What changed in this filing

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Item 1A. Risk Factors

2021-02-16 compared with 2020-02-18 · 211 added, 188 removed, 433 unchanged (48% of the section changed)

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In that case, we might not be able to continue to pay our current quarterly distribution on our common units or increase the level of such distributions in the future, and the trading price of our common units could decline.

Risk Factor Summary

Risks Related to Our Business

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to the General Partner, to enable us to make cash distributions on our common units at the current level.

• The ongoing global COVID-19 pandemic and recent oil market developments have had and may continue to have an adverse effect on our business and results of operations.

• We may not generate sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to the General Partner, to enable us to make cash distributions on our common units at the current level.

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

• We have several key customers.

The loss of any of these customers would result in a decrease in our revenues and cash available for distribution.

• The deterioration of the financial condition of our customers could adversely affect our business.

• We are exposed to counterparty credit risk.

Nonpayment and nonperformance by our customers, suppliers or vendors could reduce our revenues, increase our expenses and otherwise have a negative impact on our ability to conduct our business, operating results, cash flows and ability to make distributions to our unitholders.

• Our customers may choose to vertically integrate their operations by purchasing and operating their own compression fleet, increasing the number of compression units they currently own or using alternative technologies for enhancing crude oil production.

• A significant portion of our services are provided to customers on a month-to-month basis, and we cannot be sure that such customers will continue to utilize our services.

• We may be unable to grow our cash flows if we are unable to expand our business, which could limit our ability to maintain or increase the level of distributions to our common unitholders.

• Our debt level may limit our flexibility in obtaining additional financing, pursuing other business opportunities and paying distributions.

• The terms of the Credit Agreement and the Indentures restrict our current and future operations, particularly our ability to respond to changes or to take certain actions, may limit our ability to pay distributions and may limit our ability to capitalize on acquisitions and other business opportunities.

• A prolonged or severe sudden downturn in the economic environment, such as the severe impact of the COVID-19 pandemic, could cause an impairment of identifiable intangible assets and reduce our earnings.

• We depend on a limited number of suppliers and are vulnerable to product shortages and price increases, which could have a negative impact on our results of operations.

Risks Related to Governmental Legislation and Regulation

• We are subject to substantial environmental regulation, and changes in these regulations could increase our costs or liabilities.

• New regulations, proposed regulations and proposed modifications to existing regulations under the Clean Air Act, if implemented, could result in increased compliance costs.

Risks Inherent in an Investment in Us

• Holders of our common units have limited voting rights and are not entitled to elect the General Partner or its directors.

• ETO owns and controls the General Partner, and the General Partner has sole responsibility for conducting our business and managing our operations.

The General Partner and its affiliates, including ETO, have conflicts of interest with us and limited fiduciary duties, and they may favor their own interests to the detriment of us and our unitholders.

• The Partnership Agreement limits the General Partner’s fiduciary duties to our unitholders.

• The Partnership Agreement restricts the remedies available to our unitholders for actions taken by the General Partner that might otherwise constitute breaches of fiduciary duty.

• The Partnership Agreement restricts the voting rights of unitholders owning 20% or more of our common units.

• We may issue additional limited partner interests without the approval of unitholders, subject to certain Preferred Unit approval rights, which would dilute unitholders’ existing ownership interests and may increase the risk that we will not have sufficient available cash to maintain or increase our per common unit distribution level.

• The General Partner has a call right that may require you to sell your common units at an undesirable time or price.

• Unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.

• Unitholders may have liability to repay distributions that were wrongfully distributed to them.

• Our Partnership Agreement designates the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which would limit our unitholders’ ability to choose the judicial forum for disputes with us or our general partner’s directors, officers or other employees.

Tax Risks to Common Unitholders

• Our tax treatment depends on our status as a partnership for federal income tax purposes.

If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes, then our cash available for distribution would be substantially reduced.

• The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

• Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

• If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

• Tax gain or loss on the disposition of our common units could be more or less than expected.

• Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

unitholders will be subject to U.S.

taxes and withholding with respect to their income and gain from owning our units.

• We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased.

The IRS may challenge this treatment, which could adversely affect the value of our common units.

• We generally prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred.

The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

• We have adopted certain valuation methodologies in determining a unitholder’s allocations of income, gain, loss and deduction.

The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.

• As a result of investing in our common units, you will likely become subject to state and local taxes and income tax return filing requirements in jurisdictions where we operate or own or acquire properties.

Risks Related to Our Business

The ongoing global COVID-19 pandemic and recent oil market developments have had and may continue to have an adverse effect on our business and results of operations.

The COVID-19 pandemic that began in early 2020 has caused volatility in the capital markets and negatively impacted the worldwide economy, including the oil and gas industry.

Demand for crude oil and natural gas has declined due in part to the COVID-19 outbreak and associated government imposed restrictions and decreased consumer demand, which have had, and may continue to have, a negative impact on many of our customers involved in the domestic exploration and production of crude oil and natural gas.

In addition, turmoil between the members of OPEC+ in 2020 resulted in Saudi Arabia discounting its price and increasing its supply of oil into the global marketplace in early 2020.

The dual forces of increased supply and reduced demand due to COVID-19 caused oil prices to fall substantially, adversely affecting some of our customers.

As a result, some producers chose to delay, or shut-in, production.

While the extent of the impact these events will have on our results of operations and financial condition is uncertain, they are examples of events that caused a reduction in the demand for, price of and level of production of natural gas and crude oil in the regions where we provide compression services, which potentially could cause:

• a negative impact on our results of operations and financial condition;

• the deterioration of the financial condition of our customers, suppliers and vendors;

• a hindrance on our ability to pay distributions, service our debt and other liabilities, and comply with certain restrictive financial covenants in the Credit Agreement and the Indentures (the “Indentures”) governing the Senior Notes 2026 and Senior Notes 2027 (collectively, the “Senior Notes”);

• renegotiation of our service contracts at lower rates;

• additional costs to us, which could be significant, in connection with litigation and bankruptcies resulting from customer financial deterioration.

Furthermore, market volatility could increase our cost of capital and block our access to the equity and debt capital markets, which could eventually impede our ability to grow, make distributions to our unitholders at current levels and comply with the terms of our debt agreements.

Additionally, if COVID-19 were to significantly spread into our workforce, this could hinder our ability to provide services and otherwise perform our contractual obligations to our customers.

The duration of the COVID-19 pandemic and the magnitude of its repercussions cannot be reasonably estimated at this time, and depending on its duration and severity, it could materially adversely affect our financial condition and results of operations.

We may not generate sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to the General Partner, to enable us to make cash distributions on our common units at the current level.

In order to make cash distributions at our current distribution rate of $0.525 per common unit per quarter, or $2.10 per common unit per year, we will require available cash of $50.9 million per quarter, or $203.7 million per year, based on the number of common units outstanding as of February 11, 2021.

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• our debt service requirements and other liabilities;

• state sales and use taxes that may be levied upon us by the states in which we operate;

• fluctuations in our working capital needs;

restrictions contained in the Credit Agreement or the Indentures (the “Indentures”) governing the Senior Notes 2026 and Senior Notes 2027 (collectively, the “Senior Notes”);

• restrictions contained in the Credit Agreement or the Indentures;

• the cost of acquisitions;

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The demand for our compression services depends upon the continued demand for, and production of, natural gas and crude oil.

Demand may be affected by, among other factors, natural gas prices, crude oil prices, weather, availability of alternative energy sources, governmental regulation and the overall demand for energy.

Any prolonged, substantial reduction in the demand for

natural gas or crude oil would likely depress the level of production activity and result in a decline in the demand for our compression services, which could result in a reduction in our revenues and our cash available for distribution.

Demand may be affected by, among other factors, natural gas prices, crude oil prices, weather, availability of alternative energy sources, global health pandemics (such as COVID-19), governmental regulation and the overall demand for energy.

Any further or extended reduction in the demand for natural gas or crude oil would likely further depress the level of production activity and result in a decline in the demand for our compression services, which could result in a reduction in our revenues and our cash available for distribution.

In particular, lower natural gas or crude oil prices over the long term could result in a decline in the production of natural gas or crude oil, respectively, resulting in reduced demand for our compression services.

For example, the North American rig count, as measured by Baker Hughes, hit a 2014 peak of 1,931 rigs on September 12, 2014, and at that time, Henry Hub natural gas spot prices were $3.82 per one million British thermal units (“MMBtu”) and West Texas Intermediate (“WTI”) crude oil spot prices were $92.18 per barrel.

By contrast, the North American rig count hit a modern low of 404 rigs on May 20, 2016, and at that time, Henry Hub natural gas spot prices were $1.81 per MMBtu and WTI crude oil spot prices were $47.67 per barrel.

By contrast, the North American rig count had decreased to 404 rigs on May 20, 2016, and at that time, Henry Hub natural gas spot prices were $1.81 per MMBtu and WTI crude oil spot prices were $47.67 per barrel.

This slowdown in new drilling activity caused some pressure on service rates for new and existing services and contributed to a decline in our utilization during 2015 and into 2016.

By the end of December 2019, the North American rig count was 805 rigs, the price of WTI crude oil was $61.14 per barrel and Henry Hub natural gas spot prices were $2.09 per MMBtu.

Although commodity prices and our utilization generally increased from 2016 through 2019, the increased activity resulting from such increased commodity prices may not continue.

Following disputes between the members of OPEC+ about production levels and the price of oil and amid the outbreak of COVID-19, the price of oil declined rapidly beginning in March 2020.

As of the end of December 2020, the North American rig count was 351 rigs, the price of WTI crude oil was $48.35 per barrel and Henry Hub natural gas spot prices were $2.36 per MMBtu.

The current decline in commodity prices and crude oil and natural gas production has resulted in a decline in the demand for our compression services, which resulted in a reduction of our revenues and our cash available for distribution.

In addition, any future decreases in the rate at which crude oil and natural gas reserves are developed, whether due to increased governmental regulation, limitations on exploration and production activity or other factors, could have a material adverse effect on our business.

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

During the period of low crude oil prices, we experienced pressure on service rates from our customers in gas lift applications;

if commodity prices decline from current levels, we may again experience pressure on service rates.

Additionally, an increasing percentage of natural gas and crude oil production comes from unconventional sources, such as shales, tight sands and coalbeds.

Such sources can be less economically feasible to produce in low commodity price environments, in part due to costs related to compression requirements, and a reduction in demand for natural gas or gas lift for crude oil may cause such sources of natural gas or crude oil to become uneconomic to drill and produce, which could in turn negatively impact the demand for our services.

Further, if demand for our services decreases, we may be asked to renegotiate our service contracts at lower rates.

In addition, governmental regulation and tax policy may impact the demand for natural gas or crude oil or impact the economic feasibility of the development of new fields or production of existing fields, which are important components of our ability to expand.

During periods of low crude oil prices, we typically experience pressure on service rates from our customers in gas lift applications, and we have started to experience such effects.

Additionally, unconventional sources, such as shales, tight sands and coalbeds, can be less economically feasible to produce in low commodity price environments, in part due to costs related to compression requirements, and a reduction in demand for natural gas or gas lift for crude oil may cause such sources of natural gas or crude oil to become uneconomic to drill and produce, which has negatively impacted, and may continue to negatively impact, the demand for our services.

Further, if demand for our services decreases going forward, we may be asked to renegotiate our service contracts at lower rates.

We have several key customers.

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The deterioration of the financial condition of our customers could adversely affect our business.

During times when the natural gas or crude oil markets weaken, our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our services.

During times when the natural gas or crude oil markets weaken, such as during the COVID-19 pandemic, our customers are more likely to experience financial difficulties, including being unable to access debt or equity financing, which could result in a reduction in our customers’ spending for our services.

For example, our customers could seek to preserve capital by using lower cost providers, not renewing month-to-month contracts or determining not to enter into any new compression service contracts.

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Reduced demand for our services could adversely affect our business, results of operations, financial condition and cash flows.

We are exposed to co unterparty credit risk.

We are exposed to counterparty credit risk.

Weak economic conditions and widespread financial distress could reduce the liquidity of our customers, suppliers or vendors, making it more difficult for them to meet their obligations to us.

We are therefore subject to risks of loss resulting from nonpayment or nonperformance by our customers.

Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements.

Weak economic conditions and widespread financial distress, including as a result of the COVID-19 pandemic, has had and could reduce the liquidity of our customers, suppliers or vendors, making it more difficult for them to meet their obligations to us.

We are therefore subject to heightened risks of loss resulting from nonpayment or nonperformance by our customers, suppliers and vendors.

Severe financial problems encountered by our customers, suppliers and vendors could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements.

In the event that any of our customers was to enter into bankruptcy, we could lose all or a portion of the amounts owed to us by such customer, and we may be forced to cancel all or a portion of our service contracts with such customer at significant expense to us.

For example, as of December 31, 2020, two customers accounted for 13% and 11% of our trade account receivables, net balance, respectively.

If either of these customers was to enter bankruptcy or failed to pay us, it could adversely affect our business, results of operations, financial condition and cash flows.

In addition, nonperformance by suppliers or vendors who have committed to provide us with critical products or services could raise our costs or interfere with our ability to successfully conduct our business.

All of the above may be exacerbated in the future as the COVID-19 outbreak and the governmental responses thereto continue.

These factors, combined with volatile prices of oil and natural gas, may precipitate a continued economic slowdown and/or a recession.

We face significant competition that may cause us to lose market share and reduce our cash available for distribution.

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For example, subsequent to the CDM Acquisition the attrition rate of specialized field technicians exceeded our projections and, as a result, we incurred unanticipated costs in 2018 to utilize third-party contractors to service our compression units at a greater cost than we would have incurred to compensate employees to perform the same work.

We may not be successful in integrating acquisitions into our existing operations within our anticipated time frame, which may result in unforeseen operational difficulties or diminished financial performance or require a disproportionate amount of our

management’s attention.

In addition, acquired assets may perform at levels below the forecasts used to evaluate their acquisition, due to factors beyond our control.

If the acquired assets perform at levels below the forecasts, then our future results of operations could be negatively impacted.

Our ability to fund purchases of additional compression units and complete acquisitions in the future is dependent on our ability to access external expansion capital.

Our ability to fund purchases of additional compression units and expansion capital expenditures in the future is dependent on our ability to access external capital.

The Partnership Agreement requires us to distribute all of our available cash to our unitholders (excluding prudent operating reserves).

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As of December 31, 2020, we had outstanding borrowings under the Credit Agreement of $473.8 million, $1.1 billion of borrowing base availability and, subject to compliance with the applicable financial covenants, available borrowing capacity of $284.2 million.

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 and Senior Notes 2027 accrue interest at the rate of 6.875% per year.

Our ability to incur additional debt is also subject to limitations in the Credit Agreement, including certain financial covenants.

As of December 31, 2020, our leverage ratio under the Credit Agreement was 5.03x.

Financial covenants in the Credit Agreement permit a maximum leverage ratio of (i) 5.5 to 1.0 through the end of the fiscal quarter ending December 31, 2019 and (ii) 5.0 to 1.0 thereafter.

Financial covenants in the Credit Agreement permit a maximum leverage ratio of (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 for each fiscal quarter thereafter).

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

Our ability to incur additional debt is also subject to limitations in the Credit Agreement, including certain financial covenants.

Our level of debt could have important consequences to us, including the following:

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• our debt level will make us more vulnerable than our competitors with less debt to competitive pressures or a downturn in our business or the economy generally.

As of December 31, 2019 , we had $725.0 million and $750.0 million aggregate principal amount of Senior Notes 2026 and Senior Notes 2027 outstanding, respectively.

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 .

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.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control.

In addition, our ability to service our debt under the Credit Agreement could be impacted by market interest rates, as all of our outstanding borrowings under the Credit Agreement are subject to variable interest rates that fluctuate with changes in market interest rates.

A substantial increase in the interest rates applicable to our outstanding borrowings could have a material

negative impact on our cash available for distribution.

A substantial increase in the interest rates applicable to our outstanding borrowings could have a material negative impact on our cash available for distribution.

If our operating results are not sufficient to service our current or future indebtedness, we could be forced to take actions such as reducing the level of distributions on our common units, curtailing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, restructuring or refinancing our debt or seeking additional equity capital.

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The terms of the Credit Agreement and the Indentures restrict our current and future operations, particularly our ability to respond to changes or to take certain actions, may limit our ability to pay distributions and may limit our ability to capitalize on acquisitions and other business opportunities.

The Credit Agreement and the Indentures governing the Senior Notes contain a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability to:

The Credit Agreement and the Indentures contain a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability to:

• incur additional indebtedness;

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• make investments;

• sell assets;

• incur liens;

• enter into transactions with affiliates;

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If we were unable to repay amounts due and payable under the Credit Agreement, those lenders could proceed against the collateral securing that indebtedness.

We may not be able to replace the Credit Agreement, or if we are, any subsequent replacement of the Credit Agreement or any new indebtedness could be equally or more restrictive.

We may not be able to replace

the Credit Agreement, or if we are, any subsequent replacement of the Credit Agreement or any new indebtedness could be equally or more restrictive.

These restrictions may negatively affect our ability to grow in accordance with our strategy.

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The Preferred Units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of our common units.

The Preferred Units rank senior to all of our other classes or series of equity securities with respect to distribution rights and rights upon liquidation.

The Preferred Units rank senior to our common units with respect to distribution rights and rights upon liquidation.

These preferences could adversely affect the market price for our common units, or could make it more difficult for us to sell our common units in the future.

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• incur Indebtedness (as defined in the Credit Agreement) if, after giving pro forma effect to such incurrence, the Leverage Ratio (as defined in the Credit Agreement) determined as of the last day of the most recently ended fiscal quarter would exceed 6.5x, subject to certain exceptions.

A prolonged downturn in the economic environment could cause an impairment of goodwill or other intangible assets and reduce our earnings.

We have recorded $619.4 million of goodwill and $363.2 million of other intangible assets, net, as of December 31, 2019 .

Goodwill is recorded when the purchase price of a business exceeds the fair market value of the tangible and separately measurable intangible net assets.

Generally accepted accounting principles of the United States (“GAAP”) requires us to test goodwill for impairment on an annual basis or when events or circumstances occur indicating that goodwill might be impaired.

A prolonged or severe sudden downturn in the economic environment, such as the severe impact of the COVID-19 pandemic, could cause an impairment of identifiable intangible assets and reduce our earnings.

We have recorded $333.8 million of identifiable intangible assets, net, as of December 31, 2020.

Any event that causes a reduction in demand for our services could result in a reduction of our estimates of future cash flows and growth rates in our business.

These events could cause us to record impairments of goodwill or other intangible assets.

If we determine that any of our goodwill or other intangible assets are impaired, we will be required to take an immediate charge to earnings with a corresponding reduction of partners’ capital resulting in an increase in balance sheet leverage as measured by debt to total capitalization.

For example, for the year ended December 31, 2017, the USA Compression Predecessor recognized a $223.0 million impairment of goodwill.

See Note 6 to our consolidated financial statements in Part II, Item 8 (“Financial Statements and Supplementary Data”) for information regarding goodwill impairment.

These events could cause us to record impairments of identifiable intangible assets.

For the year ended December 31, 2020, we recognized a goodwill impairment of $619.4 million.

If we determine that any of our identifiable intangible assets are impaired, we will be required to take an immediate charge to earnings with a corresponding reduction of partners’ capital resulting in an increase in balance sheet leverage as measured by debt to total capitalization.

Impairment in the carrying value of long-lived assets could reduce our earnings.

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If business conditions or other factors cause the expected undiscounted cash flows to decline, we may be required to record non-cash impairment charges.

Events and conditions that could result in impairment in the value of our long-lived assets include changes in the industry in which we operate, competition, advances in technology, adverse changes in the regulatory environment, or other factors leading

to a reduction in our expected long-term profitability.

For example, for the years ended 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.

For example, for the years ended December 31, 2020, 2019 and 2018, we evaluated the future deployment of our idle fleet under current market conditions and determined to retire 37, 33 and 103 compressor units, respectively, for a total of approximately 15,000, 11,000 and 33,000 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, $5.9 million and $8.7 million for the years ended December 31, 2020, 2019 and 2018, respectively.

Our ability to manage and grow our business effectively may be adversely affected if we lose key management or operational personnel.

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Some of these suppliers manufacture the components we purchase in a single facility, and any damage to that facility could lead to significant delays in delivery of completed compression units to us.

The CDM Acquisition could expose us to additional unknown and contingent liabilities.

We performed due diligence in connection with the CDM Acquisition and attempted to verify the representations made by ETO in connection therewith, but there may be unknown and contingent liabilities of which we are currently unaware.

ETO has agreed to indemnify us for losses or claims relating to the operation of the business or otherwise only to a limited extent and for a limited period of time, and certain of ETO’s indemnification obligations lapsed in late 2019.

There is a risk that we could ultimately be liable for obligations relating to the CDM Acquisition for which indemnification is not available, which could materially adversely affect our business, results of operations and cash flow.

Risks Related to Governmental Legislation and Regulation

We are subject to substantial environmental regulation, and changes in these regulations could increase our costs or liabilities.

We are subject to stringent and complex federal, state and local laws and regulations, including laws and regulations regarding the discharge of materials into the environment, emissions controls and other environmental protection and occupational health and safety concerns, as discussed in detail in Item 1 “Business – Our Operations – Environmental and Safety Regulations”.

Safety Regulations”.

Environmental laws and regulations may, in certain circumstances, impose strict liability for environmental contamination, which may render us liable for remediation costs, natural resource damages and other damages as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior owners or operators or other third parties.

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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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For example, in 2015, the EPA finalized a rule strengthening the primary and secondary National Ambient Air Quality Standards (“NAAQS”) 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 negatively 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 negatively 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.

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, the EPA finalized narrow amendments to the rule, and in October 2018, the 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 on whether the 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.

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.

Climate change legislation, regulatory initiatives, and litigation could result in increased compliance costs and restrictions on our customers’ operations.

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Congress has considered legislation to reduce GHG emissions.

It presently appears unlikely that comprehensive climate legislation will be passed in the near future, although energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues.

For example, such initiatives could include a carbon tax or cap and trade program.

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

Depending on the particular program, we could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations.

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.

President Biden could seek to pursue legislative, regulatory or executive initiatives that restrict GHG emissions.

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

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.

Independent of Congress, and as discussed in detail in Item 1 “Business – Our Operations – Environmental and Safety Regulations”, the EPA has taken to adopt regulations controlling GHG emissions under its existing CAA authority.

Depending on the particular program, we could be required to control GHG emissions or to purchase and surrender allowances for GHG emissions resulting from our operations.

Federal and possibly state governments 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.

Litigation risks are also increasing, as a number of cities, local governments and other plaintiffs have sued companies engaged in the exploration and production of fossil fuels in state and federal courts, alleging various legal theories to recover for the impacts of alleged global warming effects, such as rising sea levels.

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Although a number of these lawsuits have been dismissed, others remain pending and the outcome of these cases remains difficult to predict.

Independent of Congress, and as discussed in detail in Item 1 “Business – Our Operations – Environmental and Safety Regulations”, the EPA undertook to adopt regulations controlling GHG emissions under its existing CAA authority.

For example, 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 February 2016, the U.S.

Supreme Court granted a stay of the implementation of the CPP, which will remain in effect throughout the pendency of the appeals process, including at the United States Court of Appeals for the D.C.

Circuit and the Supreme Court through any certiorari petition that may be granted.

The stay suspends the rule, including the requirement that states must start submitting implementation plans.

It is not yet clear how the courts will ultimately rule on the legality of the CPP.

Additionally, in October 2017, the EPA proposed to repeal the CPP, and in August 2018, the EPA proposed the Affordable Clean Energy rule (“ACE”) to replace the CPP.

If the effort to replace the CPP with the ACE 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.

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.

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.

Finally, it should be noted that some scientists have concluded that increasing concentrations of GHG in Earth’s atmosphere may produce climate changes that have significant weather-related effects, such as increased frequency and severity of storms, droughts, floods and other climatic events.

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

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

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.

Additionally, concern over the threat of climate change has resulted in the making of pledges by certain candidates seeking the office of the President of the United States in 2020 to ban hydraulic fracturing of oil and natural gas wells.

Scrutiny of hydraulic fracturing activities also 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.

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

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 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 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 the 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 in turn negatively impact our business.

Hydraulic fracturing involves the injection of water, sand and chemicals

under pressure into the rock formation to stimulate gas production.

Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure or waste restrictions that may restrict or prohibit hydraulic fracturing.

In addition, members of the U.S.

Congress are and a number of federal agencies historically have been requested to review, and under the Biden administration, may be requested to review again, a variety of environmental issues associated with hydraulic fracturing, which may lead to new or more strict regulation.

Any new laws or regulations regarding hydraulic fracturing could negatively impact our customers’ ability to produce natural gas, which could adversely impact our revenue.

State and federal regulatory agencies have also recently focused on a possible connection between the operation of injection wells used for oil and gas waste disposal and seismic activity.

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Developing research suggests that the link between seismic activity and wastewater disposal may vary by region, and that only a very small fraction of the tens of thousands of injection wells have been suspected to be, or have been, the likely cause of induced seismicity.

In March 2016, the United States Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas.

In March 2016, the U.S.

Geological Survey identified six states with the most significant hazards from induced seismicity, including Oklahoma, Kansas, Texas, Colorado, New Mexico, and Arkansas.

In light of these concerns, some state regulatory agencies have modified their regulations or issued orders to address induced seismicity.

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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 the development of new interpretations of those requirements by the agencies that issue the required permits, that could lead to operational delays, increased operating costs and process prohibitions that could reduce demand for our compression services, which would materially adversely affect our revenue and results of operations.

The CDM Acquisition could expose us to additional unknown and contingent liabilities.

We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.

Our operations are subject to inherent risks such as equipment defects, malfunctions and failures, and natural disasters that can result in uncontrollable flows of gas or well fluids, fires and explosions.

These risks could expose us to substantial liability for personal injury, death, property damage, pollution and other environmental damages.

Our insurance may be inadequate to cover our liabilities.

Further, insurance covering the risks we face or in the amounts we desire may not be available in the future or, if available, the premiums may not be commercially justifiable.

If we were to incur substantial liability and such damages were not covered by insurance or were in excess of policy limits, or if we were to incur liability at a time when we are not able to obtain liability insurance, our business, results of operations and financial condition could be adversely affected.

Cybersecurity breaches and other disruptions of our information systems could compromise our information and operations and expose us to liability, which would cause our business and reputation to suffer.

We rely on our information technology infrastructure to process, transmit and store electronic information critical to our business activities.

In recent years, there has been a rise in the number of cyberattacks on other companies’ network and information systems by both state-sponsored and criminal organizations, and as a result, the risks associated with such an event continue to increase.

A significant failure, compromise, breach or interruption of our information systems could result in a disruption of our operations, customer dissatisfaction, damage to our reputation, a loss of customers or revenues and potential regulatory fines.

If any such failure, interruption or similar event results in improper disclosure of information maintained in our information systems and networks or those of our customers, suppliers or vendors, including personnel, customer, pricing and other sensitive information, we could also be subject to liability under relevant contractual obligations and laws and regulations protecting personal data and privacy.

Our financial results could also be adversely affected if our information systems are breached or an employee causes our information systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating such systems.

Terrorist attacks, the threat of terrorist attacks or other sustained military campaigns may adversely impact our results of operations.

The long-term impact of terrorist attacks and the magnitude of the threat of future terrorist attacks on the energy industry in general and on us in particular are not known at this time.

Uncertainty surrounding sustained military campaigns may affect our operations in unpredictable ways, including disruptions of crude oil and natural gas supplies and markets for crude oil, natural gas and natural gas liquids and the possibility that infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror.

Changes in the insurance markets attributable to terrorist attacks may make insurance against such attacks more difficult for us to obtain, if we choose to do so.

Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage.

Instability in the financial markets resulting from terrorism or war could also negatively affect our ability to raise capital.

If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership.

Although we continuously evaluate the effectiveness of and improve upon our internal controls, our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002 (“Section 404”).

For example, Section 404 requires us to, among other things, review and report annually on the effectiveness of our internal control over financial reporting.

In addition, our independent registered public accountants are required to assess the effectiveness of our internal control over financial reporting since we ceased to be an emerging growth company under the Jumpstart Our Business Startups Act (the “JOBS Act”) on December 31, 2018.

Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations.

Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our independent registered public accounting firm’s conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404.

Ineffective internal controls will subject us to regulatory scrutiny and may result in a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

Risks Inherent in an Investment in Us

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If our common unitholders are dissatisfied with the General Partner’s performance, they have little ability to remove the General Partner.

Common unitholders are currently unable to remove the General Partner because the General Partner and its affiliates own sufficient number of our common units to prevent its removal.

The vote of the holders of at least 66 2/3% of all outstanding common units is required to remove the General Partner, and ETO currently owns over 33 1/3% of our outstanding common units.

As a result of these limitations, the price of our common units may decline because of the absence or reduction of a takeover premium in the trading price.

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ETO owns and controls the General Partner and appointed all of the officers and a majority of the directors of the General Partner, some of whom are also officers and directors of ETO.

ETO owns and controls the General Partner and appoints all of the officers and a majority of the directors of the General Partner, some of whom are also officers and directors of ETO.

Although the General Partner has a fiduciary duty to manage us in a manner that is beneficial to us and our unitholders, the directors and officers of the General Partner also have a fiduciary duty to manage the General Partner in a manner that is beneficial to its owner.

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By purchasing a unit, a unitholder agrees to become bound by the provisions of the Partnership Agreement, including the provisions discussed above.

Even if holders of our common units are dissatisfied, they currently cannot remove the General Partner without ETO’s consent.

Common unitholders are currently unable to remove the General Partner because the General Partner and its affiliates own sufficient number of our common units to prevent its removal.

The vote of the holders of at least 66 2 / 3 % of all outstanding common units is required to remove the General Partner, and ETO currently owns over 33 1 / 3 % of our outstanding common units.

The Partnership Agreement restricts the remedies available to holders of our common units for actions taken by the General Partner that might otherwise constitute breaches of fiduciary duty.

The Partnership Agreement contains provisions that restrict the remedies available to common unitholders for actions taken by the General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law.

The Partnership Agreement restricts the remedies available to our unitholders for actions taken by the General Partner that might otherwise constitute breaches of fiduciary duty.

The Partnership Agreement contains provisions that restrict the remedies available to unitholders for actions taken by the General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law.

For example, the Partnership Agreement:

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In a situation involving a transaction with an affiliate or a conflict of interest, any determination by the General Partner must be made in good faith.

If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the Board determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in subclauses (c) or (d) above, then it will conclusively be deemed that, in making its decision, the Board acted in good faith.

If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee and the Board determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the last two bullets above, then it will conclusively be deemed that, in making its decision, the Board acted in good faith.

The Partnership Agreement restricts the voting rights of unitholders owning 20% or more of our common units.

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Therefore, increases or decreases in interest rates may affect whether or not certain investors decide to invest in master limited partnership units, including ours, and a rising interest rate environment could have an adverse impact on our common unit price and impair our ability to issue additional equity or incur debt to fund growth or for other purposes, including distributions.

We may issue additional limited partner interests without the approval of the common unitholders, which would dilute the common unitholders’ existing ownership interests and may increase the risk that we will not have sufficient available cash to maintain or increase our per common unit distribution level.

We may issue additional limited partner interests without the approval of unitholders, subject to certain Preferred Unit approval rights, which would dilute unitholders’ existing ownership interests and may increase the risk that we will not have sufficient available cash to maintain or increase our per common unit distribution level.

The Partnership Agreement does not limit the number or timing of additional limited partner interests that we may issue, including limited partner interests that are convertible into or senior to our common units, without the approval of our common unitholders as long as the newly issued limited partner interests are not senior to, or pari passu with, the Preferred Units.

With the consent of a majority of the Preferred Units, we may issue an unlimited number of limited partner interests that are senior to our common units and pari passu with the Preferred Units.

If a substantial portion of the Preferred Units are converted into common units, common unitholders could experience significant dilution.

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In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future.

Our issuance of additional common units, including pursuant to our Distribution Reinvestment Plan (“DRIP”), or other equity securities of equal or senior rank, such as additional preferred units, will have the following effects:

Our issuance of additional common units, including pursuant to our DRIP, or other equity securities of equal or senior rank, such as additional preferred units, will have the following effects:

• our existing common unitholders’ proportionate ownership interest in us will decrease;

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As of December 31, 2020, ETO beneficially owns an aggregate of 46,056,228 common units in us.

We have granted certain registration rights to ETO and its affiliates with respect to any common units they own, and have filed a registration statement with the SEC for the benefit of the holders of the Preferred Units with respect to any common units they may own upon conversion of the Preferred Units or exercise of the Warrants.

The sale of these common units in the public or private markets could have an adverse impact on the price of our common units or on any trading market that may develop.

The General Partner has a call right that may require you to sell your common units at an undesirable time or price.

We have granted certain registration rights to ETO and its affiliates with respect to any common units they own, and have filed a registration statement with the SEC for the benefit of the holders of the Preferred Units with respect to any common units they may receive upon conversion of the Preferred Units or exercise of the Warrants.

Any sales of these common units in the public or private markets could have an adverse impact on the price of our common units.

The General Partner has a call right that may require holders of our common units to sell their common units at an undesirable time or price.

If at any time the General Partner and its affiliates own more than 80% of our outstanding common units, the General Partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of our common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of the Partnership Agreement.

As a result, you may be required to sell your common units at an undesirable time or price.

You may also incur a tax liability upon a sale of your common units.

As a result, holders of our common units may be required to sell their common units at an undesirable time or price.

These holders may also incur a tax liability upon a sale of their common units.

As of December 31, 2020, the General Partner and its affiliates (including ETO), beneficially own an aggregate of approximately 47% of our outstanding common units.

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner.

The Partnership is organized under Delaware law and conducts business in a number of other states, and in some of those states, the limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established.

You could be liable for any and all of our obligations as if you were a general partner if a court or governmental agency were to determine that:

we were conducting business in a state but had not complied with that particular state’s partnership statute;

your right to act with other unitholders to remove or replace the General Partner, to approve some amendments to the Partnership Agreement or to take other actions under the Partnership Agreement constitute “control” of our business.

Unitholders may not have limited liability if a court finds that limited partner actions constitute control of our business.

Under Delaware law, unitholders could be held liable for our obligations to the same extent as a general partner if a court determined that the right of limited partners to remove our general partner or to take other action under the Partnership Agreement constituted participation in the “control” of our business.

Additionally, under Delaware law, the General Partner has unlimited liability for the obligations of the Partnership, such as our debts and environmental liabilities, except for those contractual obligations of the Partnership that are expressly made without recourse to the General Partner.

The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the states in which we do business.

Unitholders could have unlimited liability for obligations of the Partnership if a court or government agency determined that (i) we were conducting business in a state, but had not complied with that particular state’s partnership statute;

or (ii) a unitholder’s right to act with other unitholders to remove or replace the General Partner, to approve some amendments to the Partnership Agreement or to take other actions under the Partnership Agreement constituted “control” of our business.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

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federal securities laws.

This exclusive forum provision may limit the ability of a limited partner to commence litigation in a forum that the limited partner prefers, or may require a limited partner to incur additional costs in order to commence litigation in Delaware, each of which may discourage such lawsuits against us or our general partner’s directors or officers.

This exclusive forum provision may limit the ability of a limited partner to commence

litigation in a forum that the limited partner prefers, or may require a limited partner to incur additional costs in order to commence litigation in Delaware, each of which may discourage such lawsuits against us or our general partner’s directors or officers.

Alternatively, if a court were to find this exclusive forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings described above, we may incur additional costs associated with resolving such matters in other jurisdictions, which could negatively affect our business, results of operations and financial condition.

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Therefore, if we were treated as a corporation for federal income tax purposes, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

The Partnership Agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity level taxation for federal, state or local income tax purposes, the level of distributions on our common units may be adjusted to reflect the impact of that law or interpretation on us.

If we were subjected to a material amount of additional entity level taxation by individual states, it would reduce our cash available for distribution.

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The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial changes or differing interpretations at any time.

From time to time, members of the U.S.

Members of the U.S.

Congress have proposed and considered substantive changes to the existing federal income tax laws that would affect publicly traded partnerships, including elimination of partnership tax treatment for certain publicly traded partnerships.

For example, the “Clean Energy for America Act,” which is similar to legislation that was commonly proposed during the Obama Administration, was introduced in the Senate on May 2, 2019.

If enacted, this proposal would, among other things, repeal the qualifying income exception within Section 7704(d)(1)(E) of the Internal Revenue Code of 1986, as amended, upon which we rely for our treatment as a partnership for U.S.

federal income tax purposes.

In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships.

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federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future.

Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes.

partnerships for federal income tax purposes.

We are unable to predict whether any changes or other proposals will ultimately be enacted.

Any future legislative changes could negatively impact the value of an investment in our common units.

You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.

Unitholders are urged to consult with their own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on their investment in our common units.

Our unitholders’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

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If our unitholders sell common units, they will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units.

Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost.

original cost.

In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale.

A substantial portion of the amount realized from a unitholder’s sale of our units, whether or not representing gain, may be taxed as ordinary income to such unitholder due to potential recapture items, including depreciation recapture.

Thus, a unitholder

may recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than such unitholder’s adjusted basis in the units.

Thus, a unitholder may recognize both ordinary income and capital loss from the sale of units if the amount realized on a sale of such units is less than such unitholder’s adjusted basis in the units.

Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year.

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Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year.

However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion to the extent such depreciation, amortization, or depletion is not capitalized into cost of goods sold with respect to inventory.

If our “business interest” is subject to limitation under these rules, our unitholders will be limited in their ability to deduct their share of any interest expense that has been allocated to them.

As a result, unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

Our ability to deduct interest paid or accrued on indebtedness properly allocable to a trade or business, “business interest”, may be limited in certain circumstances.

Should our ability to deduct business interest be limited, the amount of taxable income allocated to our unitholders in the taxable year in which the limitation is in effect may increase.

However, in certain circumstances, a unitholder may be able to utilize a portion of a business interest deduction subject to this limitation in future taxable years.

Unitholders should consult their tax advisors regarding the impact of this business interest deduction limitation on an investment in our units.

Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.

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federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them.

With respect to taxable years beginning after December 31, 2017, subject to the proposed aggregation rules for certain similarly situated businesses or activities issued by the Treasury Department, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction).

As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa.

Tax-exempt entities should consult a tax advisor before investing in our common units.

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trade or business (“effectively connected income”).

Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S.

trade or business.

A unitholder’s share of our income, gain, loss and deduction, and any gain from the sale of our units will generally be considered “effectively connected” income.

As a result, distributions to a non-U.S.

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federal income tax on the gain realized from the sale or disposition of that unit.

Moreover, the transferee of an interest in a partnership that is engaged in a U.S.

trade or business is generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferees but were not withheld.

Because the “amount realized” includes a partner’s share of the partnership’s liabilities, 10% of the amount realized could exceed the total cash purchase price for the units.

However, pending the issuance of final regulations, the IRS has suspended the application of this withholding rule to transfers of publicly traded interests in publicly traded partnerships.

If recently promulgated regulations are finalized as proposed, such regulations would provide, with respect to transfers of publicly traded interests in publicly traded partnerships effected through a broker, that the obligation to withhold is imposed on the transferor’s broker and that a partner’s “amount realized” does not include a partner’s share of a publicly traded partnership’s liabilities for purposes of determining the amount subject to withholding.

However, it is not clear when such regulations will be finalized and if they will be finalized in their current form.

Moreover, upon the sale, exchange or other disposition of a unit by a non-U.S.

unitholder, the transferee is generally required to withhold 10% of the amount realized on such transfer if any portion of the gain on such transfer would be treated as effectively connected income.

The application of the withholding requirement on transfers of publicly traded interests, including our units, are suspended until December 31, 2021.

For transfers of units occurring after December 31, 2021, the amount realized on a transfer of units will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and such broker will generally be responsible for the relevant withholding obligations.

unitholders should consult their tax advisors regarding the impact of these rules on an investment in our units.

We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased.

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The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We generally prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month (the “Allocation Date”), instead of on the basis of the date a particular unit is transferred.

Date”), instead of on the basis of the date a particular unit is transferred.

Similarly, we generally allocate (i) certain deductions for depreciation of capital additions, (ii) gain or loss realized on a sale or other disposition of our assets, and (iii) in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date.

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In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions.

Our unitholders

will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions.

Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions.

Further, our unitholders may be subject to penalties for failure to comply with state and local filing requirements.

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Unitholders should consult with their own tax advisors regarding the filing of such tax returns, the payment of such taxes, and the deductibility of any taxes paid.

General Risk Factors

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and to operate successfully as a publicly traded partnership.

Although we continuously evaluate the effectiveness of and improve upon our

internal controls, our efforts to develop and maintain our internal controls may not be successful, and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002 (“Section 404”).

For example, Section 404 requires us to, among other things, review and report annually on the effectiveness of our internal control over financial reporting.

Any failure to develop, implement or maintain effective internal controls or to improve our internal controls could harm our operating results or cause us to fail to meet our reporting obligations.

We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.

These risks could expose us to substantial liability for personal injury, death, property damage, pollution and other environmental damages.

Our insurance may be inadequate to cover our liabilities.

Further, insurance covering the risks we face or in the amounts we desire may not be available in the future or, if available, the premiums may not be commercially justifiable.

We rely on our information technology infrastructure to process, transmit and store electronic information critical to our business activities.

Terrorist attacks, the threat of terrorist attacks or other sustained military campaigns may adversely impact our results of operations.

The long-term impact of terrorist attacks and the magnitude of the threat of future terrorist attacks on the energy industry in general and on us in particular are not known at this time.

Changes in the insurance markets attributable to terrorist attacks may make insurance against such attacks more difficult for us to obtain, if we choose to do so.

Moreover, the insurance that may be available to us may be significantly more expensive than our existing insurance coverage.

Instability in the financial markets resulting from terrorism or war could also negatively affect our ability to raise capital.

Unresolved Staff Comments

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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 1A. Risk Factors