What changed in this filing

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Item 7. Management’s Discussion and Analysis

2023-02-14 compared with 2022-02-15 · 193 added, 261 removed, 240 unchanged (65% of the section changed)

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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.

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.

Discussion and analysis of our operating highlights and financial results of operations for the year ended December 31, 2021, compared to the year ended December 31, 2020, 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 Estimates” in our Annual Report on Form 10-K filed for the year ended December 31, 2021, with the SEC on February 15, 2022.

We provide compression services in 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.

As such, we have focused our activities in areas with attractive natural gas and crude oil production, which generally are 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.

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

We believe we are well-positioned to meet these changing operating conditions due to the operational design flexibility inherit within our compression-unit fleets.

Our business largely focuses 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 basins, including gas lift applications on crude oil wells targeted by horizontal drilling techniques.

Gas lift is a process by which natural gas is injected into the production tubing of an existing producing well to reduce hydrostatic pressure and allow the oil to flow at a higher rate.

This process, and other artificial-lift technologies are critical to the enhancement of oil production from horizontal wells operating in tight shale plays.

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

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.

A significant portion of our assets are utilized in natural gas infrastructure applications typically located in U.S.

onshore shale plays, primarily at centralized gathering systems and processing facilities utilizing large-horsepower compression units.

Given the infrastructure nature of these applications, the continued need for additional natural gas compression throughout the production cycle, and the long-term investment horizon of our customers, we generally have experienced stability in service rates and higher sustained fleet utilization rates relative to other businesses more directly tied to drilling activity and wellhead-specific economics.

In addition to our natural gas infrastructure applications, a portion of our small- and large-horsepower fleet is used in connection with gas-lift applications for crude oil production targeted by horizontal drilling techniques.

We deliver natural gas compression services in connection with domestic natural gas production that primarily occurs in natural gas basins, such as the Marcellus, Utica, and Haynesville Shales, and in crude oil basins where “associated” natural gas is produced alongside crude oil, such as in the Permian and Delaware Basins, Eagle Ford, and the Mid-Continent.

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 low-cost U.S.

onshore shale basins that feature crude oil and associated gas production.

The development of these basins has created additional incremental demand for natural gas compression as it is a critical method to transport associated gas volumes or enhance crude oil production through gas lift.

Following a sustained period of general stability and moderate growth for the midstream sector and the broader energy industry, the events of 2020—including the COVID-19 pandemic and worldwide crude oil price dislocations related to actions taken by members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia (together with OPEC and other allied producing countries, “OPEC+”)—impacted participants across the energy industry, including us and our customers.

The significant price volatility in both crude oil and natural gas adversely impacted energy companies’ financial performance,

and combined with reduced and uncertain future demand, created a market environment that compelled industry participants to pivot toward a renewed focus on restoring balance sheet strength, driven in part by undertaking meaningful reductions in capital investment.

During 2021 and throughout 2022, the general energy industry recovered substantially from the low commodity prices and reduced economic activity of 2020, driven by continued demand growth for crude oil and natural gas that occurred as worldwide economic recovery from COVID-19 lock-downs commenced.

As the demand for hydrocarbons generally follows economic growth, 2022 saw further demand growth coupled with ongoing supply constraints, attributable largely to the effects of comparatively reduced capital investment across the energy sector that began prior to the COVID-19 pandemic, intensified during the pandemic, and continued during the post-pandemic period as industry participants remained committed to capital discipline.

Although the effects of the COVID-19 pandemic continue to create general economic uncertainty, many economies and industries that directly or indirectly use crude oil and natural gas have entered economic recovery, resulting in increased demand for hydrocarbons.

According to the EIA, global consumption of petroleum and liquids fuels increased over 2% in 2022 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.

gross domestic product increased 1.9% in 2022, evidencing continued global economic recovery.

The EIA’s January 2023 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.

crude oil production averaged 11.9 million barrels per day (“bpd”) in 2022, up 0.6 million bpd from 2021, primarily due to production growth in the Permian and Delaware Basins.

In 2023 and 2024, 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.

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.

crude oil production growth to continue, estimating average production of 12.4 million bpd for 2023 and 12.8 million bpd in 2024, which would represent the highest annual average crude oil production on record.

The expected increase in crude oil production is due in part to the expectation that crude oil prices will remain economic for producers.

The EIA estimates that West Texas Intermediate crude oil prices will average $77 per barrel and $72 per barrel for 2023 and 2024, respectively.

We expect that anticipated crude oil production increases likewise will increase associated natural gas production volumes throughout 2023, thereby increasing demand for our compression services, particularly in the Permian and Delaware Basins.

Unlike crude oil, natural gas production and prices have been influenced by different factors, including the nonexistence of an OPEC+ equivalent for the global natural gas market, which makes natural gas price discovery dependent on market supply and demand dynamics rather than by a centralized market coordinator.

Over the past several years, increased natural gas production in the U.S., driven by large volumes of associated gas produced from shale sources, has been a major driver of an overall decline in natural gas prices.

Significant demand for natural gas is driven by domestic power generation and industrial uses such as chemical plants, which have benefited from a lower-price environment.

These low prices, combined with a general shift 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., and has created a relatively resilient baseload demand for natural gas.

The demand for domestic natural gas also continues to benefit from the construction of liquefied natural gas (“LNG”) export infrastructure, which enables industry participants to benefit from attractive global natural gas prices.

witnessed record LNG exports during 2022 according to the EIA.

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.

natural gas consumption to decrease 2% in 2023, reflecting a decrease in the use of natural gas in the electric power generation sector, as a result of milder-than-normal winter and summer weather forecasts, and an increased share of power generation from renewables.

The decreases in use for electric power generation is expected to be offset partially by other uses, including increased LNG exports and increased pipeline exports.

Natural gas prices averaged $6.42 in 2022 and the EIA Outlook expects natural gas prices to average approximately $5 for both 2023 and 2024.

However, we expect the baseload natural gas demand previously described to continue to support long-term domestic natural gas production.

Although our business is focused on providing compression services that do not bear direct exposure to commodity prices, our business exhibits indirect exposure to commodity prices as overall levels of drilling activity are influenced by prevailing commodity prices.

Moderate crude oil production increases in major U.S.

onshore basins occurred during 2022 as a result of a constructive commodity-price backdrop.

Accordingly, we experienced increased demand for our compression services as evidenced by marked improvements to our fleet utilization rates and pricing for our services.

Additionally, small horsepower gas lift applications have historically been more susceptible to commodity price swings, and when commodity prices are low, we have experienced, and may again experience, some pressure on service rates and utilization in small horsepower gas lift applications.

Other variables, including takeaway capacity, flaring considerations, reservoir pressure and flow rates, high switching costs associated with large-horsepower compressors (borne by our customers), and company-specific dynamics also factor into producers’ decisions with respect to their natural gas compression needs.

For example, as wells age, and the reservoir pressures continue to decline naturally, more horsepower may be required to meet the customer’s operational needs.

Conversely, decreased drilling activity may cause demand for new compression services to decline.

The broader outlook for commodity prices improved considerably during 2022, and although uncertainty with respect to future natural gas demand may have a varying impact on our business, we believe the longer-term outlook for natural gas fundamentals remains positive for 2023 and beyond.

Future demand for our compression services will depend, in part, on the strength and duration of economical commodity prices and producer activity in the basins that we service.

While we anticipate that the combination of commodity prices and demand to have a positive impact on activity levels in both the upstream and midstream energy sectors, we cannot predict the ultimate magnitude of that impact on our business and expect it to vary 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.

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

2021 2020 Change

Year Ended December 31,

2022 2021 Increase

Fleet horsepower (at period end) (1) 3,716,854 3,689,018 0.8 %

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As of December 31, 2022, we had 165,000 large horsepower on order for delivery during 2023.

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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(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.

(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 but 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 86.1% and 80.4% as of December 31, 2022, and 2021, respectively.

(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 82.9% and 79.8% for the years ended December 31, 2022, and 2021, 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.

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.

The 3.7% increase in total available horsepower as of December 31, 2022, compared to December 31, 2021, primarily was due to compression units added to our fleet to meet incremental demand from customers for our compression services.

The 7.9% increase in revenue-generating horsepower and 4.4% increase in revenue-generating compression units as of December 31, 2022, compared to December 31, 2021, primarily were driven by the redeployment of certain previously idle compression units due to increased demand for our services, commensurate with increased operating activity in the oil and gas industry.

The 4.5% increase in average revenue per revenue generating horsepower per month for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to select price increases on our existing fleet.

The 2.0% increase in average horsepower per revenue-generating compression unit primarily was due to the redeployment of larger-horsepower compression units.

Horsepower utilization increased to 91.8% as of December 31, 2022, compared to 82.7% as of December 31, 2021.

The increase primarily was due to an increase in revenue-generating horsepower and an increase in horsepower that is under contract but not yet generating revenue, which was driven by a combination of the redeployment of certain previously idle compression units as well as new units added to our fleet.

The increase in horsepower utilization is the result of increased demand for our services, consistent with increased operating activity in the oil and gas industry.

The above-stated factors also drove the increase in average horsepower utilization for the year ended December 31, 2022, as compared to the year ended December 31, 2021.

Horsepower utilization based on revenue-generating horsepower and fleet horsepower increased to 86.1% as of December 31, 2022, compared to 80.4% as of December 31, 2021.

The increase in horsepower utilization based on revenue-generating horsepower and fleet horsepower primarily was driven by the redeployment of certain previously idle compression units due to increased demand for our services, consistent with increased operating activity in the oil and gas industry.

The above-stated factor also drove the increase in average horsepower utilization based on revenue-generating horsepower and fleet horsepower for the year ended December 31, 2022, as compared to the year ended December 31, 2021.

Financial Results of Operations

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

Year Ended December 31, Percent

2021 2020 Change

Year Ended December 31, Increase

2022 2021 (Decrease)

Contract operations $ 673,214 $ 609,450 10.5 %

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Impairment of compression equipment 1,487 5,121 (71.0) %

Impairment of goodwill — 619,411 *

Total costs and expenses 535,305 491,773 8.9 %

Operating income (loss) 140,872 (464,852) *

Operating income 169,293 140,872 20.2 %

Other income (expense):

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Total other expense (137,959) (129,719) 6.4 %

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

Net income before income tax expense 31,334 11,153 180.9 %

Income tax expense 1,016 874 16.2 %

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

Net income $ 30,318 $ 10,279 195.0 %

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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.

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.

The $63.8 million increase in contract operations revenue for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to (i) a 4.5% increase in average revenue per revenue-generating horsepower per month, as a result of Consumer Price Index (“CPI”)-based and other price increases on customer contracts that occur as market conditions permit, (ii) a 3.9% increase in average revenue-generating horsepower as a result of increased demand for our services, consistent with increased operating activity in the oil and gas industry, and (iii) an increase in revenue attributable to natural gas treating services.

Additionally, average revenue per revenue-generating horsepower per month associated with our compression services provided on a month-to-month basis did not differ significantly 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.

The $4.5 million increase in parts and service revenue for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to an increase in maintenance work performed on units at customer locations that are outside the scope of our core maintenance activities and that are offered as a convenience, and in directly reimbursable freight and crane charges that are the financial responsibility of the customers.

Demand for retail parts and services fluctuates from period to period based on varying customer needs.

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.

Related-party revenue was earned through related-party transactions that occur in the ordinary course of business with various affiliated entities of Energy Transfer.

The $3.7 million increase in related-party revenue for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to revenue recognized from entities acquired by Energy Transfer during the previously comparable 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.

The $39.9 million increase in cost of operations for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to (i) a $19.2 million increase in direct expenses, primarily driven by fluids and parts due to higher costs and increased usage associated with higher revenue-generating horsepower, (ii) a $6.3 million increase in outside maintenance costs due to greater use and higher costs of third-party labor during the current period, (iii) a $3.6 million increase in non-income taxes, primarily due to sales tax refunds received in the prior comparable period, (iv) a $3.4 million increase in direct labor costs due to higher employee costs, (v) a $3.3 million increase in retail parts and service expenses, for which a corresponding increase in parts and service revenue also occurred, and (vi) a $2.8 million increase in expenses related to our vehicle fleet, primarily due to increased fuel costs and increased usage, as well as higher costs of maintenance 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.

The $2.1 million decrease in depreciation and amortization expense for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to increased asset disposals and assets reaching the end of their depreciable lives.

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.

The $5.2 million increase in selling, general, and administrative expense for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to (i) a $2.0 million decrease to the allowance for credit losses, resulting from a $0.7 million reversal of previously recognized credit losses in the current period versus a $2.7 million reversal in the prior comparable period, (ii) a $1.1 million increase in employee-related expenses, (iii) a $0.5 million increase in professional fees, (iv) a $0.5 million increase in severance charges, primarily attributable to the departure of one of our executives during the current period, and (v) a $0.4 million increase in other taxes.

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.

The $4.1 million increase in loss (gain) on disposition of assets for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to the exercise of a lease purchase option on certain compression units by a customer during the prior comparable period.

The remaining change primarily relates to various asset disposals.

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.

The $1.5 million and $5.1 million impairments of compression equipment during the years ended December 31, 2022 and 2021, respectively, primarily were the result of our evaluations of the future deployment of our idle fleet under then-existing market conditions.

The primary circumstances supporting these impairments were:

(i) unmarketability of units into the foreseeable future, (ii) excessive maintenance costs associated with certain fleet assets, and (iii) excessive retrofitting costs that likely would prevent certain units from securing customer acceptance.

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.

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.

As a result of our evaluations during the years ended December 31, 2022 and 2021, we retired 15 and 26 compression units, respectively, for a total of approximately 3,200 and 11,000 aggregate horsepower, respectively, that previously were used to provide compression services in our business.

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.

The $8.2 million increase in interest expense, net for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to higher weighted-average interest rates and increased borrowings under

the Credit Agreement, partially offset by a decrease in amortization of debt issuance costs attributable to the amendment and restatement of the Credit Agreement in the prior comparable period.

The weighted-average interest rate applicable to borrowings under the Credit Agreement was 4.48% and 2.98% for the years ended December 31, 2022, and 2021, respectively, and average outstanding borrowings under our Credit Agreement were $580.4 million for the year ended December 31, 2022, compared to $491.5 million for the year ended December 31, 2021.

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.

The $0.1 million increase in income tax expense for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was related to 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

Year Ended December 31, Increase

Other Financial Data:

(1) 2021 2020 Change

(1) 2022 2021 (Decrease)

Gross margin $ 233,585 $ 199,487 17.1 %

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1.08 x 1.03 x 4.9 %

Cash Coverage Ratio 1.03 x 1.10 x (6.4) %

________________________

(1) Adjusted gross margin, Adjusted EBITDA, DCF, DCF Coverage Ratio and Cash Coverage Ratio are all non-GAAP financial measures.

(1) Adjusted gross margin, Adjusted EBITDA, Distributable Cash Flow (“DCF”), and DCF 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”.

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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.

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, 2021 compared to the year ended December 31, 2020 were primarily due to the decrease in DCF.

The $34.1 million increase in gross margin for the year ended December 31, 2022, compared to the year ended December 31, 2021, was due to (i) a $72.0 million increase in revenues and (ii) a $2.1 million decrease in depreciation and amortization, partially offset by (iii) a $39.9 million increase in cost of operations, exclusive of depreciation and amortization.

Adjusted gross margin and Adjusted gross margin percentage.

The $32.0 million increase in Adjusted gross margin for the year ended December 31, 2022, compared to the year ended December 31, 2021, was due to a $72.0 million increase in revenues, partially offset by a $39.9 million increase in cost of operations, exclusive of depreciation and amortization.

The 2.6% decline in Adjusted gross margin percentage primarily was due to the inflation-driven increase in cost of operations, exclusive of depreciation and amortization, that preceded CPI-based and other price increases on customer contracts that occur as market conditions permit.

Adjusted EBITDA and Adjusted EBITDA percentage.

The $27.6 million increase in Adjusted EBITDA for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to a $32.0 million increase in Adjusted gross margin, partially offset by a $4.4 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, severance charges, and transaction expenses.

The 2.5% decline in Adjusted EBITDA percentage primarily was due to the inflation-driven increase in cost of operations, exclusive of depreciation and amortization, that preceded CPI-based and other price increases on customer contracts that occur as market conditions permit.

The $12.4 million increase in DCF for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to (i) a $32.0 million increase in Adjusted gross margin, partially offset by (ii) a $10.7 million increase in cash interest expense, net, (iii) a $4.4 million increase in selling, general, and administrative expenses, excluding unit-based compensation expense, severance charges, and transaction expenses, and (iv) a $4.3 million increase in maintenance capital expenditures.

DCF Coverage Ratio .

The increase in DCF Coverage Ratio for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to the increase in DCF, partially offset by increased distributions due to an increase in the number of outstanding common units.

Liquidity and Capital Resources

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.

We operate in a capital-intensive industry, and our primary liquidity needs are to finance the purchase of additional compression units, 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.

We believe cash generated by operating activities and, where necessary, borrowings under the Credit Agreement will be sufficient to service our debt, fund working capital, fund our estimated expansion capital expenditures, fund our maintenance capital expenditures, and pay distributions to our unitholders through 2023.

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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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:

Our capital requirements primarily have consisted of, and we anticipate that our capital requirements will continue primarily to consist 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;

• 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.

• 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 at the time of replacement were not generating operating income.

We classify capital expenditures as maintenance or expansion on an individual-asset basis.

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We currently plan to spend approximately $26.0 million in maintenance capital expenditures during 2023, 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.

Without giving effect to any equipment that we may acquire pursuant to any future acquisitions, we currently have budgeted between $260.0 million and $270.0 million in expansion capital expenditures for 2023.

Our expansion capital expenditures for the years ended December 31, 2022, and 2021, were $145.1 million and $40.2 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.

As of December 31, 2022, we had binding commitments to purchase $159.3 million worth of additional compression units and serialized parts, all of which is expected to be settled within the next twelve months.

Other Commitments

As of December 31, 2022, other commitments include operating and finance lease payments totaling $24.9 million, of which we expect to make payments of $5.1 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”.

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, 2022, and 2021, (in thousands):

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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.

The $4.8 million decrease in net cash provided by operating activities for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to changes in other working capital, offset by an $18.2 million increase in net income, as adjusted for non-cash items.

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.

The $90.8 million increase in net cash used in investing activities for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to an $89.0 million increase in capital expenditures, for purchases of new compression units, reconfiguration costs, and other 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.

The $95.6 million decrease in net cash used in financing activities for the year ended December 31, 2022, compared to the year ended December 31, 2021, primarily was due to (i) an $87.1 million increase in net borrowings under the Credit Agreement and (ii) a $9.4 million decrease in financing costs, primarily due to costs incurred related to the amendment and restatement of our Credit Agreement in the prior comparable period, partially offset by (iii) a $1.1 million increase in common unit distributions.

Revolving Credit Facility

As of December 31, 2022, 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 December 31, 2022, we had outstanding borrowings under the Credit Agreement of $646.0 million, $954.0 million of availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of $333.1 million.

As of February 9, 2023, we had outstanding borrowings under the Credit Agreement of $677.0 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.

On December 8, 2021, the Partnership amended and restated the Credit Agreement.

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.

The Partnership’s obligations under the Credit Agreement are guaranteed by the guarantors party to the Credit Agreement, which currently consists of all of the Partnership’s 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;

(i) substantially all of the Partnership’s assets and substantially all of the assets of the guarantors party to the Credit Agreement, excluding real property and other customary exclusions;

and (ii) all of the equity interests of the Partnership’s U.S.

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“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%.

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 Alternate 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 equal to 0.375% per annum.

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 Partnership also must 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 5.50 to 1.00 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.

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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.

reduce distributions from our current distribution rate or suspend distributions altogether;

delay discretionary capital spending and reduce operating expenses;

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.”.

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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.

We believe Adjusted gross margin is useful to investors as a supplemental measure of our operating profitability.

Adjusted gross margin primarily is impacted 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 presented in accordance with GAAP.

Moreover, our 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 cost structure.

To compensate for the limitations of Adjusted gross margin as a measure of our performance, we believe 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):

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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.

We define Adjusted EBITDA as EBITDA plus impairment of compression equipment, impairment of goodwill, interest income on capital leases, unit-based compensation expense (benefit), 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 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 financial performance of our assets without regard to the impact of financing methods, capital structure, or the 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;

• the ability of our assets to generate cash sufficient to make debt payments and 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.

We believe Adjusted EBITDA provides useful information to investors because, when viewed in conjunction with our GAAP results and the accompanying reconciliations, it may provide a more complete assessment of our performance as compared to considering solely GAAP results.

We also believe that external users of our financial statements benefit from having access to the same financial measures that management uses to evaluate 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 presented in accordance with GAAP.

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):

Because we use capital assets, depreciation, impairment of compression equipment, loss (gain) on disposition of assets, and the interest cost of acquiring compression equipment also are necessary elements of our aggregate costs.

Unit-based compensation expense related to equity awards granted to employees also is a meaningful business expense.

Therefore, measures that exclude these cost elements have material limitations.

To compensate for these limitations, we believe that it is important to consider net income (loss) and net cash provided by operating activities as determined under GAAP, as well as Adjusted EBITDA, to evaluate our financial performance and liquidity.

Our Adjusted EBITDA excludes some, but not all, items that affect net income (loss) and net cash provided by operating activities, and these excluded items may vary among companies.

Management compensates for the limitations of Adjusted EBITDA as an analytical tool by reviewing comparable GAAP measures, understanding the differences between the measures, and incorporating this knowledge into their decision making.

The following table reconciles Adjusted EBITDA to net income 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)

Net income $ 30,318 $ 10,279

Interest expense, net 138,050 129,826

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Impairment of compression equipment (3) 1,487 5,121

Impairment of goodwill (4) — 619,411

Adjusted EBITDA $ 425,978 $ 398,380

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________________________

(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.

(1) For the years ended December 31, 2022, and 2021, unit-based compensation expense included $4.4 million and $4.2 million, respectively, of cash payments related to quarterly payments of DERs on outstanding phantom unit awards and $1.3 million and $0.3 million, respectively, related to the cash portion of any settlement of phantom unit awards upon vesting.

The remainder of 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”.

(3) Represents non-cash charges incurred to decrease the carrying value of long-lived assets with recorded values that are not expected to be recovered through future cash flows.

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.

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 (benefit), 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 the cash flows that 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 that we expect to pay our common unitholders.

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 presented in accordance with GAAP.

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):

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 components of our

aggregate costs.

Unit-based compensation expense related to equity awards granted to employees also is a meaningful business expense.

Therefore, measures that exclude these cost elements have material limitations.

To compensate for these limitations, we believe that it is important to consider net income (loss) and net cash provided by operating activities as determined under GAAP, as well as DCF, to evaluate our financial performance and liquidity.

Our DCF excludes some, but not all, items that affect net income (loss) and net cash provided by operating activities, and these excluded items may vary among companies.

Management compensates for the limitations of DCF as an analytical tool by reviewing comparable GAAP measures, understanding the differences between the measures, and incorporating this knowledge into their decision making.

The following table reconciles DCF to net income 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)

Net income $ 30,318 $ 10,279

Non-cash interest expense 7,265 9,765

Depreciation and amortization 236,677 238,769

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

Non-cash income tax benefit (151) (42)

Unit-based compensation expense (1) 15,894 15,523

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Impairment of compression equipment (3) 1,487 5,121

Impairment of goodwill (4) — 619,411

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

Proceeds from insurance recovery — 336

Maintenance capital expenditures (4) (23,777) (19,477)

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________________________

The remainder of the unit-based compensation expense for all periods was related to non-cash adjustments to the unit-based compensation liability.

The remainder of 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.

(3) Represents non-cash charges incurred to decrease the carrying value of long-lived assets with recorded values that are not expected to be recovered through future cash flows.

(4) Reflects actual maintenance capital expenditures for the period presented.

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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):

DCF Coverage Ratio is defined as the period’s DCF divided by distributions declared to common unitholders in respect of such period.

We believe DCF Coverage Ratio is an important measure of operating performance because it permits management, investors, and others to assess our ability to pay cash distributions to common unitholders out of the cash flows that we generate.

Our DCF Coverage Ratio, as presented, may not be comparable to similarly titled measures of other companies.

The following table summarizes our DCF Coverage Ratio for the periods presented (dollars in thousands):

Year Ended December 31,

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Distributions for DCF Coverage Ratio (1) $ 205,559 $ 203,978

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

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

DCF Coverage Ratio 1.08 x 1.03 x

Cash Coverage Ratio 1.03 x 1.10 x

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(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.

The discussion and analysis of our financial condition and results of operations is based on 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.

We base our estimates on historical experience, available information, and 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.

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,

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.

The accounting estimates that we believe require management’s most difficult, subjective, or complex judgments, and that are the most critical to its reporting of results of operations and financial position are as follows:

Long-Lived Assets

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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.

Potential events or circumstances that reasonably could 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 our 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.

For the years ended December 31, 2022, and 2021, we evaluated the future deployment of our idle fleet assets under then-existing market conditions and retired 15 and 26 compressor units, respectively, for a total of approximately 3,200 and 11,000 aggregate horsepower, respectively, that previously were used to provide compression services in our business.

As a result, we recorded impairments of compression equipment of $1.5 million and $5.1 million for the years ended December 31, 2022, and 2021, respectively.

The primary causes for these impairments were:

The primary circumstances supporting these impairments were:

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.

Estimated Useful Lives of Property and Equipment

Property and equipment is carried at cost.

The use of different assumptions and judgments in the calculation of depreciation, especially those involving useful lives, likely would result in significantly different net book values of our assets and results of operations.

Commitments and Contingencies

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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 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.

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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 currently are 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.

We estimate that the range of losses we could incur is from $0 to approximately $21.8 million, including penalties and interest.

As of December 31, 2021, we had 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 had challenged the applicability of the manufacturing exemption.

During August 2022, a Compromise and Settlement Agreement (“Agreement”) was entered into with the Comptroller for the period January 1, 2008, through March 31, 2018, related to such open audits.

Pursuant to an indemnification agreement between us and Energy Transfer, Energy Transfer paid all amounts due under the Agreement in full.

As a result, the $44.9 million accrued liability and $44.9 million related-party receivable from Energy Transfer was reduced to zero as of December 31, 2022.

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.

We maintain an allowance for credit losses for our trade accounts receivable 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 financial strength of our customers by reviewing the aging of their receivables owed to us, 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, 2022, we recognized a reversal of $0.7 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.

Favorable market conditions for customers, attributable to sustained increases in commodity prices, was the primary factor supporting the recorded decrease to the allowance for credit losses for the year ended December 31, 2022.

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 resulting from improved commodity prices was the primary factor supporting the recorded decrease to the allowance for credit losses for the year ended December 31, 2021.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis