What changed in this filing

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Item 1. Business

2021-02-16 compared with 2020-02-18 · 117 added, 144 removed, 207 unchanged (56% of the section changed)

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.

All references in this report 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.

We are a growth-oriented Delaware limited partnership, and we believe that we are one of the largest independent providers of natural gas compression services in the United States (“U.S.”) in terms of total compression fleet horsepower.

USA Compression Partners, LP has been providing compression services since 1998 and completed its initial public offering in January 2013.

The USA Compression Predecessor has been providing compression services since 1997 and was a wholly owned indirect subsidiary of ETO prior to the Transactions Date.

As of December 31, 2019 , we had 3,682,968 horsepower in our fleet and 56,500 horsepower on order for expected delivery during 2020 .

USA Compression Partners, LP (the “Partnership”) is a growth-oriented Delaware limited partnership.

We are managed by our general partner, USA Compression GP, LLC (the “General Partner”), which is a wholly owned subsidiary of Energy Transfer Operating, L.P.

(“ETO”), a consolidated subsidiary of Energy Transfer LP (“ET LP”).

On April 2, 2018 (the “Transactions Date”), we acquired (the “CDM Acquisition”) all of the equity interests in CDM Resource Management LLC and CDM Environmental & Technical Services LLC, which together represent the CDM Compression Business (the “USA Compression Predecessor”), and ET LP acquired all of the equity interests in the General Partner, which it subsequently contributed to ETO.

USA Compression Predecessor has been determined to be the historical predecessor of the Partnership for financial reporting purposes because ET LP controlled the USA Compression Predecessor prior to the CDM Acquisition and obtained control of the Partnership through its acquisition of the General Partner.

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

We believe that we are one of the largest independent providers of natural gas compression services in the U.S.

in terms of total compression fleet horsepower.

We have been providing compression services since 1998 and completed our initial public offering in January 2013.

As of December 31, 2020, we had 3,726,181 horsepower in our fleet.

We provide compression services to our customers primarily in connection with infrastructure applications, including both allowing for the processing and transportation of natural gas through the domestic pipeline system and enhancing crude oil production through artificial lift processes.

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

as such, we have focused our activities in areas 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.

We operate a modern fleet of compression units, with an average age of approximately six years.

We operate a modern fleet of compression units, with an average age of approximately seven years.

We acquire our compression units from third-party fabricators who build the units to our specifications, utilizing specific components from original equipment manufacturers and assembling the units in a manner that provides us the ability to meet certain operating condition thresholds.

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The design flexibility of our units, particularly in midstream applications, allows us to enter into longer-term contracts and reduces the redeployment risk of our horsepower in the field.

Our modern and standardized fleet, decentralized field level operating structure and technical proficiency in predictive and preventive maintenance and overhaul operations have enabled us to achieve average service run times consistently at or above the levels required by our customers and maintain high overall utilization rates for our fleet.

Our modern and standardized fleet, decentralized field level operating structure and technical proficiency in predictive

and preventive maintenance and overhaul operations have enabled us to achieve average service run times consistently at or above the levels required by our customers and maintain high overall utilization rates for our fleet.

As part of our services, we engineer, design, operate, service and repair our compression units and maintain related support inventory and equipment.

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We typically continue to provide compression services at a specific location beyond the initial contract term, either through contract renewal or on a month-to-month or longer basis.

We primarily enter into take-or-pay contracts whereby our customers are required to pay our monthly fee

even during periods of limited or disrupted throughput, which enhances the stability and predictability of our cash flows.

We primarily enter into fixed-fee contracts whereby our customers are required to pay our monthly fee even during periods of limited or disrupted throughput, which enhances the stability and predictability of our cash flows.

We are not directly exposed to commodity price risk because we do not take title to the natural gas or crude oil involved in our services and because the natural gas used as fuel by our compression units is supplied by our customers without cost to us.

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Regardless of the application for which our services are provided, our customers rely upon the availability of the equipment used to provide compression services and our expertise to maximize the throughput of product, reduce fuel costs and minimize emissions.

While we significantly expanded our geographic footprint with our acquisition of the USA Compression Predecessor from ETO (the “CDM Acquisition”), our customers may have compression demands in areas of the U.S.

While we significantly expanded our geographic footprint with the CDM Acquisition, our customers may have compression demands in areas of the U.S.

in conjunction with their field development projects where we are not currently operating.

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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.

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.

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.

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%.

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.

Our Operations

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Our units can be rapidly and cost effectively modified for specific customer applications.

As of December 31, 2019 , the average age of our compression units was approximately six years.

As of December 31, 2020, the average age of our compression units was approximately seven years.

Our modern, standardized compression unit fleet is powered primarily by the Caterpillar 3400, 3500 and 3600 engine classes, which range from 401 to 5,000 horsepower per unit.

These larger horsepower units, which we define as 400 horsepower per unit or greater, represented 86.2% of our total fleet horsepower (including compression units on order) as of December 31, 2019 .

In addition, a portion of our fleet consists of smaller horsepower units ranging from 40 horsepower to 399 horsepower that are primarily used in gas lift applications.

These larger horsepower units, which we define as 400 horsepower per unit or greater, represented 86.3% of our total fleet horsepower as of December 31, 2020.

The remainder of our fleet consists of smaller horsepower units ranging from 40 horsepower to 399 horsepower that are primarily used in gas lift applications.

We believe the average age and overall composition of our compressor fleet result in fewer mechanical failures, lower fuel usage, and reduced environmental emissions.

The following table provides a summary of our compression units by horsepower as of December 31, 2020:

Unit Horsepower

Number of Units

Unit Horsepower Fleet

Horsepower Number of

Units Percent of

Horsepower Percent of

Small horsepower

510,123 3,001 13.7 % 55.0 %

Large horsepower

>400 and <1,000

437,543 751 11.7 % 13.8 %

2,778,515 1,702 74.6 % 31.2 %

Total large horsepower

3,216,058 2,453 86.3 % 45.0 %

Total horsepower

3,726,181 5,454 100.0 % 100.0 %

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

The following table sets forth certain information regarding our compression fleet as of the dates and for the periods indicated and excludes certain gas treating assets for which horsepower is not a relevant metric:

Year Ended December 31,

The following table sets forth certain information regarding our compression fleet as of the dates and for the periods indicated and excludes certain natural gas treating assets for which horsepower is not a relevant metric:

Year Ended December 31, Percent

Operating Data:

2020 2019 Change

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

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Revenue generating compression units (at period end)

3,968 4,559 (13.0) %

Average horsepower per revenue generating compression unit (5)

746 720 3.6 %

Horsepower utilization (6):

At period end

82.8 % 93.7 % (11.6) %

Average for the period (7)

86.8 % 94.1 % (7.8) %

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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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The compression business can be hazardous, involving unforeseen circumstances such as uncontrollable flows of gas or well fluids, fires and explosions or environmental damage.

To address the hazards inherent in our business, we maintain insurance coverage that, subject to significant deductibles,

includes physical damage coverage, third party general liability insurance, employer’s liability, environmental and pollution and other coverage, although coverage for environmental and pollution related losses is subject to significant limitations.

To address the hazards inherent in our business, we maintain insurance coverage that, subject to significant deductibles, includes physical damage coverage, third party general liability insurance, employer’s liability, environmental and pollution and other coverage, although coverage for environmental and pollution related losses is subject to significant limitations.

Under the terms of our standard compression services contract, we are responsible for maintaining insurance coverage on our compression equipment.

Please read Part I, Item 1A “Risk Factors – Risks Related to Our Business – We do not insure against all potential losses and could be seriously harmed by unexpected liabilities”.

Please read Part I, Item 1A “Risk Factors – General Risk Factors – We do not insure against all potential losses and could be seriously harmed by unexpected liabilities”.

Environmental and Safety Regulations

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We believe that we are in substantial compliance with all of these environmental laws and regulations.

Please read Part I, Item 1A “Risk Factors – Risks Related to Our Business – We are subject to substantial environmental regulation, and changes in these regulations could increase our costs or liabilities”.

Please read Part I, Item 1A “Risk Factors – Risks Related to Government Legislation and Regulation – We are subject to substantial environmental regulation, and changes in these regulations could increase our costs or liabilities”.

Air emissions .

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For example, in 2015, the EPA finalized a rule strengthening the primary and secondary standards for ground level ozone, both of which are 8-hour concentration standards of 70 parts per billion.

In December 2020, the EPA announced its decision to retain, without changes, the 2015 NAAQS.

After the EPA revises a NAAQS standard, the states are expected to establish revised attainment/non-attainment regions.

State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our customers’ ability to obtain such permits, and result in increased expenditures for pollution control equipment, which could impact our customers’ operations, increase the cost of additions to property, plant, and equipment, and negatively impact our business.

State implementation of the 2015 NAAQS could result in stricter permitting requirements, delay or prohibit our customers’ ability to obtain such permits, and result in increased expenditures for pollution control equipment, which could impact our customers’ operations, increase the cost of additions to property, plant, and equipment, and negatively impact our business.

In 2012, the EPA finalized rules that establish new air emissions controls for oil and natural gas production and natural gas processing operations.

Specifically, the EPA’s rule package included New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”) and a separate set of emissions standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities.

The rules established specific new requirements regarding emissions from compressors and controllers at natural gas processing plants, dehydrators, storage tanks and other production equipment as well as the first federal air standards for natural gas wells that are hydraulically fractured.

In June 2016, the EPA took steps to expand on these regulations when it published New Source Performance Standards, known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce methane gas and VOC emissions.

These Subpart OOOOa standards would expand the 2012 New Source Performance Standards by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations.

However, the EPA announced in April 2017 that it intended to reconsider certain aspects of the 2016 New Source Performance Standards, and in May 2017, the EPA issued an administrative stay of key provisions of the rule, but was promptly ordered by the D.C.

Circuit to implement the rule.

The EPA also proposed 60-day and two-year stays of certain provisions in June 2017 and published a Notice of Data Availability in November 2017 seeking comment and providing clarification regarding the agency’s legal authority to stay the rule.

In March 2018, EPA finalized narrow amendments to the rule, and in October 2018, EPA proposed further reconsideration amendments to the rule.

Among other things, these amendments would alter fugitive emissions requirements, monitoring frequencies, and well site pneumatic pump standards.

In September 2019, the EPA published a proposed rulemaking amending the June 2016 regulations that, among other things, would remove sources in the transmission and storage segment from the oil and natural gas source category and rescind the methane-specific requirements applicable to sources in the production and processing segments of the industry.

As an alternative, EPA also proposed to rescind the methane-specific requirements that apply to all sources in the oil and natural gas industry, without removing the transmission and storage sources from the current source category.

Under either alternative, EPA plans to retain emissions limits for volatile organic compounds.

The EPA proposed rulemaking indicates that the controls to reduce volatile organic compound emissions also reduce methane at the same time, so separate methane limitations for these segments of the industry are redundant.

Whether these proposed standards may become implemented, on what date and exactly what they will require is unknown at this time.

Depending upon whether EPA finalizes these further amendments or promulgates any additional regulation of air emissions from the oil and gas sector could result in increased expenditures for pollution control equipment, which could impact our customers’ operations and negatively impact our business.

The rules established specific new requirements regarding emissions from compressors and controllers at natural gas processing plants, dehydrators, storage tanks

and other production equipment as well as the first federal air standards for natural gas wells that are hydraulically fractured.

In June 2016, the EPA took steps to expand on these regulations when it published New Source Performance Standards, known as Subpart OOOOa, that required certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce methane gas and VOC emissions.

These Subpart OOOOa standards would have expanded the 2012 New Source Performance Standards by using certain equipment-specific emissions control practices, requiring additional controls for pneumatic controllers and pumps as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations.

However, in September 2020, the EPA issued a final rule that removed the transmission and storage segment from the 2016 New Source Performance Standards, rescinded VOCs and methane emissions standards for the transmission and storage segment, and rescinded methane emissions standards for the production and processing segments.

Various states and industry and environmental groups are separately challenging the EPA’s 2016 standards and its September 2020 final rule.

Notwithstanding the current court challenges, on January 20, 2021, President Biden issued an executive order directing the EPA to consider publishing for notice and comment a proposed rule suspending, revising, or rescinding the September 2020 rule, which could result in more stringent methane emission rulemaking.

Any additional regulation of air emissions from the oil and gas sector could result in increased expenditures for pollution control equipment, which could impact our customers’ operations and negatively impact our business.

We are also subject to air regulation at the state level.

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Congress has considered legislation to reduce GHG emissions.

Federal and possibly state governments may impose significant and potentially draconian restrictions on fossil-fuel exploration, production and use if pledges made by certain candidates seeking various political offices were enacted into law.

Some proposals include bans on hydraulic fracturing of oil and gas wells, bans on new leases for production of minerals on federal properties, and imposing restrictive requirements on new pipeline infrastructure or fossil-fuel export facilities.

At the federal level, President Biden could seek to pursue legislative, regulatory or executive initiatives that may impose significant restrictions on fossil-fuel exploration, production and use such as limitations or bans on hydraulic fracturing of oil and gas wells, bans or restrictions on new leases for production of minerals on federal properties, and imposing restrictive requirements on new pipeline infrastructure or fossil-fuel export facilities.

For example, on January 27, 2021, President Biden issued an executive order directing the Secretary of the Interior to pause approval of new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices.

Other energy legislation and initiatives could include a carbon tax or cap and trade program.

At the state level, many states, including the states in which we or our customers conduct operations, have adopted legal requirements that have imposed new or more stringent permitting, disclosure or well construction requirements on oil and gas activities.

Further, although Congress has not passed such legislation, almost half of the states have begun to address GHG emissions, primarily through the planned development of emissions inventories or regional GHG cap and trade programs.

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Independent of Congress, the EPA undertook to adopt regulations controlling GHG emissions under its existing CAA authority.

For example, in 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs endanger

human health and the environment, allowing the agency to proceed with the adoption of regulations that restrict emissions of GHG under existing provisions of the CAA.

For example, in 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs endanger human health and the environment, allowing the agency to proceed with the adoption of regulations that restrict emissions of GHG under existing provisions of the CAA.

In 2009 and 2010, the EPA adopted rules regarding regulation of GHG emissions from motor vehicles and requiring the reporting of GHG emissions in the U.S.

from specified large GHG emissions sources, including petroleum and natural gas facilities such as natural gas transmission compression facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year.

In 2015, the EPA published standards of performance for GHG emissions from new power plants.

The final rule establishes a performance standard for integrated gasification combined cycled units and utility boilers based on the use of the best system of emissions reduction that the EPA has determined has been adequately demonstrated for each type of unit.

The rule also sets limits for stationary natural gas combustion turbines based on the use of natural gas combined cycle technology.

The EPA also promulgated the Clean Power Plan rule (“CPP”), which is intended to reduce carbon emissions from existing power plants by 32 percent from 2005 levels by 2030.

In 2019, the EPA finalized the Affordable Clean Energy rule (“ACE”) to replace the CPP, providing states with authority to regulate GHGs from coal-fired power plants, and establish heat rate improvements as the best system of emissions reduction.

The ACE rule has been challenged in court and the final outcome of that litigation is uncertain.

If the ACE Rule results in state plans to significantly reduce the level of GHG emissions from electric utility generating units, or if the effort to replace the CPP with the ACE rule is unsuccessful and rules similar to the CPP are upheld to control GHG emissions from electric utility generating units, demand for the oil and natural gas our customers produce may decrease.

In addition, the costs of electricity for our operations may also increase, thereby adversely impacting our business.

In addition to the EPA, the Bureau of Land Management (“BLM”) has also promulgated rules to regulate hydraulic fracturing.

In addition, from time to time, there have been various proposals to regulate hydraulic fracturing at the federal level.

Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the rock formation to stimulate gas production.

In 2015, the BLM promulgated new requirements relating to well construction, water management, and chemical disclosure for companies drilling on federal and tribal land, but subsequently finalized a rule in December 2017 rescinding the 2015 rule.

This rescission has been challenged and that litigation is ongoing.

If this rescission is not upheld, it could increase the costs of operation for our customers who operate on BLM land, and negatively impact our business.

Additionally, on November 15, 2016, the BLM also finalized a rule to reduce the flaring, venting and leaking of methane from oil and gas operations on federal and Indian lands (the “Venting Rule”).

The Venting Rule requires operators to use certain technologies and equipment to reduce flaring and to periodically inspect their operations for leaks.

The Venting Rule also specifies when operators owe the government royalties for flared gas.

In December 2017, BLM finalized a decision to delay implementation of key requirements in the Venting Rule for one year.

The agency subsequently finalized a rule in September 2018 to revise the 2016 Venting rule (the “Revised Venting Rule”) by rescinding certain requirements, such as the requirement to use certain technologies and equipment, as well as the leak detection and repair requirement.

The Revised Venting Rule also specifies that BLM will defer to the appropriate State or tribal authorities in determining whether royalties are owed for flared gas.

Challenges to the Venting Rule and the Revised Venting Rule are pending in court.

If the Revised Venting Rule is not upheld, and the Venting Rule is fully implemented, it could increase the costs of operations for our customers who operate on BLM land, and negatively impact our business.

On January 27, 2021, President Biden issued an executive order directing the Secretary of the Interior to pause approval of new oil and natural gas leases on public lands or in offshore waters pending completion of a comprehensive review

and reconsideration of federal oil and gas permitting and leasing practices, effectively limiting hydraulic fracturing on federal lands and waters.

Any limitations or bans on hydraulic fracturing at the federal level could increase the costs of operations for our customers who operate on federal land, and negatively impact our business.

Some states have also passed legislation or regulations regarding hydraulic fracturing.

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Some local communities have adopted additional restrictions for oil and gas activities, such as requiring greater setbacks, and some groups are petitioning local governments to ban hydraulic fracturing.

If additional regulatory measures are adopted, customers in Colorado could experience delays, limitations, or prohibitions on their activities.

If additional regulatory measures are adopted that ban or restrict production of natural gas through hydraulic fracturing, our customers could experience delays, limitations, or prohibitions on their activities.

Such delays, limitations, or prohibitions could result in decreased demand for our services.

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At the international level, nearly 200 nations entered into an international climate agreement at the 2015 United Nations Framework Convention on Climate Change in Paris, under which participating countries did not assume any binding obligation to reduce future emissions of GHGs but instead pledged to voluntarily limit or reduce future emissions.

Although the U.S.

became a party to the Paris Agreement in April 2016, the Trump administration announced in June 2017 its intention to either withdraw from the Paris Agreement or renegotiate more favorable terms.

However, the Paris Agreement stipulates that participating countries must wait four years before withdrawing from the agreement.

Despite the planned withdrawal, certain U.S.

The Paris Agreement went into effect on November 4, 2016.

While the U.S.

withdrew from the Paris Agreement on November 4, 2020, President Biden issued an executive order on January 20, 2021 recommitting the United States to the Paris Agreement.

In addition, certain U.S.

city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement.

Although it is not currently possible to predict with specificity how any proposed or future GHG legislation, regulation, agreements or initiatives will impact our business, any legislation or regulation of GHG emissions that may be imposed in areas in which we conduct business or on the assets we operate could result in increased compliance or operating costs or additional operating restrictions or reduced demand for our services, and could have a material adverse effect on our business, financial condition and results of operations.

Notwithstanding potential risks related to climate change, the International Energy Agency estimates that oil and gas will continue to represent a major share of global energy use through 2040, and other private sector studies project continued growth in demand for the next two decades.

Although it is not currently possible to predict with specificity how any proposed or future GHG legislation, regulation, agreements or initiatives will impact our business, any legislation or regulation of GHG emissions that may be imposed in areas in which we conduct business or on the assets we operate, including a carbon tax or cap and trade program, could result in increased compliance or operating costs or additional operating restrictions or reduced demand for our services, and could have a material adverse effect on our business, financial condition and results of operations.

Notwithstanding potential risks related to climate change, the EIA estimates that oil and gas will continue to represent a major share of energy use through 2050.

However, recent activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector.

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Water discharge .

The Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States.

The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency.

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Federal and state regulatory agencies can impose administrative, civil and criminal penalties as well as other enforcement mechanisms for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.

Our compression operations do not generate process wastewaters that are discharged to waters of the United States.

Our compression operations do not generate process wastewaters that are discharged to waters of the U.S.

In any event, our customers assume responsibility under the majority of our standard natural gas compression contracts for obtaining any permits that may be required under the CWA, whether for discharges or developing property by filling wetlands.

Considerable legal uncertainty exists surrounding the standard for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the CWA.

A 2015 EPA rulemaking that would have significantly expanded the scope of jurisdictional waters has been repealed by a recent rulemaking in October 2019 by the EPA and the U.S.

Army Corps of Engineers.

Should the 2019 repeal be vacated and the 2015 rule take effect, or should a different rule expand the jurisdictional reach of the CWA, our customers could face increased costs and delays due to additional permitting and regulatory requirements and possible challenges to permitting decisions.

On April 21, 2020, the EPA and the U.S.

Army Corps of Engineers issued a rule streamlining the standard for what constitutes jurisdictional waters and wetlands subject to the protections and requirements of the CWA.

Lawsuits have been filed challenging the rule, and on January 20, 2021, President Biden issued an executive order directing the heads of all agencies to immediately review all

regulatory actions taken between January 20, 2017 and January 20, 2021, including the April 2020 rule.

Should the April 2020 rule be rescinded or a different rule promulgated that expands the jurisdictional reach of the CWA, our customers could face increased costs and delays due to additional permitting and regulatory requirements and possible challenges to permitting decisions.

Safe Drinking Water Act.

A significant portion of our customers’ natural gas production is developed from unconventional sources that require hydraulic fracturing as part of the completion process.

Legislation to amend the Safe Drinking Water Act (“SDWA”) to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed and the U.S.

Congress continues to consider legislation to amend the SDWA.

Scrutiny of hydraulic fracturing activities continues in other ways, with the EPA having commenced a multi-year study of the potential environmental impacts of hydraulic fracturing.

In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources.

The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts:

water withdrawals for fracturing in times or areas of low water availability;

surface spills during the management of fracturing fluids, chemicals or produced water;

injection of fracturing fluids into wells with inadequate mechanical integrity;

injection of fracturing fluids directly into groundwater resources;

discharge of inadequately treated fracturing wastewater to surface waters;

and disposal or storage of fracturing wastewater in unlined pits.

The EPA has also announced that it believes hydraulic fracturing using fluids containing diesel fuel can be regulated under the SDWA notwithstanding the SDWA’s general exemption for hydraulic fracturing.

Several states have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing, including prohibitions on the practice.

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If additional levels of regulation, restrictions and permits were required through the adoption of new laws and regulations at the federal or state level or if the agencies that issue the permits develop new interpretations of those requirements, that could lead to delays, increased operating costs and process prohibitions that could reduce demand for our compression services, which could materially adversely affect our revenue and results of operations.

Solid waste .

The Resource Conservation and Recovery Act (“RCRA”) and comparable state laws control the management and disposal of hazardous and non-hazardous waste.

These laws and regulations govern the generation, storage, treatment, transfer and disposal of wastes that we generate including, but not limited to, used oil, antifreeze, filters, sludges, paint, solvents and sandblast materials.

The EPA and various state agencies have limited the approved methods of disposal for these types of wastes.

Site remediation .

The Comprehensive Environmental Response Compensation and Liability Act (“CERCLA”) and comparable state laws impose strict, joint and several liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to the release of a hazardous substance into the environment.

The Comprehensive Environmental Response Compensation and Liability Act (“CERCLA”) and comparable state laws may impose strict, joint and several liability without regard to fault or the legality of the original conduct on certain classes of persons that contributed to the release of a hazardous substance into the environment.

These persons include the owner and operator of a disposal site where a hazardous substance release occurred and any company that transported, disposed of or arranged for the transport or disposal of hazardous substances released at the site.

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We are not currently responsible for any remedial activities at any properties we use;

however, there is always the possibility that our future use of those properties may result in spills or releases of petroleum hydrocarbons, wastes or other regulated substances into the environment that may cause us to become subject to remediation costs and liabilities under CERCLA, RCRA or other environmental laws.

We cannot provide any assurance that the costs and liabilities associated with the future imposition of such remedial obligations upon us would not have a material adverse effect on our operations or financial position.

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The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and, as necessary, disclose information about hazardous materials used or produced in our operations to various federal, state and local agencies, as well as employees.

Human Capital Management

USA Compression Management Services, LLC (“USAC Management”), a wholly owned subsidiary of the General Partner, performs certain management and other administrative services for us, such as accounting, corporate development, finance and legal.

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We consider our employee relations to be good.

Our employees are our greatest asset, and we seek to attract and retain top talent by fostering a culture that is guided by our four pillars of people, culture, equipment and service.

These four pillars guide our values in a manner that respects all people with a commitment to safety and the environments where we operate.

Ethics and Values.

We are committed to operating our business in a manner that honors and respects all people and the communities in which we do business.

We recognize that people are our most critical resource, and we are committed to hiring and investing in our employee base.

We value employees for what they bring to our organization by embracing those from diverse backgrounds, cultures, and experiences.

We believe that one of the keys to our successes over time has been the cultivation of an atmosphere of inclusion and respect.

These are the principles upon which we build and strengthen relationships among our people, our unitholders, our customers, and those within the communities we support.

We believe strict adherence to our Code of Business Conduct and Ethics is not only right, but is in our best interest and the best interest of our unitholders, our customers, and the industry in general.

In all instances, our policies require that the business of the Partnership be conducted in a lawful and ethical manner.

Every employee acting on behalf of the Partnership must adhere to our policies.

Please refer to Part III, Item 10 “Directors, Executive Officers and Corporate Governance” for additional information on our Code of Business Conduct and Ethics.

Commitment to Safety and the Environment.

We have a strong commitment to safety and the environment.

We provide continuous training opportunities for employees, including training that is required by applicable laws, regulations, standards, and permit conditions.

Our safety standards and expectations are clearly communicated to all operations employees with the expectation that each individual has the obligation to make safety their highest priority.

Our safety culture promotes an open environment for discovering, resolving, and sharing safety challenges.

We strive to eliminate unwanted safety events and support our safety culture through a comprehensive program that includes a dedicated field operations based safety team, monthly employee safety meetings and safety audits, among other things.

A portion of our senior management bonuses and field management bonuses are dependent on our safety performance.

We promote employee empowerment, leadership, communication, personal responsibility to comply with standard operating procedures and regulatory requirements, effective risk reduction processes, and personal wellness.

Our goal is operational excellence, which includes maintaining an injury- and incident-free workplace.

To achieve this, we strive to hire and maintain the most qualified and dedicated workforce in the industry and make safety and safety accountability part of our daily operations.

The OSHA Total Recordable Incident Rate (“TRIR”) is a key performance indicator by which we evaluate the success of our safety program.

TRIR provides a measure of occupational safety performance for the year by calculating the number of recordable incidents compared to the total number of hours worked by all employees.

Out of more than 1,850,000 hours worked, our TRIR was 0.32 for 2020, compared to 0.84 in 2019, versus the industry average for 2020 which was 0.90.

We believe our low TRIR and our 2,000,000 hours worked without a lost time event speaks to our investment in and focus on safety.

Regarding COVID-19, as an essential business providing critical energy infrastructure, the safety of our employees and the continued operation of our assets are our top priorities, and we continue to follow and operate in accordance with federal, state and local health guidelines and safety protocols.

We also continue to follow the U.S.

Center for Disease Control guidance and provide employees with training and direction to help maintain the health and safety of our workforce.

Available Information

Our website address is usacompression.com.

We make available, free of charge at the “Investor Relations” section of our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as soon as reasonably practicable after such reports are electronically filed with, or furnished to, the SEC.

We make available, free of charge at the “Investor Relations” section of our website, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, as soon as reasonably practicable after such reports are electronically filed with, or furnished to, the SEC.

The information contained on our website does not constitute part of this report.

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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 1. Business