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Item 7. Management’s Discussion and Analysis

2021-02-16 compared with 2020-02-18 · 226 added, 228 removed, 166 unchanged (73% of the section changed)

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Following the transactions described in further detail below, CDM Resource Management LLC (“CDM Resource”) and CDM Environmental & Technical Services LLC (“CDM E&T”), which together represent the CDM Compression Business (the “USA Compression Predecessor”), has been determined to be the historical predecessor of USA Compression Partners, LP (the “Partnership”) for financial reporting purposes.

The USA Compression Predecessor is considered the predecessor of the Partnership because Energy Transfer Equity LP (“ETE”), through its wholly owned subsidiary Energy Transfer Partners, L.L.C., (“ETP LLC”) controlled the USA Compression Predecessor prior to the transactions described below and obtained control of the Partnership through its acquisition of USA Compression GP, LLC, the general partner of the Partnership (the “General Partner”).

The closing of the Transactions occurred on April 2, 2018 (the “Transactions Date”) and has been reflected in the consolidated financial statements of the Partnership.

In October 2018, ETE and Energy Transfer Partners, L.P.

(“ETP”) completed the merger of ETP with a wholly owned subsidiary of ETE in a unit-for-unit exchange (the “ETE Merger”).

Following the closing of the ETE Merger, ETE changed its name to “Energy Transfer LP” (“ET LP”) and ETP changed its name to “Energy Transfer Operating, L.P.” (“ETO”).

Upon the closing of the ETE Merger, ETE contributed to ETO 100% of the limited liability company interests in the General Partner.

References herein to “ETO” refer to ETP for periods prior to the ETE Merger and ETO following the ETE Merger, and references to “ET LP” refer to ETE for periods prior to the ETE Merger and ET LP following the ETE Merger.

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements, the notes thereto, and the other financial information appearing elsewhere in this report.

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See Part I “Disclosure Regarding Forward-Looking Statements” and Part I, Item 1A “Risk Factors”.

All references in this section to the USA Compression Predecessor, as well as the terms “our,” “we,” “us” and “its” refer to the USA Compression Predecessor when used in a historical context or in reference to the periods prior to the Transactions Date, unless the context otherwise requires or where otherwise indicated.

All references in this section to the Partnership, as well as the terms “our,” “we,” “us” and “its” refer to USA

Compression Partners, LP, together with its consolidated subsidiaries, including the USA Compression Predecessor, when used in the present or future tense and for periods subsequent to the Transactions Date, unless the context otherwise requires or where otherwise indicated.

Discussion and analysis of our operating highlights and financial results of operations for the year ended December 31, 2018 compared to the year ended December 31, 2017 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” in our Annual Report on Form 10-K filed for the year ended December 31, 2018 with the SEC on February 19, 2019.

Discussion and analysis of our operating highlights and financial results of operations for the year ended December 31, 2019 compared to the year ended December 31, 2018 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, 2019 with the SEC on February 18, 2020.

We provide compression services in a number of shale plays throughout the U.S., including the Utica, Marcellus, Permian Basin, Delaware Basin, Eagle Ford, Mississippi Lime, Granite Wash, Woodford, Barnett, Haynesville, Niobrara and Fayetteville shales.

Demand for our services is driven by the domestic production of natural gas and crude oil.

as such, we have focused our activities in areas with attractive natural gas and crude oil production growth, which are generally found in these shale and unconventional resource plays.

According to studies promulgated by the U.S.

Energy Information Administration (“EIA”), the production and transportation volumes of these shale plays, in aggregate, are expected to increase over the long term due to the comparatively attractive economic returns versus returns achieved in many conventional basins.

As such, we have focused our activities in areas of attractive natural gas and crude oil production growth, which are generally found in these shale and unconventional resource plays.

According to studies promulgated by the EIA, the production and transportation volumes in these shale plays are expected to increase over the long term.

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

We believe we are well-positioned to meet these changing operating conditions due to the flexibility of our compression units.

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

While our business focuses largely on compression services serving infrastructure applications, including centralized natural gas gathering systems and processing facilities, which utilize large horsepower compression units, typically in shale plays, we also provide compression services in more mature conventional basins, including gas lift applications on crude oil wells targeted by horizontal drilling techniques.

Gas lift, a process by which natural gas is injected into the production tubing of an existing producing well, in order to reduce the hydrostatic pressure and allow the oil to flow at a higher rate, and other artificial lift technologies are critical to the enhancement of oil production from horizontal wells operating in tight shale plays.

Gas lift, a process by which natural gas is injected into the production tubing of

an existing producing well, in order to reduce the hydrostatic pressure and allow the oil to flow at a higher rate, and other artificial lift technologies are critical to the enhancement of oil production from horizontal wells operating in tight shale plays.

Recent Developments

2027 Senior Notes Issuance and Exchange

On March 7, 2019, the Partnership and its wholly owned finance subsidiary, USA Compression Finance Corp.

(“Finance Corp”) co-issued $750.0 million aggregate principal amount of senior notes due on September 1, 2027 (the “Senior Notes 2027”).

The Senior Notes 2027 accrue interest from March 7, 2019 at the rate of 6.875% per year.

Interest on the Senior Notes 2027 is payable semi-annually in arrears on each of March 1 and September 1, with the first such payment having occurred on September 1, 2019.

On December 18, 2019, the Partnership closed an exchange offer whereby holders of the Senior Notes 2027 exchanged all of the Senior Notes 2027 for an equivalent amount of senior notes (“Exchange Notes 2027”) registered under the Securities Act of 1933, as amended (“Securities Act”).

The Exchange Notes 2027 are substantially identical to the Senior Notes 2027, except that the Exchange Notes 2027 have been registered with the U.S.

Securities and Exchange Commission (“SEC”) and do not contain the transfer restrictions, restrictive legends, registration rights or additional interest provisions of the Senior Notes 2027.

2018 CDM Acquisition and Related Transactions

CDM Acquisition and Issuance of Class B Units

On the Transactions Date, we consummated the transactions contemplated by the Contribution Agreement dated January 15, 2018, pursuant to which, among other things, we acquired all of the issued and outstanding membership interests of the USA Compression Predecessor from ETO (the “CDM Acquisition”) in exchange for aggregate consideration of approximately $1.7 billion , consisting of (i) 19,191,351 common units representing limited partner interests in us (the “common units”), (ii) 6,397,965 Class B units representing limited partner interests in us (“Class B Units”) and (iii) $1.2 billion in cash (including customary closing adjustments).

On July 30, 2019, 6,397,965 Class B Units automatically converted into common units on a one-for-one basis, resulting in the issuance of 6,397,965 common units to ETO.

Following the conversion, there are no longer Class B Units outstanding.

General Partner Purchase Agreement

On the Transactions Date, and in connection with the closing of the CDM Acquisition, we consummated the transactions contemplated by the Purchase Agreement dated January 15, 2018, by and among ET LP, ETP LLC, USA Compression Holdings, LLC (“USA Compression Holdings”) and, solely for certain purposes therein, R/C IV USACP Holdings, L.P.

and ETO, pursuant to which, among other things, ET LP acquired from USA Compression Holdings (i) all of the outstanding limited liability company interests in the General Partner and (ii) 12,466,912 common units for cash consideration paid by ET LP to USA Compression Holdings equal to $250.0 million (the “GP Purchase”).

Upon the closing of the ETE Merger, ET LP contributed all of the interests in the General Partner and the 12,466,912 common units to ETO.

Equity Restructuring Agreement

On the Transactions Date, and in connection with the closing of the CDM Acquisition, we consummated the transactions contemplated by the Equity Restructuring Agreement dated January 15, 2018 (the “Equity Restructuring Agreement”), pursuant to which, among other things, the Partnership, the General Partner and ET LP agreed to cancel the Partnership’s Incentive Distribution Rights (“IDRs”) and convert the General Partner’s interest into a non-economic general partner interest, in exchange for the Partnership’s issuance of 8,000,000 common units to the General Partner (the “Equity Restructuring”).

In addition, at any time after one year following the Transactions Date, ET LP has the right to contribute (or cause any of its subsidiaries to contribute) to us all of the outstanding equity interests in any of its subsidiaries that owns the general partner interest in us in exchange for $10.0 million (the “GP Contribution”);

provided that the GP Contribution will occur automatically if at any time following the Transactions Date (i) ET LP or one of its subsidiaries (including ETO) owns, directly or indirectly, the general partner interest in us and (ii) ET LP and its subsidiaries (including ETO) collectively own less than 12,500,000 of our common units.

The CDM Acquisition, GP Purchase and Equity Restructuring are collectively referred to as the “Transactions.”

Series A Preferred Unit and Warrant Private Placement

On the Transactions Date, we completed a private placement of $500 million in the aggregate of (i) newly authorized and established Series A Preferred Units representing limited partner interests in us (the “Preferred Units”) and (ii) warrants to purchase common units (the “Warrants”) pursuant to a Series A Preferred Unit and Warrant Purchase Agreement dated January 15, 2018, between the Partnership and certain investment funds managed or advised by EIG Global Energy Partners and FS Energy and Power Fund (collectively, the “Preferred Unitholders”).

We issued 500,000 Preferred Units with a face value of $1,000 per Preferred Unit and issued two tranches of Warrants to the Preferred Unitholders, which included Warrants to purchase 5,000,000 common units with a strike price of $17.03 per unit and 10,000,000 common units with a strike price of $19.59 per unit.

The Warrants may be exercised by the holders thereof at any time beginning April 2, 2019 and before April 2, 2028.

2026 Senior Notes Issuance and Exchange

On March 23, 2018, the Partnership and Finance Corp co-issued $725.0 million aggregate principal amount of senior notes due on April 1, 2026 (the “Senior Notes 2026”).

The Senior Notes 2026 accrue interest from March 23, 2018 at the rate of 6.875% per year.

Interest on the Senior Notes 2026 is payable semi-annually in arrears on each of April 1 and October 1 , with the first such payment having occurred on October 1, 2018.

On January 14, 2019, the Partnership closed an exchange offer whereby holders of the Senior Notes 2026 exchanged all of the Senior Notes 2026 for an equivalent amount of senior notes (“Exchange Notes 2026”) registered under the Securities Act.

The Exchange Notes 2026 are substantially identical to the Senior Notes 2026, except that the Exchange Notes 2026 have been registered with the SEC and do not contain the transfer restrictions, restrictive legends, registration rights or additional interest provisions of the Senior Notes 2026.

Credit Agreement Amendment and Restatement

On the Transactions Date, we entered into the Sixth Amended and Restated Credit Agreement (the “Credit Agreement”) by and among the Partnership, as borrower, USAC OpCo 2, LLC, USAC Leasing 2, LLC, USA Compression Partners, LLC, USAC Leasing, LLC, CDM Resource, CDM E&T and Finance Corp, the lenders party thereto from time to time, JPMorgan Chase Bank, N.A., as agent and a letter of credit (“LC”) issuer, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Regions Capital Markets, a division of Regions Bank, RBC Capital Markets and Wells Fargo Bank, N.A., as joint lead arrangers and joint book runners, Barclays Bank PLC, Regions Bank, RBC Capital Markets and Wells Fargo Bank, N.A., as syndication agents, and MUFG Union Bank, N.A., SunTrust Bank and The Bank of Nova Scotia, as senior managing agents.

The Credit Agreement amended and restated

that certain Fifth Amended and Restated Credit Agreement, dated as of December 13, 2013, as amended (the “Fifth A&R Credit Agreement”).

The Credit Agreement amended the Fifth A&R Credit Agreement to, among other things, (i) increase the borrowing capacity under the Credit Agreement from $1.1 billion to $1.6 billion (subject to availability under a borrowing base), (ii) extend the termination date (and the maturity date of the obligations thereunder) from January 6, 2020 to April 2, 2023, (iii) subject to the terms of the Credit Agreement, permit up to $400.0 million of future increases in borrowing capacity, (iv) modify the leverage ratio covenant to be 5.5 to 1.0 through the end of the fiscal quarter ending December 31, 2019, and 5.0 to 1.0 thereafter and (v) increase the applicable margin for eurodollar borrowings to range from 2.00% to 2.75% , depending on our leverage ratio, all as more fully set forth in the Credit Agreement.

Credit Agreement Amendment

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

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

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

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

General Trends and Outlook

Natural gas compression is a critical part of the natural gas value chain, facilitating the movement of natural gas throughout the domestic pipeline system.

Our business is driven in part by the increasing volumes of natural gas being produced in this country and the areas and conditions in which it is produced.

Compression is generally required throughout the life of a producing basin;

areas of moderating or declining natural gas production require compression to achieve minimum pressure to enter gathering and transmission pipelines.

Without compression, natural gas will generally not move through a pipeline and can thus become stranded in a given area.

A significant amount of our assets are utilized in natural gas infrastructure applications, primarily in centralized natural gas gathering systems and processing facilities.

Rather than being more closely tied to the wellhead impact of commodity price variability, these applications generally tend to be characterized by a long-term investment horizon on the part of our customers;

as such, we have generally experienced stability in rates and higher sustained utilization rates relative to other businesses more tied to drilling activity and wellhead economics.

In addition to assets utilized in infrastructure applications, a small portion of our fleet horsepower is used for gas lift applications in connection with crude oil production using horizontal drilling techniques.

Increasing levels of domestic natural gas production as a general rule require more installed compression in order to move the gas through the pipeline system and to the ultimate end user, whether that user be commercial, industrial or residential in nature.

The EIA’s January 2020 Short-Term Energy Outlook (“EIA Outlook”) expects dry natural gas production to increase to 94.7 billion cubic feet per day (“Bcf/d”) in 2020 (an increase of 3% over the record high production of 92.0 Bcf/d in 2019) and then decline to 94.1 Bcf/d in 2021.

The EIA’s expected growth in natural gas production for 2020 is largely in response to improved drilling efficiency and cost reductions, higher associated gas production from oil-directed rigs, and increased takeaway pipeline capacity from the Appalachian and Permian production regions.

Forecast natural gas production growth is also supported by planned expansions in liquefied natural gas (“LNG”) capacity and increased pipeline exports to Mexico.

The decline in natural gas production in 2021 is in response to a forecast of low natural gas spot prices in 2020 that reduces drilling activity in the Appalachian Basin.

Henry Hub natural gas spot prices averaged $2.57 per million British thermal units (“MMBtu”) in 2019, down from $3.16/MMBtu in 2018.

The EIA Outlook expects Henry Hub prices to decrease to an average of to $2.33/MMBtu in 2020 and then increase to an average of $2.54/MMBtu in 2021.

Recently, overall domestic natural gas production has increased significantly to meet the growing demand domestically as well as abroad, through, among other things, LNG exports.

Over the last ten years, the EIA Outlook reports that dry natural gas production has increased by 63%, or approximately 5% annually.

This increase has caused meaningful demand for our services as operators have built out the necessary infrastructure to move, process and consume these increased volumes of natural gas.

While the EIA expects the overall trajectory of natural gas production to moderate, we believe demand for compression services will continue to increase because, as high-decline shale wells begin to age and production is tempered, new sources of natural gas will be required in order to meet demand.

Although we cannot predict any possible changes in demand with reasonable certainty, we expect demand for our compression services to remain strong throughout 2020.

Particularly in the Permian and Delaware Basins, natural gas tends to be produced alongside crude oil, and is thus known as “associated” gas.

Due to many factors, the Permian and Delaware Basins have experienced significant activity levels in recent years, and along with the production of crude oil, the EIA has reported a 157% increase in associated natural gas produced in those areas since December 2015 and a 24% increase in December 2019 as compared to December 2018.

Because customers must handle the associated natural gas, compression has been a critical part of the equation for our customers to be able to produce the desired crude oil and move it to market.

Given the relatively attractive economics of producing crude oil in the Permian and Delaware Basins, these areas are expected to continue to be important sources of crude oil, along with the associated natural gas,

in the coming years.

As crude oil production grows in these areas, there will be demand for additional compression to handle the associated natural gas.

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.

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

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

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

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

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

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

While our business is focused on providing compression services and does not have any direct exposure to commodity prices, we have indirect exposure to commodity prices as overall levels of activity across the energy industry are influenced by the commodity price environment.

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

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

The EIA’s January 2021 Short-Term Energy Outlook (“EIA Outlook”) estimates that annual U.S.

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

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

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

The EIA Outlook forecasts total U.S.

crude oil production to average 13.3 million barrels per day (“bbl/d”) in 2020, up 9% from 2019 average production of 12.2 million bbl/d, which was the highest annual average on record.

Average production in 2021 is expected to continue to increase to 13.7 million bbl/d.

Almost all of the production growth within the U.S.

is expected to be attributable to onshore production within the lower 48 states, and particularly from the Permian and Delaware Basins in Texas and New Mexico, which account for 0.8 million bbl/d and 0.4 million bbl/d of the increases in 2020 and 2021, respectively.

Favorable geology and technological and operational improvements have allowed the Permian and Delaware Basins to become one of the most prolific regions for oil production.

The EIA Outlook forecasts a slowing rate of increases in year-over-year crude oil production, primarily as a result of a decline in the deployment of drilling rigs over the past year, a trend which the EIA expects will continue through 2020 and into 2021.

Despite the decline in the number of drilling rigs, the EIA forecasts production will continue to grow as rig efficiency and well-level productivity rise.

As crude oil production grows, we expect natural gas production to grow as well.

For 2020, the EIA’s West Texas Intermediate (“WTI”) crude oil price forecast rises by $2 per barrel (“/bbl”) from 2019 levels to average $59/bbl for the year.

For 2021, the EIA expects WTI prices will rise further to an average of $62/bbl.

The EIA expects oil prices above $60/bbl to contribute to rising crude oil production, as producers will be able to fund drilling programs through cash flow and other funding sources, despite a somewhat more restrictive capital market.

Daily and monthly average crude oil prices could vary significantly from annual average forecasts due to global economic developments and geopolitical events in the coming months that could have the potential to push oil prices higher or lower than forecast.

Uncertainty remains regarding the duration of, and members’ adherence to, the current Organization of the Petroleum Exporting Countries (“OPEC”) production cuts, which could influence prices in either direction.

We believe the recent stability of crude oil prices during 2019 and 2018 has allowed for the continued build-out of related large-scale natural gas infrastructure projects, particularly in the Permian and Delaware Basins.

Our total fleet horsepower has increased by approximately 86,000 horsepower as of December 31, 2019 compared to December 31, 2018 , while maintaining horsepower utilization at approximately 94% .

We intend to prudently deploy capital for new compressor units in 2020 .

We have already entered into commitments to purchase all of our large horsepower compressor units for the first half of 2020 , as the lead time to build these units is approximately six months.

Most of our 2020 purchases of large horsepower compressor units are already committed to customers or under contract with customers.

Factors Affecting the Comparability of our Operating Results

As described above, the USA Compression Predecessor has been deemed to be the accounting acquirer of the Partnership in accordance with applicable business combination accounting guidance, and, as a result, the historical financial statements reflect the results of operations of the USA Compression Predecessor for periods prior to the Transactions Date.

Therefore, the Partnership’s future results of operations may not be comparable to the USA Compression Predecessor’s historical results of operations for the reasons described below.

The revenues generated by the Partnership consist of the revenues from compression services as well as related ancillary revenues, including those generated by the USA Compression Predecessor, subsequent to the Transactions Date.

The historical revenues included within the Partnership’s financial statements relating to periods prior to the Transactions Date are only comprised of those of the USA Compression Predecessor.

Additionally, selling, general and administrative expenses will not be comparable to the selling, general and administrative expenses previously allocated to the USA Compression Predecessor by ETO.

The Partnership’s selling, general and administrative expenses will also not be comparable to the historical USA Compression Predecessor’s selling, general and administrative expenses because the Partnership’s selling, general and administrative expenses will include the expenses associated with being a publicly traded master limited partnership, whereas the USA Compression Predecessor was operated as a component of a larger company.

The Partnership incurs interest on its long-term debt and makes distributions to its unitholders.

The USA Compression Predecessor held no long-term debt and had no outstanding publicly traded equity securities.

As a result, the Partnership’s long-term debt and related charges will not be comparable to the USA Compression Predecessor’s historical long-term debt and related charges.

During the year ended December 31, 2018, we recorded $4.2 million in transaction expenses, $3.2 million in severance expenses and $6.8 million in unit-based compensation expense, all of which related to the CDM Acquisition.

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

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

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

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

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

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

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

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

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

Variables such as takeaway capacity, flaring considerations, reservoir pressure and flow rates, high switching costs associated with large horsepower compressors (borne by our customers), and specific company dynamics may all factor into producers’ decisions with respect to their existing production.

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.

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

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

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

For example, while the EIA expects a decline in natural gas production for 2021 due to a decrease in the usage of natural gas in the electric power generation sector, as a result of relatively higher natural gas prices (versus coal) and increased power generation from renewables, these decreases are expected to be partially offset by other uses, including increased liquefied natural gas exports as well as increased pipeline exports to Mexico.

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

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

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

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

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

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

On the whole, we believe the longer-term outlook for natural gas fundamentals remains positive, as market signs, including natural gas futures market, point to a more balanced gas market through 2021.

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

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

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

While we anticipate that the combination of commodity prices and demand may likely have an impact on activity levels in both the upstream and midstream sectors, we cannot predict the ultimate magnitude of that impact on our business and expect it to be varied across our operations, depending on the region, customer, nature of compression application, contract term and other factors.

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

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,

Year Ended December 31, Percent

2020 2019 Change

Fleet horsepower (at period end) (1) 3,726,181 3,682,968 1.2 %

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(1) Fleet horsepower is horsepower for compression units that have been delivered to us (and excludes units on order).

As of December 31, 2019 , we had 56,500 horsepower on order for delivery during 2020 .

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

Calculated as the average of the result of dividing the contractual monthly rate for all units at the end of each month in the period by the sum of the revenue generating horsepower at the end of each month in the period.

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

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

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Average horsepower utilization based on revenue generating horsepower and fleet horsepower was 84.5% and 89.8% for the years ended December 31, 2020 and 2019, respectively.

The 2.4% increase in fleet horsepower as of December 31, 2019 compared to December 31, 2018 was attributable to compression units added to our fleet to meet incremental demand by new and current customers for our compression services.

The 1.5% increase in revenue generating horsepower as of December 31, 2019 compared to December 31, 2018 was primarily due to organic growth in our large horsepower fleet, while the 1.5% decrease in revenue generating compression units was primarily due to returns of small horsepower compression units from our customers, partially offset by the organic growth of large horsepower compression units and a 4.8% increase in average horsepower per revenue generating compression unit during the year ended December 31, 2019 .

The 3.5% increase in average revenue per revenue generating horsepower per month for the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily due to contracts on new compression units as well as selective price increases on the existing fleet.

The 3.0% increase in average horsepower utilization and 2.6% increase in average horsepower utilization based on revenue generating horsepower and fleet horsepower during the year ended December 31, 2019 compared to the year ended December 31, 2018 were primarily attributable to increased demand for our services driven by increased U.S.

production of crude oil and natural gas.

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

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

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

crude oil and natural gas activity.

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

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

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

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

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

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

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

crude oil and natural gas activity.

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

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

Average horsepower utilization based on revenue generating horsepower and fleet horsepower decreased to 84.5% for the year ended December 31, 2020 compared to 89.8% for the year ended December 31, 2019.

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

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

crude oil and natural gas activity.

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,

Year Ended December 31, Percent

2020 2019 Change

Contract operations $ 644,194 $ 664,162 (3.0) %

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Cost of operations, exclusive of depreciation and amortization 205,939 227,303 (9.4) %

Gross operating margin

Other operating and administrative costs and expenses:

Selling, general and administrative

Depreciation and amortization 238,968 231,447 3.2 %

Selling, general and administrative 59,981 64,397 (6.9) %

Loss on disposition of assets 146 940 (84.5) %

Impairment of compression equipment 8,090 5,894 37.3 %

Total other operating and administrative costs and expenses

Operating income

Impairment of goodwill 619,411 — *

Total costs and expenses 1,132,535 529,981 *

Operating income (loss) (464,852) 168,384 *

Other income (expense):

Interest expense, net (128,633) (127,146) 1.2 %

Other 86 80 7.5 %

Total other expense (128,547) (127,066) 1.2 %

Net income (loss) before income tax expense (benefit)

Income tax expense (benefit)

Net income (loss) before income tax expense (593,399) 41,318 *

Income tax expense 1,333 2,186 (39.0) %

Net income (loss) $ (594,732) $ 39,132 *

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* Not meaningful.

Contract operations revenue .

The $117.3 million increase in contract operations revenue for the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily attributable to the first three months of 2018 including only the results of the USA Compression Predecessor prior to the Transactions Date.

Average revenue generating horsepower increased 18.8% for the year ended December 31, 2019 compared to the year ended December 31, 2018 primarily due to the inclusion of the Partnership’s historical assets subsequent to the Transactions Date.

Additionally, we experienced a year-to-year increase in demand for our compression services driven by increased U.S.

production of crude oil and natural gas as average revenue per revenue generating horsepower per month increased 3.5% to $16.65 for the year ended December 31, 2019 compared to $16.09 for the year ended December 31, 2018 .

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

crude oil and natural gas activity.

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

Our contract operations revenue was not

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

Additionally, average revenue per revenue generating horsepower per month associated with our compression services provided on a month-to-month basis did not significantly differ from the average revenue per revenue generating horsepower per month associated with our compression services provided under contracts in their primary term during the period.

Parts and service revenue .

The $6.2 million decrease in parts and service revenue for the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily attributable to a decrease in maintenance work performed on units at our customers’ locations that are outside the scope of our core maintenance activities and offered as a courtesy to our customers, and freight and crane charges that are directly reimbursable by customers.

The $3.1 million decrease in parts and service revenue for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily attributable to a reduction in maintenance work performed on units at our customers’ locations that are outside the scope of our core maintenance activities and offered as a courtesy to our customers, and freight and crane charges that are directly reimbursable by customers.

Demand for retail parts and services fluctuates from period to period based on the varying needs of our customers.

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Related party revenue was earned through related party transactions in the ordinary course of business with various affiliated entities of ETO.

The $2.9 million increase in related party revenue for the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily attributable to additional compression and related ancillary services demand from such affiliates.

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

Cost of operations, exclusive of depreciation and amortization.

The $12.6 million increase in cost of operations for the year ended December 31, 2019 compared to the year ended December 31, 2018 was driven by (1) a $21.1 million increase in direct expenses, such as parts and fluids expenses, and (2) a $5.3 million increase in direct labor expenses, for which both increases were primarily attributable to the first three months of 2018 including only the results of the USA Compression Predecessor prior to the Transactions Date.

These increases were partially offset by (1) a $5.0 million decrease in ad valorem tax expense, due primarily to prior year refunds received during the year ended December 31, 2019 , (2) a $3.9 million decrease in retail parts and service expenses, which have a corresponding decrease in parts and service revenue, (3) a $3.9 million decrease in outside maintenance services and (4) a $1.1 million decrease in other indirect expenses.

Gross operating margin.

The $101.4 million increase in gross operating margin for the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily due to an increase in revenues, partially offset by an increase in cost of operations, exclusive of depreciation and amortization.

These increases were primarily due to the addition of the Partnership’s historical assets after the Transactions Date and higher demand for our services driven by increased U.S.

production of crude oil and natural gas.

Selling, general and administrative expense .

The $4.6 million decrease in selling, general and administrative expense for the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily attributable to (1) a $5.9 million decrease in transaction expenses and severance expenses, (2) a $3.2 million decrease in other miscellaneous expenses, partially offset by (1) a $2.4 million increase in payroll and benefits expenses and (2) a $1.9 million increase in professional fees expenses.

Transaction expenses and severance expenses were lower during the year ended December 31, 2019 primarily due to the Transactions completed during the year ended December 31, 2018 .

Other miscellaneous expenses decreased primarily due to the expense allocation to the USA Compression Predecessor ending after the Transactions Date.

Payroll and benefits expenses and professional fees increased due to the addition of the Partnership’s historical assets after the Transactions Date.

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

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

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

Depreciation and amortization expense .

The $17.8 million increase in depreciation and amortization expense for the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily the result of the addition of the Partnership’s historical assets on the Transactions Date and assets recently placed in service.

Loss on disposition of assets .

The $12.0 million decrease in net losses on disposition of assets during the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily attributable to disposals of various property and equipment by the USA Compression Predecessor prior to the Transactions Date during the year ended December 31, 2018 .

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

Selling, general and administrative expense .

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

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

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

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

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

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

Impairment of compression equipment .

The $5.9 million and $8.7 million impairments of compression equipment during the years ended December 31, 2019 and 2018 , respectively, were primarily the result of our evaluations of the future deployment of our idle fleet under then-current market conditions.

Our evaluations determined that due to certain performance characteristics of the impaired equipment, such as excessive maintenance costs and the inability of the equipment to meet then-current emissions standards without excessive retrofitting costs, this equipment was unlikely to be accepted by customers under then-current market conditions.

As a result of our evaluations during the years ended December 31, 2019 and 2018 , we determined to retire and re-utilize the key components of 33 and 103 compression units, respectively, with a total of approximately 11,000 and 33,000 horsepower, respectively, that had been previously used to provide compression services in our business.

The $8.1 million and $5.9 million impairments of compression equipment during the years ended December 31, 2020 and 2019, respectively, were primarily the result of our evaluations of the future deployment of our idle fleet under current market conditions.

The primary causes for these impairments were:

(i) units were not considered marketable in the foreseeable future, (ii) units were subject to excessive maintenance costs or (iii) units were unlikely to be accepted by customers due to certain performance characteristics of the unit, such as the inability to meet current quoting criteria without excessive retrofitting costs.

These compression units were written down to their respective estimated salvage values, if any.

As a result of our evaluations during the years ended December 31, 2020 and 2019, we determined to retire 37 and 33 compression units, respectively, with a total of approximately 15,000 and 11,000 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.

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

Interest expense, net .

The $48.8 million increase in interest expense, net for the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily attributable to (1) higher overall debt balances as the USA Compression Predecessor had no borrowings prior to the Transactions Date, (2) interest expense incurred on $750.0 million of 6.875% senior notes issued in March 2019, which were used to reduce borrowings under the Credit Agreement, and (3) higher interest rates on borrowings under the Credit Agreement.

These increases were partially offset by the decrease in borrowings under the Credit Agreement.

The weighted average interest rate applicable to borrowings under the Credit Agreement was 4.84% for the year ended December 31, 2019 compared to 4.69% for the period from the Transactions Date to December 31, 2018 .

Average outstanding

borrowings under the Credit Agreement were $493.3 million for the year ended December 31, 2019 compared to $984.7 million for the period from the Transactions Date to December 31, 2018 .

Income tax expense (benefit) .

During the years ended December 31, 2019 and 2018 , we recognized income tax expense of $2.2 million and an income tax benefit of $2.5 million , respectively, primarily related to current and deferred taxes associated with Texas Margin Tax.

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

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

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

Income tax expense.

The $0.9 million decrease in income tax expense for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily related to deferred taxes associated with the Texas Margin Tax.

Other Financial Data

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

Year Ended December 31,

Year Ended December 31, Percent

Other Financial Data:

Gross operating margin

Gross operating margin percentage (2)

(1) 2020 2019 Change

Gross margin $ 222,776 $ 239,615 (7.0) %

Adjusted gross margin

$ 461,744 $ 471,062 (2.0) %

Adjusted gross margin percentage (2)

69.2 % 67.5 % 2.5 %

Adjusted EBITDA

$ 413,898 $ 419,640 (1.4) %

Adjusted EBITDA percentage (2)

62.0 % 60.1 % 3.2 %

$ 220,766 $ 221,868 (0.5) %

DCF Coverage Ratio

Cash Coverage Ratio (3)

1.09 x 1.13 x (3.5) %

Cash Coverage Ratio 1.10 x 1.14 x (3.5) %

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Gross operating margin, Adjusted EBITDA, DCF, DCF Coverage Ratio and Cash Coverage Ratio are all non-GAAP financial measures.

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

Definitions of each measure, as well as reconciliations of each measure to its most directly comparable financial measure(s) calculated and presented in accordance with GAAP, can be found under the caption “Non-GAAP Financial Measures” in Part II, Item 6 “Selected Financial Data”.

Gross operating margin percentage and Adjusted EBITDA percentage are calculated as a percentage of revenue.

Distributions for the year ended December 31, 2018 reflect only three quarters of distributions as the USA Compression Predecessor did not pay distributions prior to the Transactions Date.

DCF, however, reflects a full year of DCF.

On a pro forma basis, both the DCF Coverage Ratio and Cash Coverage Ratio for the year ended December 31, 2018 were 1.10x when using comparable three quarters of DCF and three quarters of distributions.

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

Gross margin.

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

Adjusted gross margin.

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

Adjusted EBITDA.

The $99.2 million , or 30.9% , increase in Adjusted EBITDA for the year ended December 31, 2019 compared to the year ended December 31, 2018 was driven by the addition of the Partnership’s historical assets after the Transactions Date, which was the primary cause of a $101.4 million increase in gross operating margin.

This increase was partially offset by a $2.2 million increase in selling, general and administrative expenses, excluding transaction expenses, unit-based compensation expense and other non-recurring charges.

The $44.1 million , or 24.8% , increase in DCF during the year ended December 31, 2019 compared to the year ended December 31, 2018 was driven by (1) the addition of the Partnership’s historical assets after the Transactions Date, which was the primary cause of a $101.4 million increase in gross operating margin, and (2) a $2.9 million decrease in maintenance capital expenditures.

These increases were partially offset by (1) a $46.2 million increase in cash interest expense, net, (2) a $12.3 million increase in distributions on the Preferred Units and (3) a $2.2 million increase in selling, general and administrative expenses, excluding transaction expenses, unit-based compensation expense and other non-recurring charges.

The $5.7 million decrease in Adjusted EBITDA for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to a $9.3 million decrease in Adjusted gross margin, partially offset by a $3.2 million decrease in selling, general and administrative expenses, excluding unit-based compensation expense, severance charges and transaction expenses.

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

Coverage Ratios .

The decrease s in DCF Coverage Ratio and Cash Coverage Ratio for the year ended December 31, 2019 compared to the year ended December 31, 2018 were attributable to the fact that distributions for year ended December 31, 2018 reflect only three quarters of distributions, as the USA Compression Predecessor did not pay distributions prior to the Transactions Date, as well as additional distributions in 2019 due to the conversion of 6,397,965 Class B Units, which did not participate in distributions, to common units on a one-for-one basis on July 30, 2019.

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

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.

Our principal sources of liquidity include cash generated by operating activities, borrowings under the Credit Agreement and issuances of debt and equity securities, including under the DRIP.

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 through 2020 .

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.

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

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

Covenants in the Credit Agreement and other debt instruments require that we maintain certain leverage ratios, and if we predict that we may violate those covenants in the future we could:

(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.

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

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

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.

To fund a portion of the CDM Acquisition, on March 23, 2018 the Partnership and Finance Corp co-issued $725.0 million in aggregate principal amount of the Senior Notes 2026 and, on the Transactions Date, the Partnership issued the Preferred Units and Warrants for aggregate gross consideration of $500.0 million .

The transaction fees associated with these issuances were financed with borrowings under the Credit Agreement.

Also on the Transactions Date, the borrowing capacity under the Credit Agreement was increased from $1.1 billion to $1.6 billion .

In addition, on March 7, 2019, the Partnership and Finance Corp co-issued $750.0 million aggregate principal amount of the Senior Notes 2027 and used the net proceeds to reduce our outstanding borrowings under the Credit Agreement.

We are not aware of any regulatory changes or environmental liabilities that we currently expect to have a material impact on our current or future operations.

Please see “Capital Expenditures” below.

The following table summarizes our sources and uses of cash for the years ended December 31, 2019 and 2018 (in thousands):

Year Ended December 31,

Net cash provided by operating activities

Net cash used in investing activities

Net cash provided by (used in) financing activities

Net cash provided by operating activities .

The $74.2 million increase in net cash provided by operating activities for the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily due to a $58.7 million increase in net income, as adjusted for non-cash items, and changes in other working capital.

Net cash used in investing activities .

The $635.2 million decrease in net cash used in investing activities for the year ended December 31, 2019 compared to the year ended December 31, 2018 was primarily due to (1) $1.2 billion of cash paid, offset by $710.5 million of cash assumed, each as part of the CDM Acquisition for the year ended December 31, 2018 , (2) a $95.4 million decrease in capital expenditures for purchases of new compression units, related equipment and reconfiguration costs, (3) a $15.0 million increase in proceeds from disposition of property and equipment and (4) a $3.8 million increase in insurance proceeds received during the year ended December 31, 2019 for compression units previously damaged.

Net cash provided by (used in) financing activities .

Net cash used in financing activities for the year ended December 31, 2019 was $156.2 million compared to net cash provided by financing activities of $549.4 million for the year ended December 31, 2018 .

This change was primarily due to (1) $479.1 million of net proceeds received during the year ended December 31, 2018 for the issuance of Preferred Units and Warrants used to partially fund the CDM Acquisition, (2) an increase of $51.9 million in cash distributions paid on common units, as the USA Compression Predecessor did not pay distributions prior to the Transactions Date, (3) an increase of $24.5 million of cash distributions paid on Preferred Units as they were not outstanding prior to the Transactions Date, (4) a decrease in net borrowings of $127.3 million for the year ended December 31, 2019 , as additional borrowings for the year ended December 31, 2018 were made primarily to pay fees and expenses related to the CDM Acquisition, and (5) $28.5 million

in intercompany contributions received by the USA Compression Predecessor for the year ended December 31, 2018 from its former parent company.

Capital Expenditures

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We currently plan to spend approximately $22.0 million in maintenance capital expenditures during 2021, including parts consumed from inventory.

Given our growth objectives and anticipated demand from our customers we anticipate that we will continue to make expansion capital expenditures.

Without giving effect to any equipment we may acquire pursuant to any future acquisitions, we currently have budgeted between $30.0 million and $40.0 million in expansion capital expenditures during 2021.

Our expansion capital expenditures for the years ended December 31, 2020 and 2019 were $95.6 million and $170.3 million, respectively.

The following table summarizes our sources and uses of cash for the years ended December 31, 2020 and 2019 (in thousands):

Year Ended December 31,

Net cash provided by operating activities $ 293,198 $ 300,580

Net cash used in investing activities (105,099) (144,490)

Net cash used in financing activities (188,107) (156,179)

Net cash provided by operating activities .

The $7.4 million decrease in net cash provided by operating activities for the year ended December 31, 2020 compared to the year ended December 31, 2019 was primarily due to a $5.3 million decrease in net income, as adjusted for non-cash items, and changes in other working capital.

Net cash used in investing activities .

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

Net cash used in financing activities .

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

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

Revolving Credit Facility

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As of February 11, 2021, we had outstanding borrowings under the Credit Agreement of $498.2 million.

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

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

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

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

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

We expect to remain in compliance with our covenants under the Credit Agreement throughout 2021.

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For a more detailed description of the Credit Agreement including the covenants and restrictions contained therein, please refer to Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.

On March 7, 2019, the Partnership and Finance Corp co-issued $750.0 million aggregate principal amount of senior notes due on September 1, 2027 (the “Senior Notes 2027”).

The Senior Notes 2027 accrue interest from March 7, 2019 at the rate of 6.875% per year.

Interest on the Senior Notes 2027 is payable semi-annually in arrears on each of March 1 and September 1, with the first such payment having occurred on September 1, 2019.

The Exchange Notes 2027 are substantially identical to the Senior Notes 2027, except that the Exchange Notes 2027 have been registered with the SEC and do not contain the transfer restrictions, restrictive legends, registration rights or additional interest provisions of the Senior Notes 2027.

See Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data” for information regarding the Senior Notes.

Distribution Reinvestment Plan

As of December 31, 2020, we had $725.0 million and $750.0 million aggregate principal amount outstanding on our Senior Notes 2026 and Senior Notes 2027, respectively.

The Senior Notes 2026 are due on April 1, 2026 and accrue interest at the rate of 6.875% per year.

Interest on the Senior Notes 2026 is payable semi-annually in arrears on each of April 1 and October 1.

The Senior Notes 2027 are due on September 1, 2027 and accrue interest at the rate of 6.875% per year.

Interest on the Senior Notes 2027 is payable semi-annually in arrears on each of March 1 and September 1.

For more detailed descriptions of the Senior Notes 2026 and Senior Notes 2027, please refer to Note 10 to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.

During the years ended December 31, 2020 and 2019, distributions of $1.9 million and $1.0 million, respectively, were reinvested under the DRIP resulting in the issuance of 188,695 and 60,584 common units, respectively.

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Payments Due by Period

Contractual Obligations

Less than 1 year

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

Long-term debt (1)

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

Interest on long-term debt obligations (2)

Equipment and capital purchases (3)

676,030 119,607 225,563 202,813 128,047

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

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$ 2,656,075 $ 124,415 $ 707,626 $ 209,723 $ 1,614,311

________________________

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

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

Represents commitments for new compression units that are being fabricated and is a component of our overall projected expansion capital expenditures during 2020 of $110.0 million to $120.0 million .

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

Effects of Inflation .

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

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

Off-Balance Sheet Arrangements

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We base our estimates on historical experience, available information and various other assumptions we believe to be reasonable under the circumstances.

On an ongoing basis, we evaluate our estimates;

On an ongoing basis,

we evaluate our estimates;

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

The accounting policies that

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

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

Revenue Recognition

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

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

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

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

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Due to the imprecise nature of these projections and assumptions, actual results can, and often do, differ from our estimates.

If the growth assumptions embodied in the current year impairment testing prove inaccurate, we could incur an impairment charge in the future.

As of December 31, 2019 , the Partnership had $619.4 million of goodwill, of which $366.0 million was determined as part of the purchase price allocation to the Partnership’s assets acquired by the USA Compression Predecessor.

As of October 1, 2019 and 2018 , we performed a qualitative assessment of relevant events and circumstances potentially indicating the likelihood of goodwill impairment.

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.

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

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

Upon completion of our qualitative assessment, we concluded that it is not more likely than not that the fair value of our single reporting unit was less than its carrying value and that our goodwill was not impaired for the years ended December 31, 2019 and 2018 .

One key assumption for the measurement of goodwill impairment is management’s estimate of future cash flows and EBITDA.

These estimates are based on the annual budget for the upcoming year and forecasted amounts for multiple subsequent years.

The annual budget process is typically completed near the annual goodwill impairment testing date, and management uses the most recent information for the annual impairment tests.

The forecast is also subjected to a comprehensive update annually in conjunction with the annual budget process and is revised periodically to reflect new information and/or revised expectations.

As discussed above, estimates of fair value can be affected by a variety of external and internal factors.

Volatility in crude oil prices can cause disruptions in global energy industries and markets.

Potential events or circumstances that could reasonably be expected to negatively affect the key assumptions we used in estimating the fair value of our reporting unit 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.

We continue to monitor the $619.4 million balance of goodwill and if the estimated fair value of our reporting unit declines due to any of these or other factors, we may be required to record future goodwill impairment charges.

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

Long-Lived Assets

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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, 2019 and 2018 , we evaluated the future deployment of our idle fleet under then-current market conditions and determined to retire and re-utilize key components of 33 and 103 compressor units, respectively, or approximately 11,000 and 33,000 horsepower, respectively, that were previously used to provide services in our business.

As a result, we recorded $5.9 million and $8.7 million in impairment of compression equipment for the years ended December 31, 2019 and 2018 , respectively.

The primary causes for this impairment 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 then-current quoting criteria without excessive retrofitting costs.

For the years ended December 31, 2020 and 2019, we evaluated the future deployment of our idle fleet under current market conditions and determined to retire 37 and 33 compressor units, respectively, for a total of approximately 15,000 and 11,000 horsepower, respectively, that were previously used to provide compression services in our business.

As a result, we recorded impairments of compression equipment of $8.1 million and $5.9 million for the years ended December 31, 2020 and 2019, respectively.

The primary causes for these impairments were:

These compression units were written down to their respective estimated salvage values, if any.

Allowances and Reserves

We maintain an allowance for doubtful accounts based on specific customer collection issues and historical experience.

The determination of the allowance for doubtful accounts requires us to make estimates and judgments regarding our customers’ ability

to pay amounts due.

On an ongoing basis, we conduct an evaluation of the financial strength of our customers based on payment history, the overall business climate in which our customers operate and specific identification of customer bad debt and make adjustments to the allowance as necessary.

Allowance for Credit Losses

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

Our determination of the allowance for credit losses requires us to make estimates and judgments regarding our customers’ ability to pay amounts due and is the same process for both of our financial assets as they have similar risk characteristics.

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

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

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Recent Accounting Pronouncements

For discussion on the adoption of Accounting Standards Update 2016-02 Leases and other specific recent accounting pronouncements affecting us, please see Note 2 and Note 18 , respectively, to our consolidated financial statements in Part II, Item 8 “Financial Statements and Supplementary Data”.

Please see Part II, Item 8 “Financial Statements and Supplementary Data”, Note 2 for discussion on the adoption of Accounting Standards Update 2016-13 Financial Instruments – Credit Losses (“Topic 326”):

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

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