Western Midstream Partners 10-K2021 FY Annual report

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FILING FORMAT

This annual report on Form 10-K is a combined report being filed by two separate registrants: Western Midstream Partners, LP and Western Midstream Operating, LP. Western Midstream Operating, LP is a consolidated subsidiary of Western Midstream Partners, LP that has publicly traded debt, but does not have any publicly traded equity securities. Information contained herein related to any individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating exclusively to the other registrant.

TABLE OF CONTENTS

Unless the context otherwise requires, references to “we,” “us,” “our,” “WES,” “the Partnership,” or “Western Midstream Partners, LP” refer to Western Midstream Partners, LP (formerly Western Gas Equity Partners, LP) and its subsidiaries. As used in this Form 10-K, the terms and definitions below have the following meanings:

PART I

GENERAL OVERVIEW

We are engaged in the business of gathering, compressing, treating, processing, and transporting natural gas; gathering, stabilizing, and transporting condensate, NGLs, and crude oil; and gathering and disposing of produced water. In our capacity as a natural-gas processor, we also buy and sell natural gas, NGLs, and condensate on behalf of ourselves and as an agent for our customers under certain contracts.

Our Corporate Governance Guidelines, Code of Ethics and Business Conduct, Partner Code of Conduct, and the charters of the Audit Committee, the Special Committee, the ESG Committee, and the Compensation Committee of our Board are available on our website. We will also provide, free of charge, a copy of any of our governance documents listed above upon written request to our general partner’s secretary at our principal executive office. Our principal executive office is located at 9950 Woodloch Forest Drive, Suite 2800, The Woodlands, TX 77380. Our telephone number is 346-786-5000.

ASSETS AND AREAS OF OPERATION

As of December 31, 2021, our assets and investments consisted of the following:

These assets and investments are located in Texas, New Mexico, the Rocky Mountains (Colorado, Utah, and Wyoming), and North-central Pennsylvania. The following table provides information regarding our assets by geographic region, as of and for the year ended December 31, 2021:

Our operations are organized into a single operating segment that engages in gathering, compressing, treating, processing, and transporting natural gas; gathering, stabilizing, and transporting condensate, NGLs, and crude oil; and gathering and disposing of produced water. See Part II, Item 8 of this Form 10-K for disclosure of revenues and operating income (loss) for the years ended December 31, 2021, 2020, and 2019, and total assets for the years ended December 31, 2021 and 2020.

ACQUISITIONS AND DIVESTITURES

STRATEGY

Our primary business objective is to create long-term value for our unitholders through continued delivery of profitable operations and return of capital to stakeholders over time. Our foundational principles of operational excellence, superior customer service, and sustainable operations influence our decision making and long-term strategy. To accomplish our primary business objective, we intend to execute the following strategy:

COMPETITIVE STRENGTHS

We believe that we are well positioned to successfully execute our strategy and achieve our primary business objective because of the following competitive strengths:

WES AND WES OPERATING’S RELATIONSHIP WITH OCCIDENTAL PETROLEUM CORPORATION

The officers of our general partner manage our operations and activities under the direction and supervision of the Board of our general partner, which is a wholly owned subsidiary of Occidental. Occidental is among the largest independent oil and gas exploration and production companies in the world. Occidental’s upstream oil and gas business explores for, develops, and produces crude oil and condensate, NGLs, and natural gas.

As of December 31, 2021, Occidental held (i) 200,281,578 of our common units, representing a 48.6% limited partner interest in us, (ii) through its ownership of the general partner, 9,060,641 general partner units, representing a 2.2% general partner interest in us, and (iii) a 2.0% limited partner interest in WES Operating through its ownership of WGRAH, which is reflected as a noncontrolling interest within our consolidated financial statements. As of December 31, 2021, Occidental held 49.7% of our outstanding common units.

For the year ended December 31, 2021, 57% of Total revenues and other, 36% of our throughput for natural-gas assets (excluding equity-investment throughput), 89% 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. While Occidental is our contracting counterparty, these arrangements with Occidental include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market. In addition, Occidental provides dedications, minimum-volume commitments with associated deficiency payments, and/or cost-of-service commitments under certain of our contracts.

Historically, we sold a significant amount of our natural gas and NGLs to AESC, Occidental’s marketing affiliate. In addition, we purchased natural gas from AESC pursuant to purchase agreements. While we still have some marketing arrangements with affiliates of Occidental, we began marketing and selling substantially all of our natural gas and NGLs directly to third parties beginning on January 1, 2021.

Pursuant to the Services Agreement entered into as part of the December 2019 Agreements, Occidental agreed to (i) continue to provide certain administrative and operational services to us for up to a two-year transition period, and (ii) transfer certain Occidental employees to the Partnership, with the Partnership assuming liabilities relating to those employees at the time of their transfer. In late March 2020, seconded employees’ employment was transferred to the Partnership. Most of the administrative and operational services previously provided by Occidental fully transitioned to the Partnership by December 31, 2021, with certain limited transition services remaining in place pursuant to the terms of the Services Agreement.

INDUSTRY OVERVIEW

The midstream industry is the link between the exploration for and production of natural gas, NGLs, and crude oil and the delivery of these hydrocarbon components to end-use markets. Operators within this industry create value at various stages along the midstream value chain by gathering production from producers at the wellhead or production facility, separating the produced hydrocarbons into various components, delivering these components to end-use markets, and where applicable, gathering and disposing of produced water.

The following diagram illustrates the primary groups of assets found along the midstream value chain:

Midstream companies provide services with respect to natural gas that are generally classified into the categories described below.

Midstream companies provide services with respect to crude oil that are generally classified into the categories described below.

Midstream companies provide services with respect to produced water that are generally classified into the categories described below.

Midstream services, other than transportation, are usually provided under contractual arrangements that vary in terms of exposure to commodity-price risk. Three typical contract types, or combinations thereof, include the following:

PROPERTIES

The following sections describe in more detail the services provided by our assets in our areas of operation as of December 31, 2021.

    

COMPETITION

The midstream services business is extremely competitive, and our competitors include other midstream companies, producers, and intrastate and interstate pipelines. Competition primarily is based on reputation, commercial terms, reliability, service levels, location, available capacity, capital expenditures, and fuel efficiencies. Competition levels vary in our geographic areas of operation and is greatest in areas experiencing heightened producer activity and during periods of high commodity prices. Notwithstanding, Occidental and third-party producers provide certain dedications and/or minimum-volume commitments in our significant areas of operation. We believe that our assets located outside of dedicated areas, whether in or out of the aforementioned significant areas of operation, are geographically well-positioned to retain and attract both Occidental and third-party volumes.

We believe the primary advantages of our assets include proximity to established and/or future production and the available service flexibility provided to producers. We believe we can efficiently, and at competitive and flexible contract terms, provide services that customers require to gather, compress, treat, process, and transport natural gas; gather, stabilize, and transport condensate, NGLs, and crude oil; and gather and dispose of produced water.

REGULATION OF OPERATIONS

Many of the pipelines we use to gather and transport oil, natural gas, and NGLs are subject to regulation by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), an agency under the U.S. Department of Transportation, pursuant to the Natural Gas Pipeline Safety Act of 1968, as amended (the “NGPSA”), with respect to natural gas, and the Hazardous Liquids Pipeline Safety Act of 1979, as amended (the “HLPSA”), with respect to NGLs and oil. The NGPSA and HLPSA govern the design, installation, testing, construction, operation, replacement, and management of natural-gas, crude-oil, NGLs, and condensate pipeline facilities. Pursuant to these acts, PHMSA has promulgated regulations governing, among other things, pipeline wall thicknesses, design pressures, maximum operating pressures (“MOP”), pipeline patrols and leak surveys, minimum depth requirements, emergency procedures, and other matters intended to ensure adequate protection for the public and to prevent accidents and failures. Additionally, 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 high consequence areas (“HCAs”), where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources, and unusually sensitive ecological areas. Past operation of our pipelines with respect to these NGPSA and HLPSA requirements has not resulted in the incurrence of material costs; however, the possibility of new or amended laws and regulations or reinterpretation of PHMSA enforcement practices or other guidance with respect thereto exists, and future compliance with the NGPSA, HLPSA, and new or amended PHMSA regulations could result in increased costs that could have a material adverse effect on our results of operations or financial position.

For example, in October 2019, PHMSA submitted three major rules to the Federal Register, including rules focused on (i) the safety of gas-transmission pipelines (i.e., the first of the three parts of the Mega Rule), (ii) the safety of hazardous liquid pipelines, and (iii) enhanced emergency-order procedures. The gas-transmission rule requires operators of gas-transmission pipelines constructed before 1970 to determine the material strength of their lines by reconfirming the MOP. In addition, the rule updates reporting and records-retention standards for gas-transmission pipelines. This rule took effect on July 1, 2020. In November 2021, PHMSA released another part of the Mega Rule to expand regulations on U.S. natural-gas gathering lines. This rule requires operators of all onshore gas-gathering lines to report incidents and file annual reports and imposes additional safety requirements for larger diameter (i.e., outer diameters of 8.625 inches or greater), higher operating pressure gas-gathering lines. The remaining gas-transmission issues will be addressed in the last part of the Mega Rule, titled, “Pipeline Safety: Safety of Gas Transmission Pipelines, Repair Criteria, Integrity Management Improvements, Cathodic Protection, Management of Change, and Other Related Amendments.”

The safety of hazardous liquid pipelines rule (submitted by PHMSA in October 2019) extended leak-detection requirements to all non-gathering hazardous liquid pipelines and requires operators to inspect affected pipelines following extreme weather events or natural disasters to address any resulting damage. This rule also took effect on July 1, 2020. Finally, the enhanced emergency-order procedures rule focuses on increased emergency-safety measures. In particular, this rule increases the authority of PHMSA to issue an emergency order that addresses unsafe conditions or hazards that pose an imminent threat to pipeline safety. This rule took effect on December 2, 2019.

New laws or regulations adopted by PHMSA, like those summarized above, may impose more stringent requirements applicable to integrity-management programs and other pipeline-safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays. In addition, while states are largely preempted by federal law from regulating pipeline safety for interstate lines, most are certified by PHMSA to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. Historically, our intrastate pipeline-safety compliance costs have not had a material adverse effect on our operations; however, there can be no assurance that such costs will remain immaterial in the future.

Regulation of pipeline-transportation services may affect certain aspects of our business and the market for our products and services. The operations of our MIGC pipeline and the Ramsey Residue Lines are subject to regulation by FERC under the Natural Gas Act of 1938 (the “NGA”). Under the NGA, FERC has authority to regulate natural-gas companies that provide natural-gas pipeline-transportation services in interstate commerce. Federal regulation extends to such matters as the following:

Interstate natural-gas pipelines regulated by FERC also are required to comply with numerous regulations related to standards of conduct, market transparency, and market manipulation. FERC’s standards of conduct regulate the manner in which interstate natural-gas pipelines may interact with their marketing affiliates (unless FERC has granted a waiver of such standards). FERC’s market oversight and transparency regulations require annual reports of purchases or sales of natural gas meeting certain thresholds and criteria and certain public postings of information on scheduled volumes. FERC’s market manipulation regulations make it unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, to engage in fraudulent conduct. The Commodity Futures Trading Commission (the “CFTC”) also holds authority to monitor certain segments of the physical and futures energy commodities market pursuant to the Commodity Exchange Act. FERC and CFTC have authority to impose civil penalties for violations of these statutes and regulations, potentially in excess of $1.0 million per day per violation. Should we fail to comply with all applicable statutes, rules, regulations, and orders administered by FERC and CFTC, we could be subject to substantial penalties and fines.

Regulation of interstate liquids-pipeline services may affect certain aspects of our business and the market for our products and services. Our GNB NGL pipeline provides interstate service as a FERC-regulated common carrier under the Interstate Commerce Act, the Energy Policy Act of 1992, and related rules and orders. We also own interests in FRP, TEP, Saddlehorn, Panola, Cactus II, and White Cliffs, each of which provides interstate services as a FERC-regulated common carrier under the same statues and regulations. FERC regulation requires that interstate liquid-pipeline rates, including rates for transportation of NGLs and crude oil, be filed with FERC and that these rates be “just and reasonable” and not unduly discriminatory. Rates of interstate NGLs and crude-oil pipelines are currently regulated by FERC primarily through an annual indexing methodology, under which pipelines increase or decrease rates in accordance with an index adjustment specified by FERC. The FERC’s indexing methodology is subject to review and revision every five years, with the most recent five-year review occurring in 2020. On December 17, 2020, FERC established the index level for the five-year period commencing on July 1, 2021, which will end on June 30, 2026, at the Bureau of Labor’s producer-price index for finished goods (“PPI-FG”) plus 0.78%. On January 20, 2022, the FERC granted rehearing of certain aspects of the final rule and revised the index level to PPI-FG minus 0.21%, effective March 1, 2022, through June 30, 2026. FERC ordered pipelines with filed rates that exceed their index ceiling levels

The Interstate Commerce Act permits interested persons to challenge proposed new rates and authorizes FERC to suspend the effectiveness of such rates for up to seven months pending an investigation. If, upon completion of an investigation, FERC finds that the new or changed rate is unlawful, it is authorized to require the pipeline to refund revenues collected in excess of the just and reasonable rate during the term of the investigation. The just-and-reasonable rate used to calculate refunds cannot be lower than the last tariff rate approved as just and reasonable. FERC may also investigate, upon complaint or on its own initiative, a changed rate and may order a carrier to reduce its rates prospectively. Upon an appropriate showing, a shipper may obtain reparations for charges in excess of a just-and-reasonable rate for a period of up to two years prior to the filing of a complaint. FERC’s Revised Policy on Treatment of Income Taxes (“Revised Policy Statement”), that no longer permits MLPs to recover an income tax allowance in cost-of-service rates, applies to our pipelines regulated under the Interstate Commerce Act. The Revised Policy Statement may result in an adverse impact on revenues associated with the cost-of-service rates of our FERC-regulated interstate pipelines.

As discussed above, the CFTC holds authority to monitor certain segments of the physical and futures energy commodities market. The Federal Trade Commission (the “FTC”) has authority to monitor petroleum markets in order to prevent market manipulation. The CFTC and FTC have authority to impose civil penalties for violations of these statutes and regulations, potentially in excess of $1.0 million per day per violation. Should we fail to comply with all applicable statutes, rules, regulations, and orders administered by the CFTC and FTC, we could be subject to substantial penalties and fines.

Regulation of gas-gathering pipeline services may affect certain aspects of our business and the market for our products and services. Natural-gas gathering facilities are exempt from the jurisdiction of FERC. We believe that our gas-gathering pipelines meet the traditional tests that FERC has used to determine that a pipeline is not subject to FERC jurisdiction, although FERC has not made any determinations with respect to the jurisdictional status of any of our gas pipelines other than MIGC and the Ramsey Residue Lines. However, the distinction between FERC-regulated gas-transmission services and federally unregulated gathering services has been the subject of substantial litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts, or Congress. State regulation of gathering facilities generally includes various safety, environmental, and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. FERC makes jurisdictional determinations on a case-by-case basis. Our natural-gas gathering operations could be adversely affected should they be subject to more stringent application of state or federal regulation of rates and services. Our natural-gas gathering operations also may be or become subject to additional safety and operational regulations relating to the design, installation, testing, construction, operation, replacement, and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Our natural-gas gathering operations are subject to ratable-take and common-purchaser statutes in most of the states in which we operate. These statutes generally require our gathering pipelines to take natural gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas. The states in which we operate have adopted a complaint-based regulation of natural-gas gathering activities, which allows natural-gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. We cannot predict whether such a complaint will be filed against us in the future. Failure to comply with state regulations can result in the imposition of administrative, civil, and criminal remedies. To date, there has been no adverse effect to our systems resulting from these regulations.

FERC’s anti-manipulation rules apply to non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases, or transportation subject to FERC jurisdiction. The anti-manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but only to the extent

Regulation of intrastate pipeline services may affect certain aspects of our business and the market for our products and services. Intrastate natural-gas and liquids transportation is subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural-gas transportation and the degree of regulatory oversight and scrutiny given to intrastate pipeline rates and services varies from state to state. Regulations within a particular state generally will affect all intrastate pipeline operators within the state on a comparable basis; thus, we believe that the regulation of intrastate transportation in any state in which we operate will not disproportionately affect our operations.

We own an interest in Red Bluff Express, which offers natural-gas transportation services under Section 311 of the Natural Gas Policy Act of 1978. Such pipelines are required to meet certain quarterly reporting requirements, providing detailed transaction information that could be made public. Such pipelines also will be subject to periodic rate review by FERC. In addition, FERC’s anti-manipulation, market-oversight, and market-transparency regulations may extend to intrastate natural-gas pipelines, although they may otherwise be non-jurisdictional, and FERC’s civil penalty authority, described above, would apply to violations of these rules.

ENVIRONMENTAL MATTERS AND OCCUPATIONAL HEALTH AND SAFETY REGULATIONS

Our business operations are subject to numerous federal, regional, state, tribal, and local environmental and occupational health and safety laws and regulations. The more significant of these existing environmental laws and regulations include the following legal standards that exist currently in the United States, as amended from time to time:

Additionally, regional, state, tribal, and local jurisdictions exist in the United States where we operate that also have, or are developing or considering developing, similar environmental laws and regulations governing many of these same types of activities. While the legal requirements imposed under state law may be similar in form to federal laws and regulations, in some cases, the actual implementation of these requirements may impose additional, or more stringent, conditions or controls that can significantly alter or delay the permitting, development, or expansion of a project or substantially increase the cost of doing business. These federal and state environmental laws and regulations, including new or amended legal requirements that may arise in the future to address potential environmental concerns such as air and water impacts and oil and natural-gas development in close proximity to specific occupied structures and/or certain environmentally sensitive or recreational areas, are expected to continue to have a considerable impact on our operations.

In connection with our operations, we have acquired certain properties supportive of oil and natural-gas activities from third parties whose actions with respect to the management and disposal or release of hydrocarbons, hazardous substances, or wastes were not under our control. Under environmental laws and regulations, we could incur strict joint and several liability for remediating hydrocarbons, hazardous substances, or wastes disposed of or released by prior owners or operators. We also could incur costs related to the clean-up of third-party sites to which we sent regulated substances for disposal or recycling, and for damages to natural resources or other claims related to releases of regulated substances at or from such third-party sites.

We have incurred and will continue to incur operating and capital expenditures, some of which may be material, to comply with environmental and occupational health and safety laws and regulations. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations; however, there can be no assurance that such costs will not have a material adverse effect on our business, financial condition, results of operations, or cash flows in the future, or that new or more stringently applied existing laws and regulations will not materially increase our costs of doing business. Although we are not fully insured against all environmental risks, and our insurance does not cover any penalties or fines that may be issued by a governmental authority, we maintain insurance coverage that we believe sufficient based on our assessment of insurable risks and consistent with insurance coverage held by other similarly situated industry participants. Nevertheless, it is possible that other developments, such as stricter and more comprehensive environmental laws and regulations, and claims for damages to property or persons or imposition of penalties resulting from our operations, could have a material adverse effect on our results of operations.

The following are examples of proposed and/or final regulations or other regulatory initiatives that could have a potentially material impact on us:

We also dispose of produced water generated from oil and natural-gas production operations. The legal standards related to the disposal of produced water into non-producing geologic formations by means of underground injection wells are subject to change based on concerns of the public or governmental authorities, including concerns relating to seismic events near injection wells used for the disposal of produced water. 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 near produced-water disposal wells is the introduction of class action lawsuits, which allege 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 to dispose of produced water, which could have a material adverse effect on our results of operations, capital expenditures and operating costs, and financial condition.

TITLE TO PROPERTIES AND RIGHTS-OF-WAY

Our real property is classified into two categories: (i) parcels that we own in fee title and (ii) parcels in which our interest derives from leases, easements, rights-of-way, permits, or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our plants and other major facilities are located are owned by us in fee title, and we believe that we have satisfactory title to these lands. The remainder of the land on which our plant sites and major facilities are located is held by us pursuant to surface leases between us, as lessee, and the fee owner of the lands, as lessor. We or our affiliates have leased or owned these lands for many years without any material challenge known to us relating to the title to the land upon which the assets are located, and we believe that we have satisfactory leasehold estates or fee ownership of such lands. We have no knowledge of any challenge to the underlying fee title of any material lease, easement, right-of-way, permit, or license held by us or to our title to any material lease, easement, right-of-way, permit, or lease, and we believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits, and licenses.

Some of the leases, easements, rights-of-way, permits, and licenses transferred to us by Occidental required the consent of the grantor of such rights, which in certain instances was a governmental entity. We believe we have obtained sufficient third-party consents, permits, and authorizations for the transfer of the assets necessary to enable us to operate our business in all material respects. With respect to any remaining consents, permits, or authorizations that have not been obtained, we have determined these will not have a material adverse effect on the operation of our business should we fail to obtain such consents, permits, or authorization in a reasonable time frame.

HUMAN CAPITAL RESOURCES

The officers of our general partner manage our operations and activities under the direction and supervision of the Board. As of December 31, 2021, WES employed 1,127 persons, all of whom reside in the United States. None of these employees are covered by collective bargaining agreements, and WES considers its employee relations to be good.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

We have made in this Form 10-K, and may make in other public filings, press releases, and statements by management, forward-looking statements concerning our operations, economic performance, and financial condition. These forward-looking statements include statements preceded by, followed by, or that otherwise include the words “believes,” “expects,” “anticipates,” “intends,” “estimates,” “projects,” “target,” “goal,” “plans,” “objective,” “should,” or similar expressions or variations on such expressions. These statements discuss future expectations, contain projections of results of operations or financial condition, or include other “forward-looking” information.

Although we and our general partner believe that the expectations reflected in our forward-looking statements are reasonable, neither we nor our general partner can provide any assurance that such expectations will prove correct. These forward-looking statements involve risks and uncertainties. Important factors that could cause actual results to differ materially from expectations include, but are not limited to, the following:

Risk factors and other factors noted throughout this Form 10-K could cause actual results to differ materially from those contained in any forward-looking statement. Except as required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.

Common units are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. We urge you to carefully consider the following risk factors together with all of the other information included in this Form 10-K in evaluating an investment in our common units.

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

RISKS INHERENT IN OUR BUSINESS

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, 2021, 57% of Total revenues and other, 36% of our throughput for natural-gas assets (excluding equity-investment throughput), 89% 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. The loss of a significant portion of production volumes supplied by Occidental would result in a material decline in our revenues and our cash available for distribution. In addition, Occidental may determine that drilling activity in areas other than our areas of operation is strategically more attractive. 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.

We are dependent on Occidental as our largest customer and the owner of our general partner, and we expect to derive significant revenue from Occidental for the foreseeable future. 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, 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, nor can we estimate the impact such conditions would have on Occidental’s ability to perform under our gathering and transportation agreements with Occidental. Accordingly, any material non-payment or non-performance by Occidental could reduce our ability to make distributions to our unitholders.

Any material limitations to our ability to access capital as a result of adverse changes at Occidental 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, material adverse changes at Occidental could adversely impact our unit price, 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 Occidental’s reports filed under the Securities and Exchange Act of 1934, as amended, with the SEC (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 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

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 February 15, 2022, WES Operating’s long-term debt was rated “BBB-” 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. Because of these downgrades, financing costs under the RCF increased. Additionally, WES Operating currently has $3.1 billion of outstanding senior notes that provide for changes to the coupon rates following changes to WES Operating’s credit rating.

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. We may be required to post collateral in the form of letters of credit or cash as financial assurance of our performance under certain contractual arrangements, such as pipeline transportation contracts and NGLs and gas-sales contracts. At December 31, 2021, there were $5.1 million in letters of credit or cash-provided assurance of our performance under contractual arrangements with credit-risk-related contingent features.

Sustained low natural-gas, NGLs, or oil prices impact natural-gas and oil exploration and production activity levels and can result in a decline in the production of hydrocarbons over the medium to long term, resulting in reduced throughput on our systems. Such declines also potentially affect the ability of our vendors, suppliers, and customers to continue operations. As a result, sustained lower natural-gas and crude-oil prices could have a material adverse effect on our business, results of operations, financial condition, and our ability to pay cash distributions to our unitholders.

In general terms, the prices of natural gas, oil, condensate, NGLs, and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty, and a variety of additional factors that are beyond our control. For example, market prices for natural gas have declined substantially from the highs achieved in 2008 and have generally remained depressed for several years. More recently, the COVID-19 pandemic and resulting mitigation measures have had an adverse impact on global economic conditions, and have contributed to significant volatility in demand for oil, NGLs, and natural gas, resulting in extended periods of lower commodity prices that negatively impacted our and our customers’ financial outlooks and activity levels.

The volumes that support our business are dependent on, among other things, the level of production from natural-gas and oil wells connected to our gathering systems and processing and treating facilities. This production will naturally decline over time. As a result, our cash flows associated with production from these wells also will decline over time. To maintain or increase throughput levels on our systems, we must obtain new sources of oil and natural-gas throughput. 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 and other third-party producers have 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. Sustained

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 and other third-party producers 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.

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. Similarly, we may be impacted by workforce attrition to the extent our employees are resistant to any vaccine or testing mandates that may be imposed upon us. 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.

Although inflation in the United States has been relatively low in recent years, the U.S. economy could experience a significant inflationary effect from, among other things, supply chain disruptions caused by, or governmental stimulus or fiscal policies adopted in response to, the COVID-19 crisis. While we cannot predict any future trends in the rate of inflation, the global COVID-19 pandemic has brought unprecedented uncertainty to the near-term economic outlook. A significant increase in inflation would raise our costs for labor, materials, and services, and to the extent we are unable to recover higher costs through our commercial agreements, would negatively impact our profitability and cash flows available for distribution to unitholders.

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 2021 distribution of $0.32700 per unit per quarter, or $1.30800 per unit per year, we require per-quarter available cash of $134.7 million, or $538.8 million per year, based on the number of common units outstanding at January 31, 2022. 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.

On some of our systems, we rely on third-party customers for substantially all of our revenues related to those assets. The loss of a portion or all of these customers’ contracted volumes, as a result of competition, creditworthiness, inability to negotiate extensions, replacements of contracts, or otherwise, could reduce our ability to make cash distributions to our unitholders. 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.

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. While we have achieved significant milestones in our separation from Occidental, attention to such organizational activities is continuing and could divert management’s attention from our existing business. Additionally, newly adopted systems, controls, and compliance infrastructure may face post-implementation challenges in the near term.

If any of these risks, or other unanticipated liabilities or costs were to arise, then desired benefits from our efforts to become independent from Occidental may not materialize. Such difficulties may have a material adverse effect on our business, financial condition, results of operations, or cash available for distribution to our unitholders.

While we do not conduct hydraulic fracturing, our oil and natural-gas exploration and production customers do conduct such activities. Hydraulic fracturing is an essential and common practice used by many of our customers to stimulate production of natural gas and oil from dense subsurface rock formations such as shales. 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.

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. 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. Moreover, increased regulation of the hydraulic-fracturing process also could lead to greater opposition to, and litigation over, oil and natural-gas production activities using hydraulic-fracturing techniques. Any one or more of these developments could have a material adverse effect on our business, financial condition, and results of operations.

We dispose of produced water generated from oil and natural-gas production operations. The legal requirements related to the disposal of produced water into a non-producing geologic formation by means of underground injection wells are subject to change based on concerns of the public or governmental authorities, including concerns relating to recent seismic events near injection wells used for the disposal of produced water. 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. 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.

Our business and operations are concentrated in a limited number of producing areas. 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.

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.

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. If our operating results are not sufficient to service indebtedness in the future, we will be forced to take actions such as reducing distributions; reducing or delaying our business activities, acquisitions, investments, or capital expenditures; selling assets; or seeking additional equity capital. We may not be able to execute any of these actions on satisfactory terms or at all.

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.

Management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with GAAP. A material weakness is a deficiency, or a combination of deficiencies, in our internal controls that result in a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. Effective internal control is necessary for us to provide reliable financial reports and deter and detect any material fraud. If we cannot provide reliable financial reports or prevent material fraud, our reputation and operating results will be harmed. Our efforts to develop and maintain our system of internal controls and to remediate material weaknesses in our controls may not be successful, and we may be unable to maintain adequate control over our financial processes and reporting in the future, including future compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective controls, or difficulties encountered in their implementation or other effective improvement of our internal controls, could harm our operating results. Ineffective internal control also could cause investors to lose confidence in our reported financial information.

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 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 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. Disruption of those communications, whether caused by cyber-attacks or otherwise, may disrupt our ability to deliver natural gas and control these assets.

There is no assurance that we will not suffer material losses from future cyber-attacks, and as such threats continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate or remediate any cyber vulnerabilities. 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.

We typically do not obtain independent evaluations of hydrocarbon reserves connected to our systems. Accordingly, we do not have independent estimates of total reserves connected to our systems or the anticipated life of such reserves. 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 gathering, transportation, treating, and processing systems are connected to other pipelines or facilities, the majority of which are owned by third parties. 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, 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.

We believe that our gas-gathering systems meet the traditional tests FERC has used to determine if a pipeline is a gas-gathering pipeline and is, therefore, not subject to FERC jurisdiction. FERC, however, has not made any determinations with respect to the jurisdictional status of any of these gas-gathering systems. The distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of ongoing litigation and, over time, FERC policy concerning which activities it regulates and which activities are excluded from its regulation has changed. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, FERC has regulated the gas-gathering activities of interstate pipeline transmission companies more lightly, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates. As a result of these activities, natural-gas gathering may begin to receive greater regulatory scrutiny at the state and federal levels.

Additionally, while states are largely preempted by federal law from regulating pipeline safety for interstate lines, most are certified by PHMSA to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. Moreover, PHMSA and one or more state regulators, including the Texas Railroad Commission, have expanded the scope of their regulatory inspections in recent years to include certain in-plant equipment and pipelines found within NGLs fractionation facilities and associated storage facilities, to assess compliance with hazardous liquids pipeline safety requirements. To the extent that PHMSA and/or state regulatory agencies are successful in asserting their jurisdiction in this manner, midstream operators of NGLs fractionation facilities and associated storage facilities may be required to make operational changes or modifications at their facilities to meet standards beyond current OSHA and EPA requirements, where such changes or modifications may result in additional capital costs, possible operational delays, and increased costs of operation that, in some instances, may be significant.

Some portions of the pipeline systems that we operate were in service for many decades, prior to our purchase of these systems. Consequently, there may be historical occurrences or latent issues regarding our pipeline systems that our executive management may be unaware of and that may have a material adverse effect on our business and results of operations. The age and condition of our pipeline systems also could result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of our pipeline systems could adversely affect our business and results of operations.

Our operations are subject to stringent and comprehensive federal, tribal, state, and local environmental laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These environmental laws and regulations may impose numerous obligations that are applicable to our operations, including: (i) the acquisition of permits to conduct regulated activities; (ii) restrictions on the types, quantities, and concentrations of materials that can be released into the environment; (iii) limitations on the generation, management, and disposal of wastes; (iv) limitations or prohibitions of construction and operating activities in environmentally sensitive areas such as wetlands, urban areas, wilderness regions, and other protected areas; (v) requiring capital expenditures to limit or prevent releases of materials from our pipelines and facilities; and (vi)

We may incur significant environmental costs and liabilities in connection with our operations due to our handling of natural gas, crude oil, NGLs, and other petroleum products, because of pollutants from our operations emitted into ambient air or discharged or released into surface water or groundwater, and as a result of historical industry operations and waste-disposal practices. For example, an accidental release as a result of our operations could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by owners of the properties through which our gathering or transportation systems pass, neighboring landowners, and other third parties for personal injury, natural-resource and property damages, and fines or penalties for related violations of environmental laws or regulations. Joint and several strict liabilities may be incurred, without regard to fault, under certain of these environmental laws and regulations. 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. 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.

One of the ways we intend to grow our business is through the construction of new midstream assets. The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political, and legal uncertainties that are beyond our control. These uncertainties also could affect downstream assets, which we do not own or control, but which are critical to certain of our growth projects. Delays in the completion of new downstream assets, or the unavailability of existing downstream assets, due to environmental, regulatory, or political considerations, could have an adverse impact on the completion or utilization of our growth projects. 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. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. In addition, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize.

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. The energy industry as a whole has received the attention of such activists, as have companies with our partnership governance model.

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. 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.

Our inability, or limited ability, to control the operations and/or management of joint-venture legal entities in which we have a partial ownership interest may result in our receiving or retaining less cash than we expect. We also may be unable, or limited in our ability, to cause any such entity to effect significant transactions such as large expenditures or contractual commitments, the construction or acquisition of assets, or the borrowing of money.

In addition, for the equity investments in which we have a minority ownership interest, we are unable to control ongoing operational decisions, including the incurrence of capital expenditures or additional indebtedness that we may be required to fund. Further, the other owners of our equity investments may establish reserves for working capital, capital projects, environmental matters, and legal proceedings, that would similarly reduce the amount of cash available for distribution. Any of the above could impact our ability to make cash distributions to our unitholders adversely.

Further, in connection with the acquisition of our membership interest in Chipeta, we became party to the Chipeta LLC agreement. Among other things, the Chipeta LLC agreement provides that to the extent available, Chipeta will distribute available cash, as defined in the Chipeta LLC agreement, to its members quarterly in accordance with those members’ membership interests. Accordingly, we are required to distribute a portion of Chipeta’s cash balances, which are included in the cash balances in our consolidated balance sheets, to the other Chipeta member.

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. 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.

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 (i) damage to our assets and surrounding properties and disruption of our operations as a result of weather, natural disasters, or acts of terrorism; (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. These risks also may result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks that may occur in our business. In addition, although we are insured for environmental pollution resulting from environmental accidents that occur on a sudden and accidental basis, we may not be insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to certain indemnification rights, for potential environmental liabilities.

RISKS INHERENT IN AN INVESTMENT IN US

Our general partner has included provisions in its and our contractual arrangements that limit its liability so that the counterparties to such arrangements have recourse only against our assets and not against our general partner or its assets. Our general partner may, therefore, cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner’s duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

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. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. 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. By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the above-described provisions.

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:

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, Occidental, the owner of our general partner, may transfer its ownership interest in our general partner to a third party, also without unitholder consent. Our new general partner or the new owner of our general partner would then be in a position to replace the Board and officers of our general partner and to control the decisions taken by the Board and officers.

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

We had 402,993,919 common units outstanding as of December 31, 2021. Occidental currently holds 200,281,578 common units, representing 49.7% of our outstanding common units. Occidental’s shelf registration statement currently allows for the offer and sale of approximately 30.3 million common units, or 7.5% of our common units as of December 31, 2021, 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.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the impermissible distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. 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.

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, 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

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. Notwithstanding our status as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as us to be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement and is not treated as an investment company. Based on our current operations, we believe that we satisfy the qualifying income requirement and are not treated as an investment company. Failing to meet the qualifying income requirement, being treated as an investment company, a change in our business activities, or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the applicable corporate tax rate and likely would pay state income tax at varying rates. Distributions to our unitholders generally would be taxed as corporate distributions, and no income, gains, losses, deductions, or credits would flow through to our unitholders. If we are subject to corporate taxation, our cash available for distribution to our unitholders would be reduced substantially. Likewise, our treatment as a corporation would result in a material reduction in the anticipated cash flows and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income or franchise taxes or other forms of taxation. For example, we are required to pay Texas margin tax on our gross income apportioned to Texas. Imposition of similar taxes on us in other jurisdictions in which we operate, or to which we may expand our operations, could reduce the cash available for distribution to our unitholders substantially.

The current U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative, or judicial interpretation at any time. From time to time, members of Congress have proposed and considered substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including elimination of partnership tax treatment for publicly traded partnerships. 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 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.

We have not requested a ruling from the IRS with respect to the pricing of our related-party agreements with Occidental or our treatment as a partnership for U.S. federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take, and a court may not agree with some or all of those positions. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. 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.

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 adjustment directly from us. To the extent possible under applicable rules, our general partner may pay such amounts directly to the IRS or, if we are eligible, elect to issue a revised Schedule K-1 to each unitholder with respect to an audited and adjusted return. No assurances can be made 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 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 any U.S. 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

If a unitholder sells common units, the unitholder will recognize gain or loss equal to the difference between the amount realized and that unitholder’s tax basis in those common units. 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.

Investment in common units by tax-exempt entities, such as employee benefit plans, and individual retirement accounts (or “IRAs”) 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. Tax-exempt entities should consult a tax advisor before investing in our units.

Non-U.S. unitholders are subject to U.S. federal income tax on income effectively connected with a U.S. trade or business (“effectively connected income”). A unitholder’s share of our income, gain, loss and deduction, and any gain from the sale or disposition of our units will generally be considered to be effectively connected income and subject to U.S. federal income tax. Additionally, distributions to non-U.S. unitholders will be reduced by withholding taxes at the highest applicable effective tax rate.

Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person. Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor. Treasury regulations and recent Treasury guidance further provide that withholding on a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs on or prior to December 31, 2022, and after that date, if effected through a broker, the obligation to withhold is imposed on the transferor’s broker. Non-U.S. 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 (the “Allocation 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. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. 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.

In determining items of income, gain, loss, and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets. Although we may, from time to time, consult with professional appraisers

A successful IRS challenge to these methods or allocations 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.

In addition to U.S. federal income taxes, our unitholders are subject to other taxes, including foreign, state, and local taxes; unincorporated business taxes; and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we conduct business or 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 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.

None.

On August 12, 2019, Sanchez Energy Corporation and certain of its affiliated companies (collectively, “Sanchez”) filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas. While Sanchez holds a working interest in the acreage dedicated to our Springfield system, Sanchez also was the upstream operator for substantially all of the natural gas, crude oil, and NGLs that the Springfield system gathers and that WES processes in the Eagle Ford Shale Play. On April 29, 2020, we received notice that Sanchez filed a motion 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. We objected to Sanchez’s rejection and instituted an adversary proceeding regarding such rejection. On May 15, 2020, Gavilan Resources LLC (“Gavilan”), an entity that owns a 25% working interest in the acreage where the Springfield gathering system and Brasada processing plant are located, also filed for Chapter 11 bankruptcy protection. As a part of this bankruptcy, Mesquite Energy, Inc. (the successor to Sanchez) (“Mesquite”) purchased Gavilan’s assets at auction. Gavilan did not assume and assign its agreements with Springfield as part of its asset sale. The parties reached a comprehensive legal and commercial settlement of these disputes in December 2021.

Not applicable.

PART II

MARKET INFORMATION

Our common units are listed on the NYSE under the symbol “WES.” As of February 17, 2022, there were 21 unitholders of record of our common units. This number does not include unitholders whose units are held in trust by other entities. The actual number of unitholders is greater than the number of holders of record. We also have 9,060,641 general partner units issued and outstanding; there is no established public trading market for any such general partner units. All general partner units are held by our general partner.

OTHER SECURITIES MATTERS

SELECTED INFORMATION FROM OUR PARTNERSHIP AGREEMENT

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

EXECUTIVE SUMMARY

The following table provides additional information on throughput for the periods presented below:

OUR OPERATIONS

Our results primarily are driven by the volumes of natural gas, NGLs, crude oil, and produced water we service through our systems. In our operations, we contract with customers to provide midstream services focused on natural gas, NGLs, crude oil, and produced water. We gather natural gas from individual wells or production facilities located near our gathering systems and the natural gas may be compressed and delivered to a processing plant, treating facility, or downstream pipeline, and ultimately to end users. We treat and process a significant portion of the natural gas that we gather so that it will satisfy required specifications for pipeline transportation. We gather crude oil from individual wells or production facilities located near our gathering systems, and in some cases, treat or stabilize the crude oil to satisfy required specifications for pipeline transportation. We also gather and dispose of produced water.

We operate in Texas, New Mexico, Colorado, Utah, Wyoming, and North-central Pennsylvania, with a substantial portion of our business concentrated in West Texas and the Rocky Mountains. For example, for the year ended December 31, 2021, our West Texas and DJ Basin assets provided (i) 47% and 35%, respectively, of Total revenues and other, (ii) 33% and 36%, respectively, each of our throughput for natural-gas assets (excluding equity-investment throughput), (iii) 60% and 29%, respectively, of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and (iv) all of our throughput for produced-water assets.

For the year ended December 31, 2021, 57% of Total revenues and other, 36% of our throughput for natural-gas assets (excluding equity-investment throughput), 89% 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. While Occidental is our contracting counterparty, these arrangements with Occidental include not just Occidental-produced volumes, but also, in some instances, the volumes of other working-interest owners of Occidental who rely on our facilities and infrastructure to bring their volumes to market. In addition, Occidental provides dedications, minimum-volume commitments with associated deficiency payment, and/or cost-of-service commitments under certain of our contracts.

For the year ended December 31, 2021, 93% of our wellhead natural-gas volume (excluding equity investments) and 100% of our crude-oil 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. This type of contract provides us with a relatively stable revenue stream that is not subject to direct commodity-price risk, except to the extent that (i) we retain and sell drip condensate that is recovered during the gathering of natural gas from the wellhead or production facilities or (ii) actual recoveries differ from contractual recoveries under a limited number of processing agreements.

HOW WE EVALUATE OUR OPERATIONS

ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS

RESULTS OF OPERATIONS

The following tables and discussion present a summary of our results of operations: