What changed in this filing

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Item 7. Management’s Discussion and Analysis

2022-02-15 compared with 2021-02-16 · 273 added, 164 removed, 228 unchanged (66% of the section changed)

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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 growth, 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 increase over the long term.

Furthermore, the changes in production volumes and pressures of shale plays over time require a wider range of compression services than in conventional basins.

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.

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

Credit Agreement Amendment

The Credit Agreement was amended on August 3, 2020 (the “Amendment Effective Date”) to amend, among other things, the requirements of certain covenants and the date on which certain covenants in the Credit Agreement must be met beginning on the Amendment Effective Date until the last day of the fiscal quarter ending December 31, 2021 (the “Covenant Relief Period”).

The amendment, among other items, increases the maximum funded debt to EBITDA ratio to (i) 5.75 to 1.00 for the fiscal quarters ending September 30, 2020 and December 31, 2020, (ii) 5.50 to 1.00 for the fiscal quarters ending March 31, 2021 and June 30, 2021 and (iii) 5.25 to 1.00 for the fiscal quarters ending September 30, 2021 and December 31, 2021 (reverting back to 5.00 to 1.00 after the Covenant Relief Period).

In addition, during the Covenant Relief Period, the applicable margin for Eurodollar borrowings is increased from a range of 2.00% – 2.75% to a range of 2.25% – 3.00%.

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 the amendment to our Credit Agreement.

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.

General Trends and Outlook

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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.

Over the recent past, relative stability in commodity prices encouraged investment in domestic exploration and production (“E&P”) and midstream infrastructure across the energy industry, particularly in the low-cost basins characterized by associated gas and crude oil production.

Relative stability in commodity prices over much of the past

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.

However, certain 2020 events have impacted, and may continue to impact, our operations in areas driven by associated gas and crude oil production.

For example, in March 2020 the collapse of discussions among members of Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC and other allied producing countries, “OPEC+”), combined with Saudi Arabia’s announcement that it would be discounting its price, and increasing its supply, of crude oil into the global market created downward pressure on crude oil prices worldwide.

Recent events, including reports of decreasing domestic crude oil inventory in storage as well as OPEC’s general compliance to agreed-upon production cuts and Saudi Arabia’s leadership in taking on further production cuts may be indicators of improving longer-term crude oil fundamentals which may positively impact basins where associated gas volumes are produced.

Further, the ongoing global impact, both real and perceived, on crude oil demand from the COVID-19 pandemic created uncertainty regarding the demand for compression services in our operating areas driven by associated gas and crude oil production.

While 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.

As the price of crude oil fluctuated during 2020, certain of our customers reduced their demand for our services.

Accordingly, we have reduced our planned capital spending significantly for 2021.

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 11.3 million barrels per day (“bpd”) in 2020, down 1.0 million bpd from 2019 reflecting the impact of well curtailments and a decrease in drilling activity related to low crude oil prices.

While the price of crude oil rebounded during the second quarter of 2020 and remained relatively stable during the third and fourth quarters of 2020, and rig counts have

increased modestly since the recent bottom during summer 2020, many E&P companies, including some of our customers, continue to take a cautious approach to development plans and budget for reduced capital expenditure forecasts.

The EIA Outlook forecasts total U.S.

crude oil production in 2021 to decline again, averaging 11.1 million bpd, before increasing to 11.5 million bpd in 2022.

Taking into account an approximate six-month lag between changes in crude oil prices and changes in crude oil production, the EIA Outlook expects production from the Lower 48 states to decline through February 2021 before showing steady increases throughout the remainder of 2021;

ending 2021 with an aggregate 3% decline in Lower 48 production.

We expect the reduction in capital spending during 2020 to result in a decrease in new production, in turn negatively affecting the demand for new compression services in the near term.

Further, while the Permian and Delaware Basins, one of our largest operating areas on a horsepower basis, still benefit from favorable geology as well as technological and operational improvements that have benefited operators in the region;

overall reduced drilling activity and the typically steep well decline curves are expected to have an impact on production.

As an example, the EIA Outlook expects two-thirds of U.S Lower 48 onshore growth in 2022 to come from the Permian.

However, cost of capital and capital allocation policies are expected to continue to force operators to be disciplined in their spending.

While we expect new activity to generally be reduced in 2021, the impact from these events on existing production of crude oil and natural gas, however, is far less certain.

Variables such as 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.

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.

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driven by large volumes of gas produced from shale sources has been a main driver of an overall drop in natural gas prices.

This sustained low natural gas price environment has helped create relatively resilient baseload demand for natural gas for domestic use in power generation and for industrial purposes such as chemical plants and other types of manufacturing.

Also, the development of long-term export infrastructure has continued to occur alongside the low natural gas price environment and the U.S.

became a net exporter of natural gas into global markets in 2017.

For example, while the EIA expects a decline in natural gas production for 2021 due to 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, these decreases are expected to be partially offset by other uses, including increased liquefied natural gas exports as well as increased pipeline exports to Mexico.

While the EIA expects an overall decline in natural gas production in 2021, monthly production is expected to bottom out in March 2021 and then increase through the rest of 2021, followed by continued increase in 2022.

We expect the baseload natural gas demand previously described will continue to support long-term domestic natural gas production.

In addition to the relatively stable supply, demand and price fundamentals of natural gas, we believe that the geographic diversity and portability of our assets should help mitigate the impact of market volatility or regional uncertainty.

While reduced production of associated gas impacted demand for our services in certain regions beginning in the first quarter of 2020, such reduction in production had a positive impact on both natural gas prices as well as the utilization of our assets in other regions primarily tied to natural gas prospects, such as the Marcellus, Utica and Haynesville shales.

Given these producing regions primarily contain natural gas, if natural gas prices remain resilient we believe it is reasonable to expect that these areas could see additional capital inflows to take advantage of relatively more attractive economics, which could increase demand for our services in these shales.

The design flexibility of our compression units allow us to make rapid reconfigurations and relocate units to these areas.

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 gas market through 2021.

In summary, while the outlook for commodity prices stabilized over the course of 2020, continued uncertainty with respect to demand could have a varying impact on our business.

Whereas several factors, including uncertain future demand, caused volatility in crude oil prices during 2020, on the natural gas side, relatively more moderate demand destruction coupled with associated gas production decreases have in part helped to support natural gas prices.

The overall outlook for our compression services will depend, in part, on the strength and duration of recovery in the commodity markets, and we believe as natural gas experienced a recovery more quickly than crude oil, the continued market dynamics should help support our business activities and overall utilization and pricing.

While we anticipate that the combination of commodity prices and demand may likely have an 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 compression application, contract term and other factors.

We believe our customers’ mid- to long-term expectations regarding commodity prices and the cost they would incur to return our large horsepower equipment will provide an incentive for our customers to keep our equipment in the field following expiration of the primary term, whereas we believe there is likely to be continued pressure on utilization and pricing with respect to our smaller horsepower equipment.

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.

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.

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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.

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(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% and 89.9% at December 31, 2020 and 2019, respectively.

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 1.2% increase in fleet horsepower as of December 31, 2020 compared to December 31, 2019 was attributable to compression units added to our fleet primarily for specific customer demand for our compression services, partially offset by compression units impaired during the current period.

The 9.4% decrease in revenue generating horsepower as of December 31, 2020 compared to December 31, 2019 was due to returns of compression units from our customers which also caused a 13.0% decrease in revenue generating compression units over the same period.

The returns of compression units from our customers are primarily due to a decrease in demand for compression services driven by a decline in U.S.

crude oil and natural gas activity.

The 3.6% increase in average horsepower per revenue generating compression unit was driven primarily by the composition of compression unit returns.

The 0.4% increase in average revenue per revenue generating horsepower per month for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to contracts on new compression units and selective price increases on our existing large horsepower fleet, partially offset by reduced pricing in our small horsepower fleet.

Horsepower utilization decreased to 82.8% as of December 31, 2020 compared to 93.7% as of December 31, 2019.

The 11.6% decrease in horsepower utilization is primarily due to (1) a 10.8% increase in our idle horsepower from compression units returned to us and (2) a 2.0% decrease in horsepower that is on-contract or pending-contract but not yet active.

horsepower utilization decreased to 86.8% during the year ended December 31, 2020 compared to 94.1% during the year ended December 31, 2019.

The 7.8% decrease in average horsepower utilization is primarily due to (1) a 6.9% increase in our average idle horsepower from compression units returned to us and (2) a 3.0% decrease in horsepower that is on-contract or pending-contract but not yet active.

The decreases in period end and average horsepower utilization are primarily due to a decrease in demand for compression services driven by a decline in U.S.

crude oil and natural gas activity.

Horsepower utilization based on revenue generating horsepower and fleet horsepower decreased to 80.4% as of December 31, 2020 compared to 89.9% as of December 31, 2019.

The 10.6% decrease in horsepower utilization based on revenue generating horsepower as of December 31, 2020 was primarily attributable to an increase in our idle horsepower from compression units returned to us.

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.

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 5.9% decrease in average horsepower utilization based on revenue generating horsepower for the year ended December 31, 2020 was primarily attributable to an increase in our average idle horsepower from compression units returned to us.

The decreases in period end and average horsepower utilization based on revenue generating horsepower and fleet horsepower are primarily due to a decrease in demand for compression services driven by a decline in U.S.

crude oil and natural gas activity.

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

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Selling, general and administrative 56,082 59,981 (6.5) %

Loss on disposition of assets 146 940 (84.5) %

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

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

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Contract operations revenue .

The $20.0 million decrease in contract operations revenue for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to a decline in demand for compression services driven by a decrease in U.S.

crude oil and natural gas activity.

This decline in demand resulted in a 4.3% decrease in average revenue generating horsepower for the year ended December 31, 2020 compared to the year ended December 31, 2019, partially offset by a 0.4% increase in average revenue per revenue generating horsepower per month which increased to $16.71 for the year ended December 31, 2020 compared to $16.65 for the year ended December 31, 2019.

Our contract operations revenue was not

materially impacted by any renegotiations of our contracts during the period with our customers.

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.

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 .

The $3.1 million decrease in parts and service revenue for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily attributable to a reduction in 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.

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 ETO.

The $7.6 million decrease in related party revenue for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily attributable to a decrease in parts and service revenue, as well as a decrease in contract operations revenue due to the expiration of contracts with various affiliated entities of ETO.

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 $21.4 million decrease in cost of operations for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to (1) an $11.5 million decrease in direct expenses, such as parts and fluids expenses, (2) a $6.2 million decrease in direct labor expenses, (3) a $4.6 million decrease in retail parts and services expenses, which had a corresponding decrease in parts and service revenue, (4) a $3.1 million decrease in expenses related to our vehicle fleet and (5) a $1.7 million decrease in training and other indirect expenses.

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

The decreases were partially offset by (6) a $5.1 million increase in ad valorem tax expenses due primarily to refunds received during the prior period.

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 $7.5 million increase in depreciation and amortization expense for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily related to compression units and other capital expenditures placed in service during 2019, to meet then existing demand by customers, that have a full year of depreciation expense recorded in 2020.

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 $4.4 million decrease in selling, general and administrative expense for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to (1) a $2.4 million decrease in employee-related expenses, (2) a $2.4 million decrease in general corporate expenses, (3) a $2.4 million decrease in unit-based compensation expense and (4) a $1.1 million decrease in third-party professional fees.

These decreases were offset by (5) a $2.7 million increase in the provision for expected credit losses and (6) a $1.6 million increase in severance charges.

The decreases in employee-related expenses, general corporate expenses and third-party professional fees are related to reduced headcount and cost saving measures.

The decrease in unit-based compensation expense is primarily due to the decrease in our unit price in the current period and the related mark-to-market change to our unit-based compensation liability.

The change to the provision for expected credit losses is related to the potential negative impact to our customers of low crude oil prices driven by decreased demand due to the COVID-19 pandemic and the global oversupply of crude oil during the current period.

The increase in severance charges is primarily related to the departure of one of our executives during the current period.

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 .

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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.

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.

No impairment was recorded for the year ended December 31, 2019.

Interest expense, net .

The $1.5 million increase in interest expense, net for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to a full year of interest expense incurred in the current period on the Senior Notes 2027 issued in March 2019, partially offset by reduced borrowings and lower weighted average interest rates under the Credit Agreement.

The weighted average interest rate applicable to borrowings under the Credit Agreement was 3.27% for the year ended December 31, 2020 compared to 4.84% for the year ended December 31, 2019.

Average outstanding borrowings under the Credit Agreement were $455.7 million for the year ended December 31, 2020 compared to $493.3 million for the year ended December 31, 2019.

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.

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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 under the caption “Non-GAAP Financial Measures” in Part II, Item 6 “Selected Financial Data”.

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 $16.8 million decrease in gross margin for the year ended December 31, 2020 compared to the year ended December 31, 2019 was due to (1) a $30.7 million decrease in revenues and (2) a $7.5 million increase in depreciation and amortization, offset by (3) a $21.4 million decrease in cost of operations, exclusive of depreciation and amortization.

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 $9.3 million decrease in Adjusted gross margin for the year ended December 31, 2020 compared to the year ended December 31, 2019 was due to a $30.7 million decrease in revenues, offset by a $21.4 million decrease in cost of operations, exclusive of depreciation and amortization.

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.

The $1.1 million decrease in DCF during the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to (1) a $9.3 million decrease in Adjusted gross margin and (2) a $0.7 million increase in cash interest expense, net, partially offset by (3) a $6.3 million decrease in maintenance capital expenditures and (4) a $3.2 million decrease in selling, general and administrative expenses, excluding unit-based compensation expense, severance charges and transaction expenses.

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.

Coverage Ratios .

The decreases in DCF Coverage Ratio and Cash Coverage Ratio for the year ended December 31, 2020 compared to the year ended December 31, 2019 were primarily due to additional distributions in 2020 due to the conversion of 6,397,965 Class B Units, which did not participate in distributions, to common units on a one-for-one basis on July 30, 2019.

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

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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.

In response to current market conditions, we have reduced our planned capital spending significantly for 2021.

However, if market conditions related to COVID-19 persist, this could eventually reduce our cash generated by operating activities and increase our leverage.

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:

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or (iv) issue equity securities, including under the DRIP.

The Credit Agreement was amended on August 3, 2020 to amend, among other things, the requirements of certain covenants and the date on which certain covenants in the Credit Agreement must be met beginning on the Amendment Effective Date until the last day of the fiscal quarter ending December 31, 2021.

Please see “Revolving Credit Facility” below for additional information regarding the amendment.

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.

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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

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

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

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Net cash used in investing activities .

The $39.4 million decrease in net cash used in investing activities for the year ended December 31, 2020 compared to the year ended December 31, 2019 was due to (1) a $62.1 million decrease in capital expenditures for purchases of new compression units, related equipment and reconfiguration costs, offset by (2) a $19.8 million decrease in proceeds from disposition of property and equipment and (3) a $2.9 million decrease in insurance proceeds received for compression units previously damaged.

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 $31.9 million increase in net cash used in financing activities for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to (1) a $32.1 million decrease in net borrowings and (2) a $10.5 million increase in cash distributions paid on common units primarily due to the conversion of 6,397,965 Class B Units, which did not participate in distributions, to common units on a one-for-one basis on July 30, 2019.

These changes were partially offset by a decrease in financing costs of $9.8 million due primarily to the issuance of the Senior Notes 2027 in March 2019.

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

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

On the Amendment Effective Date, we amended the Credit Agreement to, among other things, increase the maximum funded debt to EBITDA ratio to (i) 5.75 to 1.00 for the fiscal quarters ending September 30, 2020 and December 31, 2020, (ii) 5.50 to 1.00 for the fiscal quarters ending March 31, 2021 and June 30, 2021 and (iii) 5.25 to 1.00 for the fiscal quarters ending September 30, 2021 and December 31, 2021 (reverting back to 5.00 to 1.00 after the Covenant Relief Period).

In addition, the amendment provides that the 0.50 increase in maximum funded debt to EBITDA ratio applicable to certain future acquisitions (for the six consecutive month period in which any such acquisition occurs) is only available beginning with the fiscal quarter ending September 30, 2021, and in any case shall not increase the maximum funded debt to EBITDA ratio above 5.50 to 1.00.

The amendment also provides that, during the Covenant Relief Period, the availability requirement in order to make restricted payments from capital contributions and from available cash are each increased from $100 million to $250 million and the availability requirement in order to make prepayments of our senior notes, any subordinated indebtedness or any other indebtedness for borrowed money is increased from $100 million to $250 million.

In addition, during the Covenant Relief Period, the applicable margin for Eurodollar borrowings is increased from a range of 2.00% – 2.75% to a range of 2.25% – 3.00%.

The amendment further provides that the Partnership becomes guarantor of the obligations of all other guarantors under the Credit Agreement.

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

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.

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

Total Contractual Cash Obligations

The following table summarizes our total contractual cash obligations as of December 31, 2020 (in thousands):

Payments Due by Period

Contractual Obligations Total Less than 1 year 1 - 3 years 3 - 5 years More than

Long-term debt (1)

$ 1,948,810 $ — $ 473,810 $ — $ 1,475,000

Interest on long-term debt obligations (2)

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.

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,

Total revenues $ 632,645 $ 667,683

Cost of operations, exclusive of depreciation and amortization (194,389) (205,939)

Depreciation and amortization (238,769) (238,968)

Gross margin $ 199,487 $ 222,776

Depreciation and amortization 238,769 238,968

Adjusted gross margin $ 438,256 $ 461,744

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;

• 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.

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,

Net income (loss) $ 10,279 $ (594,732)

Interest expense, net 129,826 128,633

Depreciation and amortization 238,769 238,968

Income tax expense 874 1,333

EBITDA $ 379,748 $ (225,798)

Interest income on capital lease 48 383

Unit-based compensation expense (1) 15,523 8,400

Transaction expenses (2) 34 136

Severance charges 494 3,130

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

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

Impairment of goodwill (4) — 619,411

Adjusted EBITDA $ 398,380 $ 413,898

Interest expense, net (129,826) (128,633)

Non-cash interest expense 9,765 8,402

Income tax expense (874) (1,333)

Interest income on capital lease (48) (383)

Transaction expenses (34) (136)

Severance charges (494) (3,130)

Other (2,742) 4,230

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

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

________________________

Operating and finance lease obligations (3) 31,235 4,808 8,253 6,910 11,264

Total contractual cash obligations

(1) For the years ended December 31, 2021 and 2020, 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”.

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.

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.

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,

Net income (loss) $ 10,279 $ (594,732)

Non-cash interest expense 9,765 8,402

Depreciation and amortization 238,769 238,968

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

Unit-based compensation expense (1) 15,523 8,400

Transaction expenses (2) 34 136

Severance charges 494 3,130

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

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

Impairment of goodwill (4) — 619,411

Distributions on Preferred Units (48,750) (48,750)

Proceeds from insurance recovery — 336

Maintenance capital expenditures (5) (19,477) (23,301)

DCF $ 209,128 $ 220,766

Maintenance capital expenditures 19,477 23,301

Transaction expenses (34) (136)

Severance charges (494) (3,130)

Distributions on Preferred Units 48,750 48,750

Other (2,700) 3,364

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

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

________________________

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.

(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.

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

Year Ended December 31,

DCF $ 209,128 $ 220,766

Distributions for DCF Coverage Ratio (1) $ 203,978 $ 203,409

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

Distributions for Cash Coverage Ratio (3) $ 202,150 $ 201,345

DCF Coverage Ratio 1.03 x 1.09 x

Cash Coverage Ratio 1.03 x 1.10 x

________________________

(1) We assumed that the amount outstanding under the Credit Agreement at December 31, 2020 would be repaid in April 2023, the maturity date of the facility.

The $725.0 million aggregate principal amount of our Senior Notes 2026 outstanding is due April 1, 2026, and the $750.0 million aggregate principal amount of our Senior Notes 2027 outstanding is due September 1, 2027.

(2) Represents future interest payments under the Credit Agreement based on outstanding borrowings as of December 31, 2020, and the effective interest rate and unused commitment fee as of December 31, 2020 of 2.95% and 0.375%, respectively, and interest payments on our $1.5 billion aggregate principal amount of the Senior Notes.

(3) Represents commitments for future minimum lease payments on noncancelable operating and finance leases.

Effects of Inflation .

Our revenues and results of operations have not been materially impacted by inflation and changing prices in the past two fiscal years.

Off-Balance Sheet Arrangements

We have no off-balance sheet financing activities.

Please refer to Note 17 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” included in this report for a description of our commitments and contingencies.

Critical Accounting Policies and Estimates

(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.

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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;

On an ongoing basis, we evaluate our estimates;

however, actual results may differ from these estimates under different assumptions or conditions.

The accounting policies 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:

Revenue Recognition

We recognize revenue when obligations under the terms of a contract with our customer are satisfied;

generally this occurs with the transfer of our services or goods.

Revenue is measured as the amount of consideration we expect to receive in exchange for providing services or transferring goods.

Sales taxes incurred on behalf of, and passed through to, customers are excluded from revenue.

Incidental items, if any, that are immaterial in the context of the contract are recognized as expense.

Contract operations revenue

Revenue from contracted compression, station, gas treating and maintenance services is recognized ratably under our fixed-fee contracts over the term of the contract as services are provided to our customers.

Initial contract terms typically range from six months to five years, however we usually continue to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis.

We primarily enter into fixed-fee contracts whereby our customers are required to pay our monthly fee even during periods of limited or disrupted throughput.

Services are generally billed monthly, one month in advance of the commencement of the service month, except for certain customers who are billed at the beginning of the service month, and payment is generally due 30 days after receipt of our invoice.

Amounts invoiced in advance are recorded as deferred revenue until earned, at which time they are recognized as revenue.

The amount of consideration we receive and revenue we recognize is based upon the fixed fee rate stated in each service contract.

Retail parts and services revenue

Retail parts and services revenue is earned primarily on freight and crane charges that are directly reimbursable by our customers and maintenance work on units at our customers’ locations that are outside the scope of our core maintenance activities.

Revenue from retail parts and services is recognized at the point in time the part is transferred or service is provided and control is transferred to the customer.

At such time, the customer has the ability to direct the use of the benefits of such part or service after we have performed our services.

We bill upon completion of the service or transfer of the parts, and payment is generally due 30 days after receipt of our invoice.

The amount of consideration we receive and revenue we recognize is based upon the invoice amount.

There are typically no material obligations for returns, refunds, or warranties.

Our standard contracts do not usually include material variable or non-cash consideration.

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

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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).

The timing of the annual test may result in charges to our statement of operations in our fourth fiscal quarter that could not have been reasonably foreseen in prior periods.

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.

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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, weighted average costs of capital and future market conditions, among others.

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,

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.

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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.

As of October 1, 2019, we performed a qualitative assessment of relevant events and circumstances potentially indicating the likelihood of goodwill impairment.

The qualitative assessment included weighting such factors as (i) macroeconomic conditions, (ii) industry and market considerations, (iii) cost factors, (iv) overall financial performance of the reporting unit, (v) other relevant entity-specific events, and (vi) consideration of whether there was a sustained decrease in the price of our units.

Upon completion of our qualitative assessment, we concluded that it was not more likely than not that the fair value of our single reporting unit was less than its carrying value and that our goodwill was not impaired for the year ended December 31, 2019.

Long-Lived Assets

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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

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 and is the same process for both of our financial assets as they have similar risk characteristics.

We continuously evaluate the financial strength of our customers based on collection experience, the overall business climate in which our customers operate and specific identification of customer credit losses and make adjustments to the allowance as necessary.

Our evaluation of our customers’ financial strength is based on the aging of their respective receivables balance, customer correspondence, financial information and third-party credit ratings.

Our evaluation of the business climate in which our customers operate is based on a review of various publicly available materials regarding our customers’ industries, including the solvency of various companies in the industry.

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 2 for discussion on the adoption of Accounting Standards Update 2016-13 Financial Instruments – Credit Losses (“Topic 326”):

Measurement of Credit Losses on Financial Instruments and Note 18 for other specific recent accounting pronouncements affecting us.

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

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What changed 10-K

Item 7. Management’s Discussion and Analysis