a liability and are re-measured at fair value at the end of each reporting period using the market price of the Partnership’s common units. Phantom Units granted to independent directors do not have a cash settlement option; therefore we account for these awards as equity. During the requisite service period, compensation cost is recognized using the proportionate amount of the award’s fair value that has been earned through service to date.

Because we are a partnership and the General Partner is a limited liability company, section 162(m) of the Internal Revenue Code (the “Code”), which generally precludes public corporations from taking a tax deduction for individual compensation to certain of its executive officers in excess of $1 million, does not apply to the compensation paid to the NEOs and, accordingly, the Compensation Committee did not consider its impact in making the compensation recommendations discussed above.

Compensation Committee Interlocks and Insider Participation

We do not have any Compensation Committee interlocks. Messrs. Joyce, Smith and Waldheim are the only members of the Compensation Committee, and during 2021 neither Mr. Joyce nor Mr. Smith nor Mr. Waldheim was an officer or employee of Energy Transfer or any of its affiliates, or served as an officer of any company with respect to which any of our executive officers served on such company’s board of directors. In addition, neither Mr. Joyce nor Mr. Smith nor Mr. Waldheim is a former employee of Energy Transfer or any of its affiliates.

Compensation Committee Report

The Compensation Committee has reviewed and discussed the section of this report entitled “Compensation Discussion and Analysis” with management of the Partnership and approved its inclusion in this Annual Report on Form 10-K.

Compensation Committee

Glenn E. Joyce (Chairman)

William S. Waldheim

W. Brett Smith

The foregoing report shall not be deemed to be incorporated by reference by any general statement or reference to this Annual Report on Form 10-K into any filing under the Securities Act of 1933, as amended, or the Securities Exchange Act, as amended, except to the extent that we specifically incorporate this information by reference, and shall not otherwise be deemed filed under those Acts.

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Summary Compensation Table

The following table provides information concerning compensation of our NEOs for the fiscal years presented below, as applicable.

________________________

(1)The Phantom Unit values reflect the grant date fair value of the awards calculated in accordance with the Financial Accounting Standards Board’s (“FASB”) Accounting Standard Codification (“ASC”) Topic 718, disregarding the estimated likelihood of forfeitures. For a discussion of the assumptions utilized in determining the fair value of these awards, please see Note 14 in Part II, Item 8 “Financial Statements and Supplementary Data”.

(2)Represents the awards earned under the Bonus Plan for each of the NEOs. Amounts earned for the 2021 year will be paid after the Partnership’s audited financials are finalized.

(3)See the chart below for a detailed breakdown of amounts reported in this column for 2021:

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Grants of Plan-Based Awards during the Year Ended December 31, 2021

The below reflects awards granted to our NEOs under the LTIP and our Bonus Plan during 2021.

Target ($) Maximum ($)

________________________

(1)These awards were granted in 2021 pursuant to our Bonus Plan. The potential payout pursuant to these awards could be zero, thus we have not reflected a threshold amount in the table above. Actual amounts earned for the 2021 year have been reflected within the Summary Compensation Table above.

(2)The Phantom Units granted on December 5, 2021 to our NEOs were granted pursuant to our LTIP and will vest incrementally, with 60% of the Phantom Units vesting on December 5, 2024 and the remaining 40% of the Phantom Units vesting on December 5, 2026. These Phantom Units will also vest in full upon a Change in Control (as defined in the LTIP) or the death or Disability (as defined in the LTIP) of the NEO. If the NEO retires after attaining the age of 65, 60% of his then-unvested Phantom Units granted on December 5, 2021 will be forfeited, and the remainder will vest, at the time of retirement. If the NEO is over age 68 at the time of retirement, 50% of his then-unvested Phantom Units granted December 5, 2021 will be forfeited, and the remainder will vest, at the time of retirement.

(3)The Phantom Units granted on December 5, 2021 were granted in tandem with a corresponding DER.

(4)The reported grant date fair value of unit awards was calculated by multiplying $14.96, the closing price of the Partnership’s common units on December 3, 2021, the last business day prior to the date of grant (December 5, 2021), due to the grant date falling on a Sunday, by the number of units granted, as required by FASB ASC Topic 718.

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Outstanding Equity Awards as of December 31, 2021

The following table provides information regarding Phantom Units granted to the NEOs pursuant to the LTIP in each of the years ended December 31, 2018, 2019, 2020 and 2021 that were outstanding as of December 31, 2021, as well as the scheduled vesting schedule for each outstanding award. Potential acceleration events or change in control treatment for the Phantom Units are described below in the section titled “Potential Payments Upon Termination or Change in Control.” None of the NEOs held any outstanding option awards as of December 31, 2021.

Eric D. Long, President and Chief Executive Officer

Matthew C. Liuzzi, Vice President, Chief Financial Officer and Treasurer

Eric A. Scheller, Vice President and Chief Operating Officer

Christopher W. Porter, Vice President, General Counsel and Secretary

Sean T. Kimble, Vice President, Human Resources

________________________

(1)On November 1, 2018, Mr. Long and Mr. Liuzzi received a grant of 90,000 Retention Units and 35,000 Retention Units, respectively, pursuant to the LTIP and applicable Retention Agreement, of which 36,000 and 14,000 remain unvested as of December 31, 2021, respectively. These remaining unvested Retention Units will vest on December 5, 2023.

(2)Includes Phantom Units granted pursuant to the LTIP on December 5, 2018 to each of the NEOs, of which the following remain unvested as of December 31, 2021: Mr. Long - 70,749; Mr. Liuzzi - 27,434; Mr. Scheller - 5,486; Mr. Porter - 11,138; and Mr. Kimble - 14,770. These remaining unvested Retention Units will vest on December 5, 2023.

(3)Includes Phantom Units granted pursuant to the LTIP on December 5, 2019 to each of the NEOs: 167,056 to Mr. Long; 64,779 to Mr. Liuzzi; 31,446 to Mr. Scheller; 31,698 to Mr. Porter; and 34,878 to Mr. Kimble. The Phantom Units granted on December 5, 2019 vest incrementally, with 60% of the Phantom Units vesting on December 5, 2022 and the remaining 40% of the Phantom Units vesting on December 5, 2024.

(4)On December 5, 2019, Mr. Long and Mr. Liuzzi received a grant of 41,764 and 25,911 Retention Units, respectively, pursuant to the LTIP and applicable Retention Agreement. The Retention Units vest incrementally, with 60% of the Retention Units vesting on December 5, 2022 and 40% of the Retention Units vesting on December 5, 2024.

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(5)Includes Phantom Units granted pursuant to the LTIP on December 5, 2020 to each of the NEOs: 213,520 to Mr. Long; 82,797 to Mr. Liuzzi; 49,236 to Mr. Scheller; 46,422 to Mr. Porter; and 45,719 to Mr. Kimble. The Phantom Units granted on December 5, 2020 vest incrementally, with 60% of the Phantom Units vesting on December 5, 2023 and the remaining 40% of the Phantom Units vesting on December 5, 2025.

(6)Includes Phantom Units granted pursuant to the LTIP on December 5, 2021 to each of the NEOs: 182,880 to Mr. Long; 70,915 to Mr. Liuzzi; 48,195 to Mr. Scheller; 48,128 to Mr. Porter; and 38,018 to Mr. Kimble. The Phantom Units granted on December 5, 2021 vest incrementally, with 60% of the Phantom Units vesting on December 5, 2024 and the remaining 40% of the Phantom Units vesting on December 5, 2026.

(7)The market value of Phantom Units is calculated by multiplying $17.45, the closing price of the Partnership’s common units on December 31, 2021, by the number of Phantom Units outstanding.

Units Vested During the Year Ended December 31, 2021

The following table provides information regarding the vesting of Phantom Units held by the NEOs during 2021. There are no options outstanding on the Partnership’s common units.

Name Number of Phantom Units Vested (#) Value Realized on Vesting($) (5)

Eric D. Long, President and Chief Executive Officer 160,125 (1) 2,395,470

Eric A. Scheller, Vice President and Chief Operating Officer 10,461 156,742

Sean T. Kimble, Vice President, Human Resources 30,164 (4) 452,134