What changed in this filing

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Item 1A. Risk Factors

2021-02-26 compared with 2020-02-27 · 143 added, 427 removed, 303 unchanged (65% of the section changed)

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• competitive conditions;

• technology;

• the availability of capital resources to fund acquisitions, capital expenditures, and other contractual obligations, and our ability to access financing through the debt or equity capital markets;

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• our ability to repay debt;

conflicts of interest among us, our general partner and its affiliates, including Occidental, with respect to, among other things, the allocation of capital and operational and administrative costs, and our future business opportunities;

• conflicts of interest among us, our general partner and its related parties, including Occidental, with respect to, among other things, the allocation of capital and operational and administrative costs, and our future business opportunities;

• our ability to maintain and/or obtain rights to operate our assets on land owned by third parties;

• our ability to acquire assets on acceptable terms from third parties;

non-payment or non-performance of significant customers, including under gathering, processing, transportation, and disposal agreements and the $260.0 million note receivable from Anadarko;

• non-payment or non-performance of significant customers, including under gathering, processing, transportation, and disposal agreements;

• the timing, amount, and terms of future issuances of equity and debt securities;

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If any of the following risks were to occur, our business, financial condition, or results of operations could be materially and adversely affected.

In such case, the trading price of the common units could decline and you could lose part or all of your investment.

In such a case, the common units’ trading price could decline, and you could lose part or all of your investment.

RISKS INHERENT IN OUR BUSINESS

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We rely on Occidental for over 50% of revenues related to the natural gas, crude oil, NGLs, and produced water that we gather, treat, process, transport, and/or dispose.

For the year ended December 31, 2019 , 59% of Total revenues and other, 38% of our throughput for natural-gas assets (excluding equity-investment throughput), and 83% of our throughput for crude-oil, NGLs, and produced-water assets (excluding equity-investment throughput) were attributable to transactions with Occidental.

For the year ended December 31, 2020, 66% of Total revenues and other, 41% of our throughput for natural-gas assets (excluding equity-investment throughput), 88% of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and 87% of our throughput for produced-water assets were attributable to production owned or controlled by Occidental.

Occidental may decrease its production in the areas serviced by us and is under no contractual obligation to maintain its production volumes dedicated to us pursuant to the terms of our applicable gathering agreements.

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A shift in Occidental’s focus away from our areas of operation could result in reduced throughput on our systems and a material decline in our revenues and cash available for distribution.

Following the closing of the Occidental Merger and the execution of the December 2019 Agreements, Occidental owns our general partner.

Occidental’s ownership of our general partner may result in conflicts of interest.

Following the closing of the Occidental Merger, the directors and officers of our general partner and its affiliates have duties to manage our general partner in a manner that is beneficial to Occidental, who is the indirect owner of our general partner.

At the same time, our general partner has duties to manage us in a manner that is beneficial to our unitholders.

Therefore, our general partner’s duties to us may conflict with the duties of its officers and directors to Occidental.

As a result of these conflicts of interest, our general partner may favor the interests of Occidental or its owners or affiliates over the interest of our unitholders.

Now that the Occidental Merger has been completed, our future prospects will depend on Occidental’s growth strategy, midstream operational philosophy, and drilling program, including the level of drilling and completion activity by Occidental on acreage dedicated to us.

Additional conflicts also may arise in the future associated with future business opportunities that are pursued by Occidental and us.

Because we are dependent on Occidental as our largest customer and the owner of our general partner, any development that materially and adversely affects Occidental’s operations, financial condition, or market reputation could have a material and adverse impact on us.

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As a result, any event, whether in our area of operations or otherwise, that adversely affects Occidental’s production, financial condition, leverage, market reputation, liquidity, results of operations, or cash flows may adversely affect our revenues and cash available for distribution.

Accordingly, we are indirectly subject to the business risks of Occidental, including the following:

the volatility of oil and natural-gas prices, which could have a negative effect on the value of Occidental’s oil and natural-gas properties, its drilling programs, and its ability to finance its operations;

the availability of capital on favorable terms to fund Occidental’s exploration and development activities;

a reduction in or reallocation of Occidental’s capital budget, which could reduce the gathering, transportation, and treating volumes available to us as a midstream operator, and/or limit our opportunities for organic growth;

Occidental’s ability to replace its oil and natural-gas reserves;

Occidental’s operations in foreign countries, which are subject to political, economic, and other uncertainties;

Occidental’s drilling, flowline, pipeline, and operating risks, including potential environmental liabilities;

transportation-capacity constraints and interruptions;

adverse effects of governmental and environmental regulation, including state-approved ballot initiatives that would change state constitutions or statutes in a manner that makes future oil and gas development in such states more difficult or expensive;

shareholder activism with respect to Occidental’s stock or activities by non-governmental organizations to restrict the exploration, development, and production of oil and natural gas by Occidental;

adverse effects from current or future litigation.

Accordingly, we are indirectly subject to the business risks of Occidental, including, but not limited to, the volatility of oil and natural-gas prices, the availability of capital on favorable terms to fund Occidental’s exploration and development activities, the political and economic uncertainties associated with Occidental’s foreign operations, transportation-capacity constraints, and shareholder activism.

Further, we are subject to the risk of non-payment or non-performance by Occidental, including with respect to our gathering and transportation agreements.

We cannot predict the extent to which Occidental’s business would be impacted if conditions in the energy industry were to deteriorate further, nor can we estimate the impact such conditions would have on Occidental’s ability to perform under our gathering and transportation agreements and note receivable.

Accordingly, any material non-payment or non-performance by Occidental could reduce our ability to make distributions to our unitholders.

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Similarly, material adverse changes at Occidental could impact our unit price adversely, thereby limiting our ability to raise capital through equity issuances or debt financing, or adversely affect our ability to engage in or expand or pursue our business activities, and also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.

See Part I, Item 1A in Occidental’s Form 10-K for the year ended December 31, 2019 (which is not, and shall not be deemed to be, incorporated by reference herein), for a full discussion of the risks associated with Occidental’s business.

On December 31, 2019, we entered into a set of agreements that will facilitate our ability to operate independently from Occidental.

See Occidental’s Exchange Act reports filed with the Securities and Exchange Commission (which are not, and shall not be deemed to be, incorporated by reference herein), for a full discussion of the risks associated with Occidental’s business.

Occidental’s ownership of our general partner may result in conflicts of interest.

Following the closing of the Occidental Merger, Occidental owns our general partner.

Occidental’s ownership of our general partner may result in conflicts of interest.

The directors and officers of our general partner and its affiliates have duties to manage our general partner in a manner that is beneficial to Occidental.

At the same time, our general partner has duties to manage us in a manner that is beneficial to our unitholders.

Therefore, our general partner’s duties to us may conflict with the duties of its officers and directors to Occidental.

As a result of these conflicts of interest, our general partner may favor the interests of Occidental or its owners or affiliates over the interest of our unitholders.

Our future prospects depend on Occidental’s growth strategy, midstream operational philosophy, and drilling program, including the level of drilling and completion activity by Occidental on acreage dedicated to us.

Additional conflicts also may arise in the future associated with future business opportunities that are pursued by Occidental and us.

For example, Occidental is not prohibited from owning assets or engaging in businesses that directly or indirectly compete with us.

On December 31, 2019, we entered into a set of agreements that will facilitate our ability to operate more independently from Occidental.

Our separation from Occidental entails risks and uncertainties that may have a material adverse effect on our business, financial condition, results of operations, or cash available for distribution to our unitholders.

The difficulties of creating a stand-alone structure include, among other things:

implementing technology systems to manage the operations and administration of our day-to-day business;

maintaining an effective system of internal controls in compliance with the Sarbanes-Oxley Act of 2002;

replicating regulatory compliance and governance infrastructure:

hiring, training, or retaining qualified personnel as needed to replace positions that have previously been provided as a shared service by Occidental;

identifying and filling gaps in management functions and expertise and establishing effective communication and information exchange among management teams and employees;

diverting management’s attention from our existing business;

potentially losing business or key employees.

The difficulties of creating a stand-alone structure include, among other things, implementing operational and administrative technology systems, maintaining effective internal controls, replicating a regulatory compliance infrastructure, and hiring, training and retaining qualified personnel, the loss of which could reduce our competitiveness and prospects for future success.

Attention to such organizational activities could also divert management’s attention from our existing business.

If any of these risks or other unanticipated liabilities or costs were to materialize, then desired benefits from our efforts to become independent from Occidental may not materialize.

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Our costs of borrowing and ability to access the capital markets are affected by market conditions and the credit rating assigned to WES Operating’s debt by the major credit rating agencies.

As of December 31, 2019 , WES Operating’s long-term debt was rated “BBB-” by Standard and Poor’s (“S&P”), “BBB-” by Fitch Ratings, and “Ba1” by Moody’s Investors Service.

In October 2019, S&P changed its outlook on WES Operating’s credit rating from “developing” to “negative.” Any future downgrades in WES Operating’s credit ratings could adversely affect WES Operating’s ability to issue debt in the public debt markets and negatively impact our cost of capital, future interest costs, and ability to effectively execute aspects of our business strategy.

As of December 31, 2020, WES Operating’s long-term debt was rated “BB” by Standard and Poor’s (“S&P”), “BB” by Fitch Ratings, and “Ba2” by Moody’s Investors Service (“Moody’s”).

In 2020, WES Operating’s credit ratings were downgraded below investment grade by Fitch, S&P, and Moody’s.

As a result of these downgrades, financing costs under the RCF increased.

Additionally, WES Operating currently has $3.4 billion of outstanding senior notes that provide for increased interest rates following downgrade events.

For example, the 2020 downgrades to WES Operating’s credit ratings resulted in a $43.0 million increase to WES Operating’s annualized borrowing costs attributable to the aforementioned senior notes.

Additional downgrades to WES Operating’s credit ratings will further increase its borrowing costs.

Any future downgrades in WES Operating’s credit ratings could adversely affect WES Operating’s ability to issue debt in the public debt markets and negatively impact our cost of capital, future interest costs, and ability to effectively execute aspects of our business strategy.

Future credit-rating downgrades also could trigger obligations to provide financial assurance of our performance under certain contractual arrangements.

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For example, market prices for natural gas have declined substantially from the highs achieved in 2008 and have remained depressed for several years.

More recently, uncertain global demand for crude oil and the increased supply resulting from the rapid development of shale plays throughout North America have contributed significantly to a substantial decline in crude-oil prices.

Rapid development of the North American shale plays also has increased the supply of natural gas contributing to a substantial drop in natural-gas prices.

Additional factors impacting commodity prices include:

domestic and worldwide economic and geopolitical conditions;

weather conditions and seasonal trends;

the ability to develop recently discovered fields or deploy new technologies to existing fields;

the levels of domestic production and consumer demand, as affected by, among other things, concerns over inflation, geopolitical issues, and the availability and cost of credit;

the availability of imported, or a market for exported, liquefied natural gas;

the availability of transportation systems with adequate capacity;

the volatility and uncertainty of regional pricing differentials, such as in the Rocky Mountains;

the price and availability of alternative fuels;

the effect of energy conservation measures;

the nature and extent of governmental regulation and taxation;

the forecasted supply and demand for, and prices of, oil, natural gas, NGLs, and other commodities.

Because of the natural decline in production from existing wells, our success depends on our ability to obtain new sources of oil and natural-gas throughput, which is dependent on certain factors beyond our control.

More recently, the COVID-19 pandemic and resulting mitigation measures also are having an adverse impact on global economic conditions, and are contributing to a significant decline in demand for oil, NGLs, and natural gas, resulting in lower commodity prices that will negatively impact our and our customers’ financial outlooks and activity levels.

Because of the natural decline in production from existing wells, our success depends on our ability to compete for new sources of oil and natural-gas throughput, which is dependent on certain factors beyond our control.

Any decrease in the volumes that we gather, process, treat, and transport could affect our business and operating results adversely.

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The primary factors affecting our ability to obtain sources of oil and natural-gas throughput include (i) the level of successful drilling activity near our systems, (ii) our ability to compete for volumes from successful new wells to the extent such wells are not dedicated to our systems, and (iii) our ability to capture volumes currently gathered or processed by third parties.

Our industry is highly competitive, and we compete with similar companies in our areas of operation.

In addition, our customers, including Occidental, may develop their own midstream systems in lieu of using ours.

While Occidental has dedicated production from certain of its properties to us, we have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems, or the rate at which production declines.

We also have no control over producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, prevailing and projected commodity prices, demand for hydrocarbons, levels of reserves, geological considerations, governmental regulations, the availability of drilling rigs, and other production and development costs.

Fluctuations in commodity prices also affect producers’ investments in the development of new oil and natural-gas reserves.

Declines in oil and natural-gas prices have reduced exploration, development, and production activity materially in some regions and, if sustained, could lead to further decreases in such activities.

Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our gathering, processing, and treating assets.

Because of these factors, known oil and natural-gas reserves existing in areas served by our assets may deter producers (including Occidental) from developing those reserves.

Because of these factors, producers (including Occidental) may be deterred from developing known oil and natural-gas reserves existing in areas served by our assets.

Moreover, Occidental may not develop the acreage it has dedicated to us.

If competition or reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, it could reduce our revenue and impair our ability to make cash distributions to our unitholders.

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay distributions at previously announced levels to holders of our common units.

To pay the announced fourth quarter 2019 distribution of $0.62200 per unit per quarter, or $2.48800 per unit per year, we require per-quarter available cash of $281.8 million , or $1.1 billion per year, based on the number of common units outstanding at January 31, 2020 .

The global outbreak of COVID-19 may have an adverse impact on our operations and financial results.

The global outbreak of COVID-19 poses significant risks to our business and to the markets in which we operate.

Many of our facilities require our field personnel to be on location to ensure safe and efficient operations.

If a significant percentage of our workforce is unable to work, due to illness or travel or other COVID-19-related restrictions, we may experience significant operational disruptions or inefficiencies and a heightened risk of safety and environmental incidents.

Any such developments could materially and adversely affect our earnings, cash flows, and ability to make cash distributions to our unitholders.

Additionally, many of our employees have been and may in the future be subject to pandemic-related work-from-home requirements, which stress the capabilities of our information technology systems, including those relating to system security;

disrupt normal channels of intracompany communications and key business processes;

and heighten the risk of cyber-security threats and operational, health, or safety-related incidents at our facilities.

For these reasons, limited working arrangements and other related restrictions may impact our operations and management effectiveness and may introduce, or increase the likelihood of, material risks to our business, operations, productivity, and results of operations.

The amount of cash we have available for distribution to holders of our common units depends primarily on our cash flows rather than on our profitability, and we may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay distributions at previously announced levels to holders of our common units, or at all, even during periods in which we record net income.

The amount of cash we have available for distribution primarily depends on our cash flows and not solely on profitability as determined by GAAP, which will be affected by non-cash items.

As a result, we may make cash distributions for periods in which we record losses for financial accounting purposes and may not make cash distributions for periods in which we record net earnings for financial accounting purposes.

To pay the announced fourth-quarter 2020 distribution of $0.31100 per unit per quarter, or $1.24400 per unit per year, we require per-quarter available cash of $131.3 million, or $525.1 million per year, based on the number of common units outstanding at February 1, 2021.

We may not have sufficient available cash from operating surplus each quarter to enable us to pay distributions at currently announced levels.

The amount of cash we can distribute on our units principally depends on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

the prices of, level of production of, and demand for oil and natural gas;

the volume of oil, NGLs, natural gas, and produced water we gather, compress, process, treat, dispose, and/or transport;

the volumes and prices of NGLs and condensate that we retain and sell;

demand charges and volumetric fees associated with our transportation services;

the level of competition from other midstream companies;

regulatory action affecting the supply of or demand for oil or natural gas, the rates we can charge, how we contract for services, our existing contracts, our operating costs, or our operating flexibility;

prevailing economic conditions.

In addition, the actual amount of cash available for distribution will depend on other factors, some of which are beyond our control, including the following:

our level of capital expenditures;

our level of operating and maintenance and general and administrative costs;

our debt-service requirements and other liabilities;

fluctuations in our working capital needs;

our ability to borrow funds and access capital markets;

our continued treatment as a flow-through entity for U.S.

federal income tax purposes;

restrictions contained in debt agreements to which we are a party;

the amount of cash reserves established by our general partner.

The amount of cash we can distribute on our units principally depends on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter.

During 2020, we significantly reduced the quarterly cash distribution on our common units and also took measures to reduce full-year 2020 capital expenditures.

These cash-preservation measures are intended to enhance our

financial strength for the duration of the COVID-19 macroeconomic disruption and the weakened commodity-price environment;

however, the duration and severity of this pandemic and concomitant economic downturn remains uncertain.

There can be no assurance that these announced actions will be adequate to preserve our financial health for the required duration and additional actions, including additional per-unit distribution reductions, may be necessary to manage through the current environment.

Furthermore, any cash we preserve from delaying or abandoning capital projects will necessarily delay or eliminate future returns we hoped to generate from previously planned projects, which may meaningfully impact our ability to generate long-term revenue and cash-flow growth.

Also, our decision to preserve cash by reducing our quarterly distribution to common unitholders may diminish the long-term value of our units and limit our ability, or increase the cost of, accessing future equity capital necessary to fund our business or to preserve our balance sheet.

We are exposed to the credit risk of third-party customers, and any material non-payment or non-performance by these parties, including with respect to our gathering, processing, transportation, and disposal agreements, could reduce our ability to make distributions to our unitholders.

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Further, to the extent any of our third-party customers is in financial distress or enters bankruptcy proceedings, the related customer contracts may be renegotiated at lower rates or altogether rejected.

For example, Sanchez Energy Corporation, which is the upstream operator for substantially all of the natural gas, crude oil, and NGLs that we gather and process in the Eagleford Basin, and which, for the year ended December 31, 2019 , directly represents 9% of our natural-gas gathering, treating, and transportation volumes, 1% of our crude-oil, NGLs, and produced-water volumes (excluding equity-investment volumes), and directly and indirectly 6% of our natural-gas processing volumes, filed a voluntary petition for reorganization under Chapter 11 of the United States Bankruptcy Code on August 12, 2019.

As a result, our earnings in the Eagleford Basin could be materially and adversely impacted, which also may result in impairments to the carrying value of our Eagleford assets.

Our strategies to reduce our exposure to changes in commodity prices may fail to protect us and could impact our financial condition negatively, thereby reducing our cash flows and our ability to make distributions to unitholders.

For the year ended December 31, 2019 , 93% of our wellhead natural-gas volume (excluding equity investments) and 100% of our crude-oil, NGLs, and produced-water throughput (excluding equity investments) were serviced under fee-based contracts under which fixed and variable fees are received based on the volume or thermal content of the natural gas and on the volume of NGLs, crude oil, and produced water we gather, process, treat, transport, or dispose.

We pursue various strategies to reduce our exposure to adverse changes in the prices for natural gas, condensate, and NGLs.

These strategies vary in scope based on the level and volatility of natural-gas, condensate, and NGLs prices and other changing market conditions.

To the extent that we engage in price-risk management activities such as the commodity-price swap agreements, we may be prevented from realizing the full impact of price increases above the levels set in those agreements.

In addition, our commodity-price management may expose us to the risk of financial loss in certain circumstances, including if counterparties to our hedging or other price-risk management contracts fail to perform under those arrangements.

Additionally, if we are unable to manage risks associated with our contracts that have commodity-price exposure effectively, it could have a material adverse effect on our business, results of operations, financial condition, and our ability to make cash distributions to our unitholders.

Implementation of new Colorado Senate Bill 19-181 may increase costs and limit oil and natural-gas exploration and production operations in the state, which could have a material adverse effect on our customers in Colorado and significantly reduce demand for our services in the state.

For example, on April 29, 2020, we received notice that Sanchez is attempting to reject a number of midstream and downstream agreements with commercial counterparties, including Sanchez’s Springfield gathering agreements and agreements obligating Sanchez to deliver the gas volumes gathered by the Springfield system to our Brasada processing plant.

If the attempted rejection is successful, our South Texas assets could be impaired and our earnings, cash flows from operations, and ability to make cash distributions to our unitholders could be materially and adversely impacted.

Implementation of Colorado Senate Bill 19-181 may increase costs and limit oil and natural-gas exploration and production operations in the state, which could have a material adverse effect on our customers in Colorado and significantly reduce demand for our services in the state.

On April 16, 2019, Senate Bill 19-181 was signed into law in Colorado.

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The composition of the COGCC commissioners also has been changed under the new law, with the COGCC adding a commissioner with public health expertise.

The COGCC now is tasked with undertaking several reviews of existing regulations and new or amended rulemakings, with priority given to implementing the new public health, safety, and environmental priorities;

cumulative impacts;

and local government assistance and interaction.

Moreover, the new law requires the Colorado Department of Public Health and Environment’s Air Division to adopt additional air-quality rules to minimize emissions from oil and natural-gas activities.

While the COGCC already has rejected calls for a complete moratorium on new oil and natural-gas projects, it issued a set of “Objective Criteria” in May 2019, which calls for the COGCC to determine whether a pending permit will be subject to “additional review” to determine compliance with Senate Bill 19-181, pending completion of certain COGCC rulemakings necessary to implement the new law.

Timing for issuance of new or amended rules pursuant to Senate Bill 19-181 is currently unknown, with hearings initiated in late 2019 and extending into 2020.

Implementation of this new law could limit operations as a result of delays by the state in issuing new drilling permits, and result in increased operational costs, which could have a material adverse effect on our customers in Colorado, which in turn could reduce statewide demand for our midstream services significantly.

On November 23, 2020, the COGCC finalized sweeping new rules to align the commission’s new mission set forth in Senate Bill 19-181.

Some of the changes include doubling setbacks to a minimum of 2,000 feet for schools or childcare centers, enacting a prohibition on routine flaring or venting, and increased protections for wildlife.

The COGCC also approved measures to address cumulative impacts by developing a new program with the Colorado Department of Public Health and Environment, and the complete overhaul of the existing permitting procedures to create a unified permitting process.

The new rules went into effect on January 15, 2021.

Implementation of this new law and the COGCC’s new rules could limit operations as a result of delays by the state in issuing new drilling permits, and result in increased operational costs, which could have a material adverse effect on our customers in Colorado, which in turn could reduce statewide demand for our midstream services significantly.

Changes in laws or regulations regarding hydraulic fracturing could result in increased costs, operating restrictions, or delays in the completion of oil and natural-gas wells, which could decrease the need for our gathering and processing services.

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Hydraulic fracturing is typically regulated by state oil and natural-gas commissions, but several federal agencies, including the EPA and the BLM, also have asserted regulatory authority over, proposed or promulgated regulations governing, and conducted investigations relating to certain aspects of the hydraulic-fracturing process.

For example, in late 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances.

Additionally, in 2016, the EPA published an effluent-limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants.

Moreover, Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing.

At the state level, some states have adopted, and others are considering adopting, legal requirements that could impose more stringent disclosure, permitting, or well-construction requirements on hydraulic-fracturing operations, and states could elect to prohibit high-volume hydraulic fracturing altogether, following the approach taken by the State of New York.

Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place, and manner of drilling activities in general or hydraulic-fracturing activities in particular.

Moreover, non-governmental organizations may seek to restrict hydraulic fracturing.

Such was the case in Colorado where certain interest groups therein unsuccessfully pursued ballot initiatives in recent general election cycles that would have revised the state constitution or state statutes in a manner that would have made future exploration and production activities in the state more difficult or expensive, including, for example, by increasing mandatory setback distances of oil and natural-gas operations from specific occupied structures and/or certain environmentally sensitive or recreational areas.

If new or more-stringent federal, state, or local legal restrictions, prohibitions or regulations, or ballot initiatives relating to the hydraulic-fracturing process are adopted in areas where our oil and natural-gas exploration and production customers operate, those customers could incur potentially significant added costs to comply with such requirements and experience delays or curtailment in the pursuit of exploration, development, or production activities, which could reduce demand for our gathering and processing services.

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In response to such concerns, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced-water disposal wells or are otherwise investigating the existence of a relationship between seismicity and the use of such wells.

For example, Colorado developed and follows guidance when issuing underground injection control permits to limit the maximum injection pressure, rate, and volume of water.

Oklahoma has issued rules for wastewater disposal wells that impose certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults, and also is developing and implementing plans directing certain wells where seismic incidents have occurred to restrict or suspend disposal-well operations.

The Texas Railroad Commission also has adopted similar permitting, operating, and reporting rules for disposal wells.

Another consequence of seismic events may be class action lawsuits, alleging that disposal-well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal.

These developments could result in additional regulation and restrictions on our use of injection wells to dispose of produced water, including a possible shut down of wells, which could have a material adverse effect on our business, financial condition, and results of operations.

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Due to our limited geographic diversification, adverse operational developments, regulatory or legislative changes, or other events in an area in which we have significant operations could have a greater impact on our business, results of operations, financial condition, and ability to make cash distributions to our unitholders than if our operations were more diversified.

We may not be able to obtain funding on acceptable terms or at all.

This may hinder or prevent us from meeting our future capital needs.

Global financial markets and economic conditions have been, and continue to be, volatile, especially for companies involved in the oil and gas industry.

The repricing of credit risk and the recent relatively weak industry conditions have made, and will likely continue to make, it difficult for some entities to obtain funding.

In addition, as a result of concerns about the stability and solvency of some of our counterparties, the cost of obtaining financing from the credit markets generally has increased as many lenders and institutional investors have increased required rates of return, enacted tighter lending standards, refused to provide funding on terms similar to the borrower’s current debt, and reduced, or in some cases, ceased to provide funding to borrowers.

Further, we may be unable to obtain adequate funding under the RCF if our lending counterparties become unable to meet their funding obligations.

Due to these factors, we cannot be certain that funding will be available if needed and to the extent required on acceptable terms.

If funding is not available when needed, or is available only on unfavorable terms, we may be unable to execute our business plans, complete acquisitions or otherwise take advantage of business opportunities, or respond to competitive pressures, any of which could have a material adverse effect on our financial condition, results of operations, cash flows, and ability to make cash distributions to our unitholders.

Restrictions in the indentures governing our publicly traded notes (collectively, the “Notes”) or the RCF may limit our ability to capitalize on acquisitions and other business opportunities.

The operating and financial restrictions and covenants in the agreements governing the Notes, the RCF, and any future financing arrangements could restrict our ability to finance future operations or capital needs or to expand or pursue business activities associated with our subsidiaries and equity investments.

The RCF contains, and with respect to the second, fourth and fifth bullets below, the indentures governing the Notes contain, covenants that restrict or limit our ability to do the following:

incur additional indebtedness or guarantee other indebtedness;

grant liens to secure obligations other than our obligations under the Notes or RCF or agree to restrictions on our ability to grant additional liens to secure our obligations under the Notes or RCF;

engage in transactions with affiliates;

make any material change to the nature of our business from the midstream business;

enter into a merger, consolidate, liquidate, wind up, or dissolve.

The RCF also contains various customary covenants, certain events of default, and a maximum consolidated leverage ratio as of the end of each fiscal quarter (which is defined as the ratio of consolidated indebtedness as of the last day of a fiscal quarter to Consolidated EBITDA, as defined in the RCF, for the most-recent four-consecutive fiscal quarters ending on such day) of 5.0 to 1.0, or a consolidated leverage ratio of 5.5 to 1.0 with respect to quarters ending in the 270-day period immediately following certain acquisitions.

Our indebtedness may limit our ability to capitalize on acquisitions and other business opportunities or our flexibility to obtain financing.

The operating and financial restrictions and covenants in the indentures governing our publicly traded notes, (collectively, the “Notes”) or the RCF, and any future financing arrangements could restrict our ability to finance future operations or capital needs or to expand or pursue business activities associated with our subsidiaries and equity investments.

See Part II, Item 7 of this Form 10-K for a further discussion of the terms of the RCF and Notes.

Debt we owe or incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

Our indebtedness could have important consequences to us, including the following:

our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions, or other purposes may be impaired or financing may not be available on favorable terms;

our funds available for operations, future business opportunities, and distributions to unitholders will be reduced by that portion of our cash flows required to make interest payments on our debt;

we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally;

our flexibility in responding to changing business and economic conditions may be limited.

Furthermore, our indebtedness and related debt-service costs could impair our ability to obtain additional financing, reduce funds available for operations and business opportunities, make us more vulnerable to competitive pressures or market downturns, and limit our financial and operational flexibility.

Our ability to service our debt will depend on, 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.

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We may not be able to execute any of these actions on satisfactory terms or at all.

Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash distributions at our intended levels.

Interest rates may increase in the future due to inflation, increased yields on U.S.

Treasury obligations, or otherwise.

In such cases, the interest rates on our floating-rate debt, including amounts outstanding under the RCF, would increase.

If interest rates rise, our future financing costs could increase accordingly.

In addition, as is true with other MLPs (the common units of which are often viewed by investors as yield-oriented securities), our unit price could be impacted by our implied distribution yield relative to market interest rates.

The distribution yield often is used by investors to compare and rank yield-oriented securities for investment decision-making purposes.

Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest-rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash distributions at intended levels.

We may not be able to obtain funding on acceptable terms or at all.

This may hinder or prevent us from meeting our future capital needs.

Global financial markets and economic conditions have been, and continue to be, volatile, especially for companies involved in the oil and gas industry.

The repricing of credit risk and the recent relatively weak industry conditions have made, and will likely continue to make, it difficult for some entities to obtain funding.

In addition, as a result of concerns about the stability and solvency of some of our counterparties, the cost of obtaining financing from

the credit markets generally has increased as many lenders and institutional investors have increased required rates of return, enacted tighter lending standards, refused to provide funding on terms similar to the borrower’s current debt, and reduced, or in some cases, ceased to provide funding to borrowers.

Further, we may be unable to obtain adequate funding under the RCF if our lending counterparties become unable to meet their funding obligations.

Due to these factors, we cannot be certain that funding will be available if needed and to the extent required on acceptable terms.

Our failure to maintain an adequate system of internal control over financial reporting could adversely affect our ability to accurately report our results.

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We face various security threats, including cyber-threats to the security of our facilities and infrastructure, attempts to gain unauthorized access to sensitive information or to render data or systems unusable, and terrorist acts.

Additionally, destructive forms of protests and opposition by activists and other disruptions, including acts of sabotage or eco-terrorism, against oil and natural-gas development and production or midstream processing or transportation activities could potentially result in damage or injury to persons, property, or the environment, or lead to extended interruptions of our or our customers’ operations.

Our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our facilities, infrastructure, and information may result in increased costs.

Additionally, destructive forms of protests by activists and other disruptions, including acts of sabotage or eco-terrorism, against oil and natural-gas-related activities could potentially result in damage or injury to persons, property, or the environment, or lead to extended interruptions of our or our customers’ operations.

Our implementation of procedures and controls to monitor and mitigate security threats and to increase security for our facilities, infrastructure, and information may result in increased costs.

There can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring.

Cyber-attacks, in particular, are becoming more sophisticated and include, but are not limited to, malicious software intended to gain unauthorized access to data and systems, electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data.

Cyber-attacks, in particular, are becoming more sophisticated and include malicious software intended to gain unauthorized access to data and systems, electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data.

For example, the gathering, processing, treating, and transportation of natural gas from our gathering systems, processing facilities, and pipelines are dependent on communications among our facilities and with third-party systems that may be delivering natural gas into or receiving natural gas and other products from our facilities.

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Any terrorist or cyber-attack against, or other disruption of, our assets or computer systems could have a material adverse effect on our business, results of operations, financial condition, and our ability to make cash distributions to our unitholders.

The amount of cash we have available for distribution to holders of our common units depends primarily on our cash flows rather than on our profitability.

As a result, we may be prevented from making distributions, even during periods in which we record net income.

The amount of cash we have available for distribution primarily depends on our cash flows and not solely on profitability as determined by GAAP, which will be affected by non-cash items.

The amount of available cash required to pay the distribution announced for the quarter ended December 31, 2019 , on all of our common units was $281.8 million , or $1.1 billion per year.

To the extent we do not have sufficient available cash under our partnership agreement, we may be unable to pay these distributions or similar distributions in the future.

We typically do not obtain independent evaluations of hydrocarbon reserves connected to our systems.

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If the total reserves or estimated life of the reserves connected to our systems are less than we anticipate, or the timeline for the development of reserves is greater than we anticipate, and we are unable to secure additional sources of oil and natural gas, there could be a material adverse effect on our business, results of operations, financial condition, and our ability to make cash distributions to our unitholders.

Our industry is highly competitive and increased competitive pressure could adversely affect our business and operating results.

We compete with similar enterprises in our areas of operation.

Our competitors may expand or construct midstream systems that would create additional competition for the services that we provide to our customers.

In addition, our customers, including Occidental, may develop their own midstream systems in lieu of using ours.

Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors and our customers.

All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition, and ability to make cash distributions to our unitholders.

Our results of operations could be adversely affected by asset impairments.

If commodity prices decline, we may be required to write down the value of our midstream properties if the estimated future cash flows from these properties fall below their respective net book values.

Because we are an affiliate of Occidental, the assets we previously acquired from Anadarko were recorded at Anadarko’s carrying value prior to the transaction.

If commodity prices remain depressed or decline further, and producer activity reduces accordingly, we may be required to write down the value of our midstream properties if the estimated future cash flows from these properties fall below their respective net book values.

Because we are a related party of Occidental, the assets we previously acquired from Anadarko were recorded at Anadarko’s carrying value prior to the transaction.

Accordingly, we may be at an increased risk for impairments because the initial book values of a substantial portion of our assets do not have a direct relationship with, and in some cases could be significantly higher than, the consideration paid to acquire such assets.

For example, see the discussion of material impairments in Note 8—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

Further, at December 31, 2019 , we had $445.8 million of goodwill recorded on our balance sheet.

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

In addition, similar to the carrying value of the assets we previously acquired from Anadarko, part of our goodwill is an allocated portion of Anadarko’s previously recorded goodwill that was allocated to us at the time we acquired assets from Anadarko, which was recorded as a component of the carrying value of the assets acquired from Anadarko.

As a result, we may be at increased risk for impairments relative to entities who acquire assets from third parties or construct their own assets, as the carrying value of our goodwill does not reflect, and in some cases is significantly higher than, the difference between the consideration we paid for our acquisitions and the fair value of the net assets on the acquisition date.

Goodwill is not amortized, but instead must be tested at least annually for impairment, and more frequently when circumstances indicate a likely impairment, by applying a fair-value-based test.

Goodwill is deemed impaired to the extent that its carrying amount exceeds its implied fair value.

Various factors could lead to goodwill impairments, such as our inability to maintain throughput on our systems or sustained lower oil and natural-gas prices, by reducing the fair value of the associated reporting unit.

Prolonged low or further declines in commodity prices and changes to producers’ drilling plans in response to lower prices could result in future impairments.

Future non-cash asset impairments could negatively affect our results of operations.

See the discussion of material impairments in Note 9—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

If third-party pipelines or other facilities interconnected to our gathering, transportation, treating, or processing systems become partially or fully unavailable, or if the volumes we gather or transport do not meet the quality requirements of such pipelines or facilities, our revenues and cash available for distribution could be adversely affected.

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The continuing operation of such third-party pipelines or facilities is not within our control.

If any of these pipelines or facilities becomes unable to transport, treat, or process crude oil, natural gas, or NGLs, or if the volumes we gather or transport do not meet the quality requirements of such pipelines or facilities, our revenues and cash available for distribution could be adversely affected.

Our interstate natural-gas and liquids transportation assets and operations are subject to regulation by FERC, which could have an adverse effect on our revenues and our ability to make distributions.

Our interstate natural-gas pipelines are subject to regulation by FERC.

If we fail to comply with all applicable FERC-administered statutes, rules, regulations, and orders, we could be subject to substantial penalties and fines.

FERC has civil penalty authority to impose penalties for certain violations potentially in excess of $1.0 million per day for each violation.

FERC also has the power to order the disgorgement of profits from transactions deemed to violate applicable statutes.

For additional information, read Regulation of Operations–Interstate Natural-Gas Pipeline Regulation under Items 1 and 2 of this Form 10-K.

Our interstate liquids pipelines are common carriers and also are subject to regulation by FERC.

For additional information, read Regulation of Operations—Interstate Liquids-Pipeline Regulation under Items 1 and 2 of this Form 10-K.

FERC regulation requires that common-carrier liquid-pipeline rates and interstate natural-gas pipeline rates be filed with FERC and that these rates be “just and reasonable” and not unduly discriminatory.

Interested persons may challenge proposed new or changed rates, and FERC is authorized to suspend the effectiveness of such rates pending an investigation or hearing.

FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively.

Accordingly, adverse action by FERC could affect our ability to establish reasonable rates that cover operating costs and allow for a reasonable return.

An adverse determination in any future rate proceeding brought by or against us could have a material adverse effect on our business, financial condition, results of operations, and cash available for distribution.

For example, one such matter relates to FERC’s policy regarding allowances for income taxes in determining a regulated entity’s cost of service.

FERC’s Revised Policy Statement established that FERC will no longer permit master limited partnerships to recover an income tax allowance in cost-of-service rates and noted that to the extent an entity does not include an income tax allowance in cost-of-service rates, such entity may elect to exclude the accumulated deferred income tax balance from the rate calculation.

This policy may result in an adverse impact on our revenues associated with the cost-of-service rates of our FERC-regulated gas and liquids pipelines.

For additional information, read Regulation of Operations—Interstate Natural-Gas Pipeline Regulation and Regulation of Operations—Interstate Liquids-Pipeline Regulation under Items 1 and 2 of this Form 10-K.

If any of these pipelines or facilities becomes unable to transport, treat, store, or process crude oil, natural gas, or NGLs, or if the volumes we gather or transport do not meet the quality requirements of such pipelines or facilities, our revenues and cash available for distribution could be adversely affected.

For example, during the market disruptions caused by the outbreak of COVID-19, there were concerns that domestic oil-storage capacity could reach operational limits.

If such an event had occurred, our customers might have shut-in field production due to limited downstream-takeaway alternatives or resulting wellhead economics.

If production is shut-in for these or for other reasons, affected producers may become insolvent or seek to avoid their contractual obligations with us, in which case, our earnings, cash flows from operations, and ability to make cash distributions to our unitholders could be materially and adversely impacted.

A change in the jurisdictional characterization of some of our assets by federal, state, or local regulatory agencies or a change in policy by those agencies could result in increased regulation of our assets, which could cause our revenues to decline and operating expenses to increase.

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For additional information, read Regulation of Operations–Natural-Gas Gathering Pipeline Regulation under Items 1 and 2 of this Form 10-K.

Adoption of new or more stringent climate-change or other air-emissions legislation or regulations restricting emissions of GHGs or other air pollutants could result in increased operating costs and reduced demand for the gathering, processing, compressing, treating, and transporting services we provide.

Changes to climate-change or other air-emissions laws and regulations, or reinterpretations of enforcement or other guidance with respect thereto, that govern the areas in which we operate may impact our operations negatively.

Examples of such proposed and/or final regulations or other regulatory initiatives are discussed below.

Ground-Level Ozone Standards.

In 2015, the EPA issued a rule under the Clean Air Act, lowering the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone from 75 parts per billion to 70 parts per billion under the primary and secondary standards to provide requisite protection of public health and welfare, respectively.

In 2017 and 2018, the EPA issued area designations with respect to ground-level ozone as either “attainment/unclassifiable,” “unclassifiable,” or “non-attainment.” Additionally, in November 2018, the EPA issued final requirements that apply to state, local, and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone.

State implementation of the revised NAAQS could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs.

Reduction of Methane Emissions by the Oil and Gas Industry.

In 2016, the EPA published a final rule establishing new emissions standards for methane and additional standards for volatile organic compounds from certain new, modified, and reconstructed oil and natural-gas production and natural-gas processing and transmission facilities.

The EPA’s rule is comprised of New Source Performance Standards (“NSPS”), known as Subpart OOOOa, which require certain new, modified, or reconstructed facilities in the oil and natural-gas sector to reduce methane gas and volatile organic compound emissions.

These Subpart OOOOa standards expand previously issued NSPS to, among other things, hydraulically fractured oil and natural-gas well completions, fugitive emissions from well sites and compressors, and equipment leaks at natural-gas processing plants and pneumatic pumps.

In February 2018, the EPA finalized amendments to certain requirements of the 2016 final rule and, in September 2018, the agency proposed amendments that included rescission or revision of specified rule requirements, such as fugitive emission monitoring frequency.

In August 2019, the EPA proposed two options for rescinding the Subpart OOOOa standards.

Under the EPA’s preferred alternative, the agency would rescind the methane limits for new, reconstructed, and modified oil and natural-gas production sources while leaving in place the general emission limits for volatile organic compounds (“VOCs”) and relieve the EPA of its obligation to develop guidelines for methane emissions from existing sources.

In addition, the proposal would remove from the oil and natural-gas category the natural-gas transmission and storage segment.

The other proposed alternative would rescind the methane requirements of the NSPS applicable to all oil and natural-gas sources, without removing any sources from that category (and still requiring control of VOCs in general).

In a separate rulemaking, the BLM published a final rule in late 2016 that requires a reduction in methane emissions by regulating venting, flaring, and leaking from oil and natural-gas operations on public lands;

however, in September 2018, the BLM published a final rule rescinding most of the new requirements of the 2016 final rule and codifying the BLM’s prior approach to venting and flaring, which rescission has been challenged in federal court and remains pending.

Notwithstanding the uncertainty of the 2016 rule, we have taken measures to enter into a voluntary regime, together with certain other oil and natural-gas exploration and production operators, to reduce methane emissions.

At the state level, some states where we conduct operations, including Colorado, have issued requirements for the performance of leak detection programs that identify and repair methane leaks at certain oil and natural-gas sources.

Compliance with these rules or with any future federal or state methane regulations could, among other things, require installation of new emission controls on some of our equipment and increase our capital expenditures and operating costs.

Reduction of GHG Emissions.

Congress and the EPA, in addition to some state and regional authorities, have in recent years considered legislation or regulations to reduce emissions of GHGs.

These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG-reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.

In the absence of federal GHG-limiting legislation, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations that, among other things, restrict emissions of GHGs under existing provisions of the Clean Air Act and may require the installation of “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future if they would otherwise emit large volumes of GHGs together with other criteria pollutants.

Also, certain of our operations are subject to EPA rules requiring the monitoring and annual reporting of GHG emissions from specified onshore and offshore production sources.

Additionally, in April 2016, the United States joined other countries in entering into a United Nations-sponsored non-binding agreement negotiated in Paris, France (“Paris Agreement”) for nations to limit their GHG emissions through individually determined reduction goals every five years beginning in 2020.

However, in August 2017, the U.S.

State Department informed the United Nations of the intent of the United States to withdraw from the Paris Agreement, and in November 2019 the United States formally initiated the withdrawal process.

The implementation of substantial limitations on GHG emissions in areas where we conduct operations could result in increased compliance costs to acquire emissions allowances or comply with new regulatory or reporting requirements, which developments could adversely affect demand for oil and natural gas that our customers produce, reduce demand for our services, and have a material adverse effect on our business, financial condition, and results of operation.

Derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity-price, interest-rate, and other risks associated with our business.

The Dodd-Frank Act, among other things, establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market.

The CFTC has finalized certain of its regulations under the Dodd-Frank Act, but others remain to be finalized or implemented.

It is not possible at this time to predict when this will be accomplished or what the terms of the final rules will be, so the impact of those rules is uncertain at this time.

The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, and reduce the availability of derivatives to protect against risks we encounter.

We may incur significant costs and liabilities resulting from pipeline-integrity programs and related repairs.

Pursuant to authority under federal law, PHMSA has promulgated regulations requiring pipeline operators to develop and implement integrity-management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect HCAs, which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources, and unusually sensitive ecological areas.

These regulations require the operators of covered pipelines to:

(i) perform ongoing assessments of pipeline integrity;

(ii) identify and characterize applicable threats to pipeline segments that could impact HCAs;

(iii) improve data collection, integration, and analysis;

(iv) repair and remediate the pipeline as necessary;

and (v) implement preventive and mitigating actions.

In addition, states have adopted regulations similar to existing PHMSA regulations for certain intrastate gas and hazardous liquid pipelines.

At this time, we cannot predict the ultimate cost of compliance with these regulations, as the cost will vary significantly depending on the number and extent of any repairs or replacements of pipeline segments found to be necessary as a result of the pipeline-integrity testing.

The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures for repairs or replacements of pipeline segments deemed necessary to ensure the safe and reliable operation of our pipelines.

Moreover, the adoption of any new legislation or regulations that impose more-stringent or costly pipeline-integrity management could result in a material adverse effect on our results of operations or financial position.

For additional information regarding PHMSA regulations, read Regulation of Operations—Natural-Gas Gathering Pipeline Regulation under Items 1 and 2 of this Form 10-K.

Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more-stringent safety controls or result in more-stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays, and costs of operation .

Adoption of new or more stringent climate-change or other air-emissions legislation or regulations restricting emissions of GHGs or other air pollutants could negatively impact us, our producer customers, or downstream customers by increasing operating costs and reducing volumetric throughput on our systems due to reduced demand for the gathering, processing, compressing, treating, and transporting services we provide.

The threat of climate change continues to attract considerable attention in the United States and foreign countries.

Numerous proposals have been made and could continue to be made at the international, national, regional, and state levels of government to monitor and limit emissions of GHGs, as well as to restrict or eliminate such future emissions.

Further, new legislation, policies, or regulations may inhibit development plans of our producer customers, which could result in lower volumes transported across our assets.

Changes to climate-change or other air-emissions

laws and regulations, or reinterpretations of enforcement or other guidance with respect thereto, that govern the areas in which we operate may impact our operations negatively by increasing our compliance costs and the compliance costs of our customers.

In addition, in response to concerns related to climate change, companies in the fossil fuel sector may be exposed to increasing financial risks.

Financial institutions, including investment advisors and certain sovereign wealth, pension and endowment funds, may elect in the future to shift some or all of their investment into non-fossil fuel related sectors.

A material reduction in capital available to the energy industry could make it more difficult to secure funding for exploration, development, production, and transportation activities, which could result in decreased demand for our services, or difficulty in securing capital for new construction projects.

For additional information read, “ Environmental Matters ” under Items 1 and 2 of this Form 10-K.

Federal and state legislative and regulatory initiatives relating to pipeline safety and integrity management that require the performance of ongoing assessments and implementation of preventive measures, the use of new or more-stringent safety controls or result in more-stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays, and costs of operation .

Legislation adopted in recent years has resulted in more-stringent mandates for pipeline safety and has charged PHMSA with developing and adopting regulations that impose increased pipeline-safety requirements on pipeline operators.

In 2016, President Obama signed the 2016 Pipeline Safety Act that extended PHMSA’s statutory mandate regarding pipeline safety through 2019, expanded PHMSA’s authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment, and required the agency to complete certain of its outstanding mandates established under the 2011 Pipeline Safety Act.

The imposition of new safety requirements pursuant to these enacted laws or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which could result in our incurring increased capital expenditures and operating costs that could have a material adverse effect on our results of operations or financial position.

For instance, pursuant to its authority under federal law, PHMSA has promulgated regulations requiring pipeline operators to develop and implement integrity-management programs for certain gas and hazardous liquid pipelines that, in the event of a pipeline leak or rupture, could affect HCAs, which are areas where a release could have the most significant adverse consequences, including high-population areas, certain drinking water sources, and unusually sensitive ecological areas.

These regulations require the operators of covered pipelines to, among other things, perform ongoing assessments of pipeline integrity and implement preventive and mitigating actions.

The imposition of new pipeline safety or integrity management requirements pursuant to existing federal laws or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis, any or all of which could result in our incurring increased capital expenditures and operating costs that could have a material adverse effect on our results of operations or financial position.

For additional information regarding PHMSA regulations, read Regulation of Operations—Natural-Gas Gathering Pipeline Regulation under Items 1 and 2 of this Form 10-K.

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In addition, stricter laws, regulations, or enforcement policies could increase our operational or compliance costs and the costs of any restoration or remedial actions that may become necessary, which could have a material adverse effect on our results of operations or financial condition.

Regulatory initiatives targeting the reduction of certain air pollutants, such as ground level ozone or GHGs such as methane, have been proposed and/or adopted by the EPA and, while subject to further implementation or various legal impediments, could result in increased compliance costs.

The adoption of these or any other laws, regulations, or other legally enforceable mandates could increase our oil and natural-gas exploration and production customers’ operating and compliance costs and reduce the rate of production of oil or natural gas by operators with whom we have a business relationship, which could have a material adverse effect on our results of operations and cash flows.

In addition, the legal requirements related to the disposal of produced water into non-producing geologic formations by means of underground injection wells are subject to change based on public and governmental-authority concerns regarding such disposal activities.

One such concern relates to seismic events near injection wells used for the disposal of produced water resulting from oil and natural-gas activities.

In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced-water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells.

For example, Colorado developed and follows guidance when issuing underground injection-control permits to limit the maximum-injection pressure, rate, and volume of water.

Oklahoma has issued rules for wastewater disposal wells that impose certain permitting and operating restrictions and reporting requirements on disposal wells in proximity to faults and also, from time to time, is developing and implementing plans directing operators of wells injecting at certain depths where seismic incidents have occurred to restrict or suspend disposal-well operations.

The Texas Railroad Commission has adopted similar permitting, operating, and reporting rules for disposal wells.

Another consequence of seismic events may be class action lawsuits alleging that disposal-well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal.

One or more of these developments could result in additional regulation and restrictions on our use of injection wells, which could have a material adverse effect on our capital expenditures and operating costs, financial condition, and results of operations.

The adoption of any laws, regulations, or other legally enforceable mandates could increase our oil and natural-gas exploration and production customers’ operating and compliance costs and reduce the rate of production of oil or natural gas by operators with whom we have a business relationship, which could have a material adverse effect on our results of operations and cash flows.

Our construction of new assets may not result in revenue increases and is subject to regulatory, environmental, political, legal, and economic risks, which could adversely affect our results of operations and financial condition.

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In addition, construction activities could be subject to state, county, and local ordinances that restrict the time, place, or manner in which those activities may be conducted.

Construction projects also may require the expenditure of significant amounts of capital and financing may not be available on economically acceptable terms or at all.

If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all.

For example, construction activities may be delayed or require greater capital investment if the commodity prices of certain supplies such as steel pipe increase due to foreign tariffs.

In addition, our revenues may not increase immediately upon the expenditure of funds on a particular project.

For instance, if we expand a pipeline, the construction may occur over an extended period of time, yet we will not receive any material increases in revenues until the project is completed.

Moreover, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize.

Since we are not engaged in the exploration for and development of natural-gas and oil reserves, we often do not have access to estimates of potential reserves in an area prior to constructing facilities in that area.

To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate as a result of the numerous uncertainties inherent in estimating quantities of future production.

As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could affect our results of operations and financial condition adversely.

In addition, the construction of additions to our existing assets may require us to obtain new rights-of-way.

We may be unable to obtain such rights-of-way and may, therefore, be unable to connect new natural-gas volumes to our systems or capitalize on other attractive expansion opportunities.

Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way.

If the cost of renewing existing or obtaining new rights-of-way increases, our cash flows could be affected adversely.

We have partial ownership interests in several joint-venture legal entities that we do not operate or control.

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We do not own all of the land on which our pipelines and facilities have been constructed, and we therefore are, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate.

We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time.

We cannot guarantee that we always will be able to renew existing rights-of-way or obtain new rights-of-way without experiencing significant costs.

Any loss of rights with respect to our real property, through our inability to renew existing rights-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial position, and ability to make cash distributions to our unitholders.

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If a significant accident or event occurs for which we are not fully insured, our operations and financial results could be adversely affected.

Our operations are subject to all of the risks and hazards inherent in gathering, processing, compressing, treating, and transporting natural gas, crude oil, NGLs, and produced water, including the following:

damage to pipelines and plants, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires, and other natural disasters, and acts of terrorism;

inadvertent damage from construction, farm, and utility equipment;

leaks or losses of hydrocarbons or produced water as a result of the malfunction of equipment or facilities;

fires and explosions (for example, see Items Affecting the Comparability of Our Financial Results , under Part II, Item 7 of this Form 10-K for a discussion of the incident at the DBM complex);

other hazards that could also result in personal injury, loss of life, pollution, property or natural resource damages, and/or curtailment or suspension of operations.

(ii) inadvertent damage from construction, farm, and utility equipment;

(iii) leaks or losses of hydrocarbons or produced water;

(iv) fires and explosions;

and (v) other hazards that could also result in personal injury, loss of life, pollution, property or natural resource damages, and/or curtailment or suspension of operations.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment, and pollution or other environmental or natural-resource damage.

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Additionally, we may be unable to recover from prior owners of our assets, pursuant to certain indemnification rights, for potential environmental liabilities.

Any acquisitions we pursue create additional execution and other risks and may or otherwise fail to meet our expectations.

Any future acquisitions involve potential additional risks, which may be of a different nature or magnitude from those currently affecting our business, including the following:

mistaken assumptions about volumes or the timing of the delivery of volumes, revenues or costs, including synergies;

an inability to successfully integrate the acquired assets or businesses;

the assumption of unknown liabilities, including environmental liabilities;

limitations on rights to indemnity from the seller;

mistaken assumptions about the overall costs of equity or debt;

the diversion of management’s and employees’ attention to other business concerns;

unforeseen difficulties operating in new geographic areas;

customer or key employee losses at the acquired businesses.

If we consummate any future acquisitions, our capital structure and results of operations may change significantly.

We are subject to increasing scrutiny from institutional investors with respect to our governance structure and the social cost of our industry, which may adversely impact our ability to raise capital from such investors.

In recent years, certain institutional investors, including public pension funds, have placed increasing importance on the implications and social cost of environmental, social, and governance (“ESG”) matters.

We are subject to increased scrutiny from institutional investors with respect to our governance structure and the social cost of our industry, which may adversely impact our ability to raise capital from such investors.

In recent years, certain institutional investors, including public pension funds, have placed increased importance on the implications and social cost of environmental, social, and governance (“ESG”) matters.

ESG initiatives generally seek to divert investment capital from companies involved in certain industries or with disfavored governance structures.

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Investors’ increased focus and activism related to ESG and similar matters may constrain our ability to raise capital.

Any material limitations on our ability to access capital as a result of such scrutiny could limit our ability to obtain future financing on favorable terms, or at all, or could result in increased financing costs in the future.

Any material limitations on our ability to access capital as a result of such scrutiny could limit our ability to

obtain future financing on favorable terms, or at all, or could result in increased financing costs in the future.

Similarly, such activism could negatively impact our unit price, limiting our ability to raise capital through equity issuances or debt financing, or could negatively affect our ability to engage in, expand or pursue our or its business activities, and could also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.

The loss of, or difficulty in attracting and retaining, experienced personnel could reduce our competitiveness and prospects for future success.

The successful execution of our growth strategy and other activities integral to our operations depends, in part, on our ability to attract and retain experienced engineering, operating, commercial, and other professionals.

Competition for such professionals historically has been intense.

If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be adversely impacted.

RISKS INHERENT IN AN INVESTMENT IN US

Occidental owns our general partner, which has sole responsibility for conducting our business and managing our operations.

Occidental and our general partner have conflicts of interest with, and may favor Occidental’s interests to the detriment of our unitholders.

Occidental, the owner of our general partner, owns a 53.4% limited partner interest in us.

Conflicts of interest may arise between (i) Occidental and our general partner and (ii) us and our unitholders.

In resolving these conflicts of interest, our general partner may favor its own interests and the interests of Occidental over our interests and the interests of our unitholders.

These conflicts include, among others, the following situations:

Neither our partnership agreement nor any other agreement requires Occidental to pursue a business strategy that favors us.

Occidental is not limited in its ability to compete with us and may offer business opportunities or sell midstream assets to parties other than us.

Our general partner is allowed to take into account the interests of parties other than us, such as Occidental, in resolving conflicts of interest.

Our partnership agreement limits the liability of, and reduces the default state law fiduciary duties owed by, our general partner, and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty under state law.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

Our general partner may cause us to borrow funds in order to permit the payment of cash distributions.

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

Our general partner has limited, and intends to continue to limit, its liability regarding our contractual and other obligations.

Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.

Read Part III, Item 13 of this Form 10-K for additional information.

A reduction in Occidental’s ownership interest in us may reduce its incentive to support our operations.

As discussed in WES and WES Operating’s Relationship with Occidental Petroleum Corporation in Part I, Items 1 and 2 of this Form 10-K, we believe that one of our principal strengths is our relationship with Occidental, and that Occidental, through its significant economic interest in us, will continue to be motivated to promote and support the successful execution of our business plan and to pursue projects that enhance the value of our business.

As discussed in WES and WES Operating’s Relationship with Occidental Petroleum Corporation in Part I, Items 1 and 2 of this Form 10-K, we believe that one of our principal strengths is our affiliation with Occidental and that Occidental, through its significant economic interest in us, will continue to pursue projects that enhance the value of our business.

To the extent Occidental’s net interest in us declines through the sale of its holdings or otherwise, Occidental may be less incentivized to support the continued growth of our business.

Accordingly, a decrease in Occidental’s net holdings in us could have a material adverse effect on our business, results of operations, financial position, and ability to grow or make cash distributions to our unitholders.

Occidental is not limited in its ability to compete with us, which could limit our ability to grow and could affect our results of operations and cash available for distribution to our unitholders adversely.

Occidental is not prohibited from owning assets or engaging in businesses that directly or indirectly compete with us.

In addition, in the future, Occidental may acquire, construct, or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to participate in such transactions.

Cost reimbursements due to Occidental and our general partner for services provided to us or on our behalf are substantial and reduce our cash available for distribution to our unitholders.

Prior to making distributions on our common units, we reimburse Occidental, which owns our general partner, and its affiliates for expenses incurred on our behalf as determined by our general partner pursuant to the Services Agreement.

These expenses include all costs incurred by Occidental and our general partner in managing and operating us, and the reimbursement of certain general and administrative expenses we incur as a result of being a publicly traded partnership.

Our partnership agreement and the Services Agreement provide that Occidental will determine in good faith the expenses that are allocable to us.

Our general partner may, in good faith, significantly increase the amount of reimbursable general and administrative expenses in the future and any decision to do so would reduce the amount of cash otherwise available for distribution to our unitholders.

If you are not an Eligible Holder, you may not receive distributions or allocations of income or loss on your common units and your common units will be subject to redemption.

We have adopted certain requirements regarding investors that own our common units.

Eligible Holders are U.S.

individuals or entities subject to U.S.

federal income taxation on the income generated by us or entities not subject to U.S.

federal income taxation on the income generated by us, so long as all of the entity’s owners are U.S.

individuals or entities subject to U.S.

If you are not an Eligible Holder, our general partner may elect not to make distributions or allocate income or loss on your units and you bear the risk of having your units redeemed by us at the lower of your purchase-price cost and the then-current market price.

The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.

Our general partner’s liability regarding our obligations is limited.

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Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units.

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that modify and reduce the fiduciary standards to which our general partner otherwise would be held by state fiduciary duty law.

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This entitles our general partner only to consider the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates, or our limited partners.

Examples of decisions that our general partner may make in its individual capacity include the following:

how to allocate corporate opportunities among us and its affiliates;

how to exercise voting rights with respect to the units it owns;

whether to exercise its registration rights;

whether to consent to any merger or consolidation of the Partnership or amendment to the partnership agreement.

By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the above-described provisions.

Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law.

Furthermore, our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law.

For example, our partnership agreement:

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• provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal;

provides that our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is any of the following:

approved by the Special Committee of the Board of Directors, although our general partner is not obligated to seek such approval;

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;

on terms no less favorable to us than those generally being provided to or available from unrelated third parties;

fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In situations involving an affiliate transaction or a conflict of interest, any determination by our 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 Special Committee and the Board of Directors 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) and (d) above, then it will be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such good-faith presumption.

• provides that, in the absence of bad faith, our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.

The general partner interest in us may be transferred to a third party without unitholder consent.

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Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders.

The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

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

the amount of per-unit cash available for distribution may decrease;

the ratio of taxable income to distributions may increase;

the relative voting strength of each previously outstanding unit may be diminished;

the market price of the common units may decline.

The issuance by us of additional common units or other equity securities of equal or senior rank will dilute our existing unitholders’ ownership interests and voting strength, and may reduce the market price for our common units and cash available for distribution or increase the ratio of taxable income to distributions.

The market price of our common units could be affected adversely by sales of substantial amounts of our common units in the public or private markets, including sales by Occidental or other large holders.

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Occidental currently holds 214,281,578 common units, representing 51.8% of our outstanding common units.

Occidental’s shelf registration statement allows for the offer and sale of up to 50 million common units, or 11.3% of our common units as of December 31, 2019 , from time to time.

Occidental’s shelf registration statement currently allows for the offer and sale of approximately 41.8 million common units, or 10.1% of our common units as of December 31, 2020, from time to time.

Sales by Occidental or other large holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities.

In addition, under our partnership agreement, our general partner and its affiliates, including Occidental, have registration rights relating to the offer and sale of any units that they hold, subject to certain limitations.

Unitholders’ 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.

Our partnership is organized under Delaware law, and we conduct business in a number of other states.

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 other states in which we do business.

A unitholder could be liable for any and all of our obligations as if that unitholder were a general partner if a court or government agency were to determine that:

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

such unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other actions under our partnership agreement constitute “control” of our business.

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

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Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

If we are deemed to be an “investment company” under the Investment Company Act of 1940, it would affect the price of our common units adversely and could have a material adverse effect on our business.

Our assets include, among other items, a $260.0 million note receivable from Anadarko.

If this note receivable, together with a sufficient amount of our other assets are deemed to be “investment securities,” within the meaning of the Investment Company Act of 1940 (the “Investment Company Act”), we either would have to register as an investment company under the Investment Company Act, obtain exemptive relief from the SEC, or modify our organizational structure or contract rights so as to fall outside of the definition of an investment company.

Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property from or to our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage, and require us to add additional directors who are independent of us or our affiliates.

The occurrence of some or all of these events would affect the price of our common units adversely and could have a material adverse effect on our business.

Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes, in which case we would be treated as a corporation for federal income tax purposes.

As a result, we would pay federal and possibly state income taxes on our taxable income at applicable corporate tax rates;

distributions received by our unitholders generally would be taxed as corporate distributions;

and none of our income, gains, losses, or deductions would flow through to our unitholders.

If we were taxed as a corporation, our cash available for distribution to our unitholders would be reduced substantially.

Therefore, treatment of us as an investment company would result in a material reduction in the anticipated cash flows and after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

The market price of our common units could be volatile due to a number of factors, many of which are beyond our control.

The market price of our common units could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including the following:

changes in investor or analyst estimates of Occidental’s and our financial performance or our future distribution growth;

the public’s reaction to Occidental’s or our press releases, announcements, and filings with the SEC;

legislative or regulatory changes affecting our status as a partnership for federal income tax purposes;

fluctuations in broader securities market prices and volumes, particularly among securities of midstream companies and securities of publicly traded limited partnerships;

changes in market valuations of similar companies;

departures of key personnel;

commencement of or involvement in litigation;

variations in our quarterly results of operations or those of other midstream companies;

variations in the amount of our quarterly cash distributions;

future issuances and sales of our common units;

changes in general conditions in the U.S.

economy, financial markets, or the midstream industry.

In recent years, the capital markets have experienced extreme volatility that has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies.

Future market fluctuations may result in a lower price of our common units.

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

Our partnership is organized under Delaware law, and we conduct business in a number of other states.

A unitholder could be liable for any and all of our obligations as if that unitholder were a general partner if a court or government agency were to determine that we were conducting business in a state, but had not complied with that particular state’s partnership statute, or such unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other actions under our partnership agreement constitute “control” of our business.

TAX RISKS TO COMMON UNITHOLDERS

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federal income tax laws that would affect publicly traded partnerships, including elimination of partnership tax treatment for 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 Section 7704(d)(1)(E) of the Code, which we rely on for our status 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.

There can be no assurance that there will not be further changes to U.S.

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.

We believe the income that we treat as qualifying income satisfies the requirements under current regulations.

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

Any modification to the U.S.

federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible for us to satisfy the requirements to be treated as a partnership for U.S.

federal income tax purposes and could impact the value of an investment in our common units negatively.

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

federal income tax purposes or increase the amount of taxes payable by unitholders in publicly traded partnerships.

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.

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Moreover, the costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.

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 reduced substantially.

In addition, our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders’ behalf.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us.

To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder and former unitholder with respect to an audited and adjusted return.

Although our general partner may elect to have our unitholders and former unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their respective interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible, or effective in all circumstances.

As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year for which an adverse audit finding relates.

If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties, and interest, our cash available for distribution to our unitholders might be reduced substantially and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders’ behalf.

These rules are not applicable for tax years beginning on or prior to December 31, 2017.

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

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us.

Generally, we expect to elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, but there can be no assurance that such election will be made, or applicable, in all circumstances.

If we are unable to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the economic burden resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit.

If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties, and interest, our cash available for distribution to our unitholders might be substantially reduced.

Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Our unitholders are required to pay any U.S.

federal income taxes and, in some cases, state and local income taxes on their share of our taxable income irrespective of whether they receive cash distributions from us.

For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, unitholders may be allocated taxable income and gain resulting from the sale, and our cash available for distribution would not increase.

Similarly, taking advantage of opportunities to reduce our existing debt, including debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” being allocated to our unitholders as taxable income without any increase in our cash available for distribution.

Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability attributable to their share of our taxable income.

federal income taxes on their share of our taxable income irrespective of whether they receive cash distributions from us.

Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability attributable to their share of our taxable income.

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

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

A substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items such as depreciation.

In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if they sell their units, unitholders may incur a tax liability in excess of the amount of cash they receive from the sale.

Irrespective of whether a unitholder’s disposition of common units results in a gain, a substantial portion of the amount realized from a unitholder’s sale of units may be taxed as ordinary income to the unitholder due to potential recapture of items, including depreciation recapture.

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

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

In the taxable period in which a unitholder sells units, the unitholder may recognize ordinary income from our allocations of income and gain prior to the sale and from recapture items, which generally cannot be offset by any capital loss recognized on the sale of units.

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

Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (or “IRAs”) raises unique issues.

For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be taxable as unrelated business taxable income.

Further, for taxable years beginning after December 31, 2017, subject to the Treasury Department’s proposed aggregation rules regarding certain similarly situated businesses or activities, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trades or businesses) 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 taxable years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in us 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.

unitholders will be subject to U.S.

taxes and withholding on income and gain from owning our units.

unitholders generally are taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S.

trade or business (“effectively connected income”).

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

trade or business.

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

unitholder are subject to withholding at the highest applicable effective tax rate and a non-U.S.

unitholder who sells or otherwise disposes of a unit also is subject to U.S.

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

The Tax Cuts and Jobs Act imposes a withholding obligation of 10% of the amount realized on a non-U.S.

unitholder’s sale or exchange of an interest in a partnership that is engaged in a U.S.

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

Investment in common units by tax-exempt entities, such as employee benefit plans, individual retirement accounts (or “IRAs”) and foreign persons raises issues unique to them.

For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them.

Distributions to foreign persons will be reduced by withholding taxes at the highest applicable effective tax rate, and foreign persons will be required to file U.S.

federal tax returns and pay tax on their share of our taxable income.

Upon the sale, exchange or other disposition of a common unit by a foreign unitholder, the transferee is generally required to withhold 10% of the amount realized on such sale, exchange or other disposition if any portion of the gain on such sale, exchange, or other disposition would be treated as effectively connected with a U.S.

trade or business.

However, due to challenges of administering a withholding obligation applicable to open-market trading and other complications, the IRS temporarily has suspended the application of this withholding obligation to open-market transfers of interests in publicly traded partnerships, pending promulgation of final regulations.

It is not clear when such final regulations will be issued.

unitholders should consult a tax advisor before investing in our common units.

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

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

Because we cannot match transferors and transferees of common units, we have adopted certain methods of allocating depreciation and amortization deductions that may not conform with all aspects of existing Treasury Regulations.

A successful IRS challenge to the use of these methods could diminish the amount of tax benefits available to our unitholders, affect the timing for recognition of these tax benefits or the amount of gain from any sale of common units, impact the value of our common units negatively, or result in audit adjustments to unitholders’ tax returns.

Department of the Treasury and the IRS have recently issued final regulations providing guidance on the application of these rules for transfers of certain publicly traded partnership interests, including our common units.

Under these regulations, the “amount realized” on a transfer of our common 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.

Distributions to foreign unitholders may also be subject to additional withholding under these rules to the extent a portion of a distribution is attributable to an amount in excess of our cumulative net income that has not previously been distributed.

Department of the Treasury and the IRS have provided that these rules will generally not apply to transfers of our common units occurring before January 1, 2022.

Foreign unitholders should consult their tax advisor before investing in our common units.

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

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

Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets, and, 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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If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss, and deduction among our unitholders.

A unitholder whose common units are the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered to have disposed of those common units.

If so, the unitholder would no longer be treated as a partner for tax purposes with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned units.

In that case, the unitholder may no longer be treated as a partner for tax purposes with respect to those common units during the period of the loan, and the unitholder may recognize gain or loss from such deemed disposition.

Moreover, during the period of the loan, any of our income, gain, loss, or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income.

Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from lending their common units.

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

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and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions.

Our unitholders likely will be required to file foreign, 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 those requirements.

As we make acquisitions or expand our business, we may own assets or conduct business in additional states or foreign jurisdictions that impose a personal income tax.

It is the responsibility of each unitholder to file all U.S.

federal, foreign, state, and local tax returns.

Our unitholders likely will be required to file tax returns and pay taxes in some or all of these various jurisdictions, or be subject to penalties for failure to comply with those requirements.

Unresolved Staff Comments

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