What changed in Western Midstream Partners, LP's 2023 10-K compared to 2022?

Across the narrative sections we track, Western Midstream Partners, LP (WES) added 222 paragraphs, removed 300, and edited 180 between the 2022 and 2023 10-K filings. The biggest movers are Item 7A. Quantitative and Qualitative Disclosures About Market Risk (+132/−207), Item 1A. Risk Factors (+63/−65), Item 7. Management's Discussion & Analysis (+17/−12).

Did Western Midstream Partners, LP add new Risk Factors in the 2023 10-K?

Yes — Item 1A Risk Factors shows 63 new/edited paragraphs and 65 removed paragraphs versus the 2022 10-K.

What changed in Western Midstream Partners, LP's MD&A (Item 7) in 2023?

Item 7 Management's Discussion & Analysis shows 17 new/edited paragraphs and 12 removed paragraphs year-over-year. Read the side-by-side diff to see exactly which revenue, margin, and outlook commentary was rewritten.

Did Western Midstream Partners, LP's Legal Proceedings (Item 3) change in 2023?

Item 3 shows 5 added/edited paragraphs and 11 removed paragraphs — usually indicating new litigation disclosed or settled cases removed.

Where does this WES 10-K diff come from?

The source filings are Western Midstream Partners, LP's official 2022 and 2023 Form 10-K annual reports from SEC EDGAR. 10q10k.net parses each filing, aligns paragraphs by section (Item 1, 1A, 1C, 2, 3, 7, 7A), and highlights every added, removed and edited sentence side-by-side.

What changed in Western Midstream Partners, LP's 10-K — 2022 vs 2023

Paragraph-level year-over-year comparison of Western Midstream Partners, LP's 2022 and 2023 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2023 report.

+222 added−300 removedSource: 10-K (2024-02-21) vs 10-K (2023-02-22)

Top changes in Western Midstream Partners, LP's 2023 10-K

222 paragraphs added · 300 removed · 180 edited across 5 sections

Item 7A. Quantitative and Qualitative Disclosures About Market Risk+132 / −207 · 109 edited
Item 1A. Risk Factors+63 / −65 · 55 edited
Item 7. Management's Discussion & Analysis+17 / −12 · 9 edited
Item 3. Legal Proceedings+5 / −11 · 2 edited
Item 5. Market for Registrant's Common Equity+5 / −5 · 5 edited

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

55 edited+8 added−10 removed196 unchanged

2022 filing

2023 filing

Biggest changeFurther, 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. 48 Table of Contents Implementation of Colorado Senate Bill 19-181 may increase costs and limit oil and natural-gas exploration and production operations in the state, which could have a material adverse effect on our customers in Colorado and significantly reduce demand for our services in the state.

Biggest changeImplementation of Colorado Senate Bill 19-181 may increase costs and limit oil and natural-gas exploration and production operations in the state, which could have a material adverse effect on our customers in Colorado and significantly reduce demand for our services in the state. 41 Table of Contents On April 16, 2019, Senate Bill 19-181 was signed into law in Colorado.

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.

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.

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

Important factors that could cause actual results to differ materially from expectations include, but are not limited to, the following: • our ability to pay distributions to our unitholders; • our assumptions about the energy market; • future throughput (including Occidental production) that is gathered or processed by, or transported through our assets; • our operating results; • competitive conditions; • technology; • the availability of capital resources to fund acquisitions, capital expenditures, and other contractual obligations, and our ability to access financing through the debt or equity capital markets; • the supply of, demand for, and price of, oil, natural gas, NGLs, and related products or services; • commodity-price risks inherent in percent-of-proceeds, percent-of-product, and keep-whole contracts; • weather and natural disasters; • inflation; • the availability of goods and services; • general economic conditions, internationally, domestically, or in the jurisdictions in which we are doing business; • federal, state, and local laws and state-approved voter ballot initiatives, including those laws or ballot initiatives that limit producers’ hydraulic-fracturing activities or other oil and natural-gas development or operations; • environmental liabilities; • legislative or regulatory changes, including changes affecting our status as a partnership for federal income tax purposes; • changes in the financial or operational condition of Occidental; 44 Table of Contents • the creditworthiness of Occidental or our other counterparties, including financial institutions, operating partners, and other parties; • changes in Occidental’s capital program, corporate strategy, or other desired areas of focus; • our commitments to capital projects; • our ability to access liquidity under the RCF; • our ability to repay debt; • the resolution of litigation or other disputes; • conflicts of interest among us, our general partner and its related parties, including Occidental, with respect to, among other things, the allocation of capital and operational and administrative costs, and our future business opportunities; • our ability to maintain and/or obtain rights to operate our assets on land owned by third parties; • our ability to acquire assets on acceptable terms from third parties; • non-payment or non-performance of significant customers, including under gathering, processing, transportation, and disposal agreements; • the timing, amount, and terms of future issuances of equity and debt securities; • the outcome of pending and future regulatory, legislative, or other proceedings or investigations, and continued or additional disruptions in operations that may occur as we and our customers comply with any regulatory orders or other state or local changes in laws or regulations; • cyber attacks or security breaches; and • other factors discussed below and elsewhere in this Item 1A, under the caption Critical Accounting Estimates included under Part II, Item 7 of this Form 10-K, and in our other public filings and press releases.

Important factors that could cause actual results to differ materially from expectations include, but are not limited to, the following: • our ability to pay distributions to our unitholders and the amount of such distributions; • our assumptions about the energy market; • future throughput (including Occidental production) that is gathered or processed by, or transported through our assets; • our operating results; • competitive conditions; • technology; • the availability of capital resources to fund acquisitions, capital expenditures, and other contractual obligations, and our ability to access financing through the debt or equity capital markets; • the supply of, demand for, and price of oil, natural gas, NGLs, and related products or services; • commodity-price risks inherent in percent-of-proceeds, percent-of-product, keep-whole, and fixed-recovery processing contracts; • weather and natural disasters; • inflation; • the availability of goods and services; • general economic conditions, internationally, domestically, or in the jurisdictions in which we are doing business; • federal, state, and local laws and state-approved voter ballot initiatives, including those laws or ballot initiatives that limit producers’ hydraulic-fracturing activities or other oil and natural-gas development or operations; • environmental liabilities; • legislative or regulatory changes, including changes affecting our status as a partnership for federal income tax purposes; • changes in the financial or operational condition of Occidental; 37 Table of Contents • the creditworthiness of Occidental or our other counterparties, including financial institutions, operating partners, and other parties; • changes in Occidental’s capital program, corporate strategy, or other desired areas of focus; • our commitments to capital projects; • our ability to access liquidity under the RCF and commercial paper program; • our ability to repay debt; • the resolution of litigation or other disputes; • conflicts of interest among us and our general partner and its related parties, including Occidental, with respect to, among other things, the allocation of capital and operational and administrative costs, and our future business opportunities; • our ability to maintain and/or obtain rights to operate our assets on land owned by third parties; • our ability to acquire assets on acceptable terms from third parties; • non-payment or non-performance of significant customers, including under gathering, processing, transportation, and disposal agreements; • the timing, amount, and terms of future issuances of equity and debt securities; • the outcome of pending and future regulatory, legislative, or other proceedings or investigations, and continued or additional disruptions in operations that may occur as we and our customers comply with any regulatory orders or other state or local changes in laws or regulations; • cyber attacks or security breaches; and • other factors discussed below and elsewhere in this Item 1A, under the caption Critical Accounting Estimates included under Part II, Item 7 of this Form 10-K, and in our other public filings and press releases.

In such a case, the common units’ trading price could decline, and you could lose part or all of your investment. 45 Table of Contents RISKS INHERENT IN OUR BUSINESS We are dependent 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.

In such a case, the common units’ trading price could decline, and you could lose part or all of your investment. 38 Table of Contents RISKS INHERENT IN OUR BUSINESS We are dependent 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.

Effective January 15, 2021, COGCC began implementing the new Senate Bill 19-181 rules that include a unified permitting process, increased setbacks from schools, limitations on venting and flaring, enhanced wildlife protections, and, in conjunction with the Colorado Department of Public Health and Environment, requirements to evaluate the cumulative impacts of oil and gas operations.

Effective January 15, 2021, the ECMC began implementing the new Senate Bill 19-181 rules that include a unified permitting process, increased setbacks from schools, limitations on venting and flaring, enhanced wildlife protections, and, in conjunction with the Colorado Department of Public Health and Environment, requirements to evaluate the cumulative impacts of oil and gas operations.

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 59 Table of Contents 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.

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 52 Table of Contents jurisdictions.

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 47 Table of Contents 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.

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 40 Table of Contents 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.

At December 31, 2022, 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 and volatility of such prices could adversely affect our business.

At December 31, 2023, 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 and volatility of such prices could adversely affect our business.

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 53 Table of Contents environmental laws or regulations.

For additional information regarding PHMSA regulations, read Regulation of Operations—Natural-Gas Gathering Pipeline Regulation under Items 1 and 2 of this Form 10-K. 52 Table of Contents 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.

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

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.

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, 42 Table of Contents financial condition, and ability to make cash distributions to our unitholders than if our operations were more diversified.

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.

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 45 Table of Contents equipment and pipelines found within NGLs fractionation facilities and associated storage facilities, to assess compliance with hazardous liquids pipeline safety requirements.

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.

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 46 Table of Contents operators with whom we have a business relationship, which could have a material adverse effect on our results of operations and cash flows.

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.

Any modification to the U.S. federal income tax laws and interpretations thereof may or may not 50 Table of Contents 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.

In addition, we may be unable to complete maintenance or repairs due to the unavailability of necessary materials as a result of supply chain disruptions (including those caused by COVID-19 lockdowns or geopolitical events, such as the Russian invasion of Ukraine), which may result in the suspension of operations of the impacted assets until such activities can be completed.

In addition, we may be unable to complete maintenance or repairs due to the unavailability of necessary materials as a result of supply chain disruptions (including those caused by geopolitical events, such as the Russian invasion of Ukraine), which may result in the suspension of operations of the impacted assets until such activities can be completed.

Our future prospects depend on Occidental’s growth strategy, midstream operational philosophy, and drilling program, including the level of drilling and completion activity by Occidental on acreage dedicated to us. Additional conflicts also may arise in the future associated with future business opportunities that are pursued by Occidental and 46 Table of Contents us.

Our future prospects depend, in part, on Occidental’s growth strategy, midstream operational philosophy, and drilling program, including the level of drilling and completion activity by Occidental on acreage dedicated to us. Additional conflicts also may arise in the future associated with future business opportunities that are pursued by 39 Table of Contents Occidental and us.

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.

Additionally, destructive forms of protests by activists and other disruptions, including acts of sabotage or eco- 43 Table of Contents 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.

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. 54 Table of Contents We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.

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 are located, which could result in disruptions to our operations.

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.

Any future downgrades in WES Operating’s credit ratings could adversely affect WES Operating’s ability to issue debt, including commercial paper, 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.

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.

Delaware 49 Table of Contents 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.

From time to 57 Table of Contents 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.

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.

Adverse developments in our geographic areas of operation could disproportionately impact our business, results of operations, financial condition, and ability to make cash distributions to our unitholders. 49 Table of Contents Our business and operations are concentrated in a limited number of producing areas.

Adverse developments in our geographic areas of operation could disproportionately impact our business, results of operations, financial condition, and ability to make cash distributions to our unitholders. Our business and operations are concentrated in a limited number of producing areas.

For example, WES Operating currently has $3.1 billion of outstanding senior notes that provide for changes to the coupon rates following changes in WES Operating’s credit ratings. Future credit-rating downgrades also could trigger obligations to provide financial assurance of our performance under certain contractual arrangements.

For example, WES Operating currently has $2.8 billion of outstanding senior notes that provide for changes to the coupon rates following changes in WES Operating’s credit ratings. Future credit-rating downgrades also could trigger obligations to provide financial assurance of our performance under certain contractual arrangements.

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.

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 48 Table of Contents partner, or otherwise free of fiduciary duties to us and our unitholders.

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.

Consequently, there may be historical occurrences or latent issues regarding our pipeline systems that we may be unaware of and that may have a material adverse effect on our business and results of operations.

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

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, in which case our cash available for distribution to our unitholders might be substantially reduced.

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

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

Occidental’s shelf registration statement currently allows for the offer and sale of approximately 30.3 million common units, or 7.9% of our common units as of December 31, 2022, from time to time.

Occidental’s shelf registration statement currently allows for the offer and sale of approximately 30.3 million common units, or 8% of our common units as of December 31, 2023, from time to time.

Additional Senate Bill 19-181 rulemakings may be expected. Operators are adjusting to the new requirements, but are experiencing delayed drilling permit issuance and potentially will face increased operating costs, which could have a material adverse effect on our customers in Colorado, which in turn could reduce statewide demand for our midstream services significantly.

Operators are adjusting to the new requirements, but are experiencing delayed drilling permit issuance and potentially will face increased operating costs, which could have a material adverse effect on our customers in Colorado, which in turn could reduce statewide demand for our midstream services significantly.

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.

The mission of the Colorado Oil and Gas Conservation Commission (“COGCC”) has changed from fostering energy development in the state to regulating the industry in a manner that is protective of public health and safety and the environment.

The mission of the Colorado Oil and Gas Conservation Commission, now renamed as the Energy & Carbon Management Commission (“ECMC”), has changed from fostering energy development in the state to regulating the industry in a manner that is protective of public health and safety and the environment.

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.

For the year ended December 31, 2022, 55% of Total revenues and other, 35% 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 80% of our throughput for produced-water assets were attributable to production owned or controlled by Occidental.

For the year ended December 31, 2023, 59% of Total revenues and other, 34% of our throughput for natural-gas assets (excluding equity-investment throughput), 86% of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and 78% of our throughput for produced-water assets were attributable to production owned or controlled by Occidental.

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.

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.

To pay the announced fourth-quarter 2022 distribution of $0.50000 per unit per quarter, or $2.00000 per unit per year, we require per-quarter available cash of $196.6 million, or $786.4 million per year, based on the number of common units outstanding at February 1, 2023.

To pay the announced fourth-quarter 2023 distribution of $0.57500 per unit per quarter, or $2.30000 per unit per year, we require per-quarter available cash of $223.4 million, or $893.6 million per year, based on the number of common units outstanding at February 1, 2024.

We are exposed to the credit risk of third-party customers, and any material non-payment or non-performance by these parties, including with respect to our gathering, processing, transportation, and disposal agreements, could reduce our ability to make distributions to our unitholders. On some of our systems, we rely on third-party customers for substantially all of our revenues related to those assets.

We are exposed to the credit risk of third-party customers, and any material non-payment or non-performance by these parties, including with respect to our gathering, processing, transportation, and disposal agreements, could reduce our ability to make distributions to our unitholders. Across our asset portfolio, we rely on third-party customers for a substantial amount of our revenues.

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.

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.

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.

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.

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.

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.

Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning 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”).

Tax-exempt entities should consult a tax advisor before investing in our units. 51 Table of Contents Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning 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”).

Our business could be negatively affected by security threats, including cyber-threats, and other disruptions. 50 Table of Contents 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.

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.

The market price of our common units could be affected adversely by sales of substantial amounts of our common units in the public or private markets, including sales by Occidental or other large holders. We had 384,070,984 common units outstanding as of December 31, 2022. Occidental currently holds 190,281,578 common units, representing 49.5% of our outstanding common units.

The market price of our common units could be affected adversely by sales of substantial amounts of our common units in the public or private markets, including sales by Occidental or other large holders. We had 379,519,983 common units outstanding as of December 31, 2023. Occidental currently holds 185,181,578 common units, representing 48.8% of our outstanding common units.

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units and restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty. 55 Table of Contents 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.

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.

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 44 Table of Contents its regulation has changed.

In addition, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. We are subject to increased scrutiny from institutional investors with respect to our governance structure and the social cost of our industry, which may adversely impact our ability to raise capital from such investors.

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

Further increases in inflation would raise our costs for labor, materials, fuel, 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.

While we cannot predict any future trends in the rate of inflation, sustained or further increases in inflation would negatively impact our profitability and cash flows available for distribution to unitholders to the extent we are unable to recover such higher costs through our commercial agreements.

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.

RISKS INHERENT IN AN INVESTMENT IN US Our general partner’s liability regarding our obligations is limited. 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.

A change in the jurisdictional characterization of some of our assets by federal, state, or local regulatory agencies or a change in policy by those agencies could result in increased regulation of our assets, which could cause our revenues to decline and operating expenses to increase. 51 Table of Contents 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.

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

Because we are a related party of Occidental, the assets we previously acquired from Anadarko were recorded at Anadarko’s carrying value prior to the transaction. See the discussion of material impairments in Note 9—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

For example, virtually all of our income allocated to organizations 58 Table of Contents 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.

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.

On April 16, 2019, Senate Bill 19-181 was signed into law in Colorado. This legislation reforms oversight of oil and natural-gas exploration and production activities in the state.

This legislation reforms oversight of oil and natural-gas exploration and production activities in the state.

Our profitability may be negatively impacted by inflation in the cost of labor, materials, and services.

Our profitability may be negatively impacted by inflation in the cost of labor, materials, and services. Although inflation in the United States has declined during 2023, the prices of key inputs to the midstream industry have continued to be significantly impacted by inflation relative to historical levels.

More specifically, the bottlenecks and disruptions from the lingering effects of the COVID-19 crisis have caused difficulties within the U.S. and global supply chains, creating logistical delays along with labor shortages. Continued inflation has raised our costs for labor, materials, fuel, and services, thereby increasing our operating costs and capital expenditures, and these costs may continue to increase.

This continued inflation has raised our costs for steel products, automation components, power supply, labor materials, fuel, chemicals, and services, thereby increasing our operating costs and capital expenditures, and these costs may continue to increase.

Removed

Although inflation in the United States has been relatively low in recent years, the U.S. economy currently is experiencing significant inflation relative to historical precedent from, among other things, supply-chain disruptions caused by, or governmental stimulus or fiscal policies adopted in response to, the COVID-19 crisis and in connection with the war in Ukraine.

Added

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.

Removed

While we cannot predict any future trends in the rate of inflation, the aforementioned factors have brought significant uncertainty to the near-term economic outlook.

Added

Since July 2019, the ECMC has conducted rulemaking hearings to adopt rules required in the bill, and adopted rules in 2019, 2020 and 2021 to implement the provisions of Senate Bill 19-181. Rules adopted include those related to wellbore integrity, financial assurance, worker certification, and the like.

Removed

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

Added

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.

Removed

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

Added

In addition, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. We may fail to successfully combine our business with the assets and business of Meritage, which could have an adverse impact on our future results. The Meritage acquisition closed on October 13, 2023.

Removed

RISKS INHERENT IN AN INVESTMENT IN US A reduction in Occidental’s ownership interest in us may reduce its incentive to support our operations.

Added

The integration of these acquired assets involve potential risks, including the failure to realize expected profitability, growth, or accretion; environmental or regulatory compliance matters or liabilities; diversion of management’s attention from our existing business; and the incurrence of unanticipated liabilities and costs for which indemnification is unavailable or inadequate.

Removed

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

Added

If any of the risks described above or other anticipated or unanticipated liabilities were to materialize, it could have an adverse effect on our business, financial condition, and results of operations.

Removed

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

Added

Any of the above could adversely impact our ability to make cash distributions to our unitholders. 47 Table of Contents Further, in connection with the acquisition of our membership interest in Chipeta, we became party to the Chipeta LLC agreement.

Removed

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

Added

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.

Removed

Unitholders may have liability to repay distributions that were wrongfully distributed to them. 56 Table of Contents Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them.

Removed

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

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

2 edited+3 added−9 removed2 unchanged

2022 filing

2023 filing

Biggest changeOn October 29, 2020, WGR Operating, LP (“WGR”), on behalf of itself and derivatively on behalf of Mont Belvieu JV, filed suit against Enterprise Products Operating, LLC (“Enterprise”) and Mont Belvieu JV (as a nominal defendant) in the District Court of Harris County, Texas.

Biggest changeItem 3. Legal Proceedings On October 29, 2020, WGR Operating, LP (“WGR”), on behalf of itself and derivatively on behalf of Mont Belvieu JV, filed suit against Enterprise Products Operating, LLC (along with its affiliates, collectively “Enterprise”) and Mont Belvieu JV (as a nominal defendant) in the District Court of Harris County, Texas (the “Mont Belvieu JV Lawsuit”).

Our lawsuit seeks a declaratory judgment regarding proper revenue allocation as set forth in the Operating Agreement between Mont Belvieu JV (of which WGR is a 25% owner) and Enterprise (the “Operating Agreement”) related to fractionation trains at the Mont Belvieu complex in Chambers County, Texas.

In the Mont Belvieu JV Lawsuit, we sought a declaratory judgment regarding proper revenue allocation as set forth in the Operating Agreement between the Mont Belvieu JV (in which WGR was a 25% owner) and Enterprise related to fractionation trains at the Mont Belvieu complex in Chambers County, Texas.

Removed

Item 3. Legal Proceedings On July 1, 2020, the U.S. Department of Justice, on behalf of the U.S.

Added

Separately, on November 22, 2022, WGR filed suit against Enterprise in the District Court of Harris County, Texas (the “Whitethorn Lawsuit”).

Removed

Environmental Protection Agency (the “EPA”), and the State of Colorado commenced an enforcement action in the United States District Court for the District of Colorado against Kerr - McGee Gathering LLC (“KMG”), a wholly owned subsidiary of WES, for alleged non - compliance with the leak detection and repair requirements of the federal Clean Air Act (“LDAR requirements”) at its Fort Lupton facility in the DJ Basin complex.

Added

In the Whitethorn Lawsuit, we alleged, among other things, that Enterprise breached a contract related to its hydrocarbon trading activity that utilized the Whitethorn pipeline, and that Enterprise, as operator of the Whitethorn pipeline, breached its duties to act as a reasonable and prudent operator and for the sole benefit of the Whitethorn joint venture (in which WGR was a 20% owner).

Removed

KMG previously had been in negotiations with the EPA and the State of Colorado to resolve the alleged non - compliance at the Fort Lupton facility. Per the complaint, plaintiffs pray for injunctive relief, remedial action, and civil penalties. We are currently exploring global resolution of the claims.

Added

In response, Enterprise filed counterclaims related to alleged overpayments to WGR of approximately $12.0 million. In connection with the sales of our interests in both the Mont Belvieu JV and Whitethorn LLC on February 16, 2024, the Mont Belvieu Lawsuit and the Whitethorn Lawsuit were settled.

Removed

While such resolution would likely include an injunctive relief component and payment of a civil penalty, which may exceed the disclosure threshold amount required by Item 103 of Regulation S-K, management believes the resolution of these claims will not have a material impact on WES’s results of operations, cash flows, or financial condition.

Removed

Specifically, the Operating Agreement sets forth a revenue allocation structure, whereby revenue would be allocated to the various fracs at the Mont Belvieu complex in sequential order, with Fracs VII and VIII (which are owned by Mont Belvieu JV) following Fracs I through VI, but preceding any “Later Frac Facilities.” Subsequent to the construction of Fracs VII and VIII, Enterprise built Fracs IX, X, and XI, which it wholly owns, and has treated such subsequent fracs as outside the Mont Belvieu revenue allocation.

Removed

We do not believe Enterprise’s attempt to bypass the agreed - to revenue allocation is proper under the parties’ agreements and now seek judicial determination. We currently sue only for declaratory judgment to avoid potential future damages. We cannot make any assurances regarding the ultimate outcome of this proceeding and its resulting impact on WGR or WES.

Removed

On November 22, 2022, WGR filed suit against Enterprise Crude Oil LLC (“ECO”) in the District Court of Harris County, Texas. Our lawsuit alleges that ECO breached a contract related to the Whitethorn joint venture pursuant to which ECO must share with WGR certain of the profits and losses generated by ECO’s hydrocarbon trading activity conducted utilizing the Whitethorn pipeline.

Removed

Specifically, we claim that ECO has engaged in trades knowing that the revenue to be realized would be less than the minimum floor set under the contract and has failed to allocate revenues and expenses as prescribed by the contract, resulting in improper losses to WGR.

Removed

Enterprise has filed a counterclaim to our lawsuit, alleging that, between 2017 and 2019, it had mistakenly overpaid WGR approximately $12.0 million in trading profits and seeking recovery of such amount. We cannot make any assurances regarding the ultimate outcome of this proceeding and its resulting impact on WGR or WES.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

5 edited+0 added−0 removed7 unchanged

2022 filing

2023 filing

Biggest changeThe following table sets forth information with respect to repurchases made by WES of its common units in the open market or in privately negotiated transactions under the $1.25 billion Purchase Program during the fourth quarter of 2022: Period Total number of units purchased Average price paid per unit Total number of units purchased as part of publicly announced plans or programs (1) Approximate dollar value of units that may yet be purchased under the plans or programs (1) October 1-31, 2022 523,858 $ 25.93 523,858 $ 539,340,520 November 1-30, 2022 175,422 26.79 175,422 784,641,400 December 1-31, 2022 850,668 26.13 850,668 762,409,380 Total 1,549,948 26.14 1,549,948 ______________________________________________________________________________________ (1) In February 2022, WES announced a $1.0 billion purchase program, pursuant to which we may purchase up to $1.0 billion in aggregate value of our common units through December 31, 2024.

Biggest changeThe following table sets forth information with respect to repurchases made by WES of its common units in the open market or in privately negotiated transactions under the $1.25 billion Purchase Program during the fourth quarter of 2023: Period Total number of units purchased Average price paid per unit Total number of units purchased as part of publicly announced plans or programs (1) Approximate dollar value of units that may yet be purchased under the plans or programs (1) October 1-31, 2023 — $ — — $ 627,807,310 November 1-30, 2023 — — — 627,807,310 December 1-31, 2023 — — — 627,807,310 Total — — — ______________________________________________________________________________________ (1) In February 2022, WES announced a $1.0 billion buyback program, pursuant to which we may purchase up to $1.0 billion in aggregate value of our common units through December 31, 2024.

See Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for additional details. 61 Table of Contents 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. Available cash.

See Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for additional details. 55 Table of Contents 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. Available cash.

As of December 31, 2022, our general partner owned a 2.3% general partner interest in us, which entitles it to receive cash distributions. Our general partner may own our common units or other equity securities and would be entitled to receive cash distributions on any such interests. 62 Table of Contents

As of December 31, 2023, our general partner owned a 2.3% general partner interest in us, which entitles it to receive cash distributions. Our general partner may own our common units or other equity securities and would be entitled to receive cash distributions on any such interests. 56 Table of Contents

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities MARKET INFORMATION Our common units are listed on the NYSE under the symbol “WES.” As of February 16, 2023, there were 23 unitholders of record of our common units. This number does not include unitholders whose units are held in trust by other entities.

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities MARKET INFORMATION Our common units are listed on the NYSE under the symbol “WES.” As of February 14, 2024, there were 24 unitholders of record of our common units. This number does not include unitholders whose units are held in trust by other entities.

The 2017 LTIP and the 2021 LTIP permit the issuance of up to 3,431,251 and 9,500,000 units, respectively, of which 1,928,415 and 9,500,000 units, respectively, remained available for future issuance as of December 31, 2022. Read the information under Part III, Item 12 of this Form 10-K, which is incorporated by reference into this Item 5.

The 2017 LTIP and the 2021 LTIP permit the issuance of up to 3,431,251 and 9,500,000 units, respectively, of which 1,226,875 and 9,479,648 units, respectively, remained available for future issuance as of December 31, 2023. Read the information under Part III, Item 12 of this Form 10-K, which is incorporated by reference into this Item 5.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

9 edited+8 added−3 removed8 unchanged

2022 filing

2023 filing

Biggest changeThe following table provides additional information on throughput for the periods presented below: Year Ended December 31, 2022 2021 Inc/ (Dec) 2020 Inc/ (Dec) Throughput for natural-gas assets (MMcf/d) Delaware Basin 1,470 1,256 17 % 1,297 (3) % DJ Basin 1,331 1,369 (3) % 1,305 5 % Equity investments 483 463 4 % 445 4 % Other 1,082 1,215 (11) % 1,386 (12) % Total throughput for natural - gas assets 4,366 4,303 1 % 4,433 (3) % Throughput for crude-oil and NGLs assets (MBbls/d) Delaware Basin 198 183 8 % 189 (3) % DJ Basin 82 90 (9) % 101 (11) % Equity investments 373 366 2 % 381 (4) % Other 37 33 12 % 41 (20) % Total throughput for crude - oil and NGLs assets 690 672 3 % 712 (6) % Throughput for produced-water assets (MBbls/d) Delaware Basin 853 717 19 % 712 1 % Total throughput for produced - water assets 853 717 19 % 712 1 % 64 Table of Contents OUR OPERATIONS Our results primarily are driven by the volumes of natural gas, NGLs, crude oil, and produced water we service through our systems.

Biggest changeSee Reconciliation of Non-GAAP Financial Measures within this Item 7. • Adjusted gross margin for natural - gas assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7) averaged $1.28 per Mcf for the year ended December 31, 2023, representing a 3% decrease compared to the year ended December 31, 2022. • Adjusted gross margin for crude - oil and NGLs assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7) averaged $2.48 per Bbl for the year ended December 31, 2023, representing a 1% increase compared to the year ended December 31, 2022. • Adjusted gross margin for produced - water assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7) averaged $0.83 per Bbl for the year ended December 31, 2023, representing a 12% decrease compared to the year ended December 31, 2022. 58 Table of Contents The following table provides additional information on throughput for the periods presented below: Year Ended December 31, 2023 2022 Inc/ (Dec) Throughput for natural-gas assets (MMcf/d) Delaware Basin 1,635 1,470 11 % DJ Basin 1,322 1,331 (1) % Powder River Basin 120 33 NM Equity investments 466 483 (4) % Other 1,050 1,049 — % Total throughput for natural - gas assets 4,593 4,366 5 % Throughput for crude-oil and NGLs assets (MBbls/d) Delaware Basin 214 198 8 % DJ Basin 71 82 (13) % Powder River Basin 5 — 100 % Equity investments 333 373 (11) % Other 42 37 14 % Total throughput for crude - oil and NGLs assets 665 690 (4) % Throughput for produced-water assets (MBbls/d) Delaware Basin 1,029 853 21 % Total throughput for produced - water assets 1,029 853 21 % _________________________________________________________________________________________ NM — Not meaningful OUR OPERATIONS Our results primarily are driven by the volumes of natural gas, NGLs, crude oil, and produced water we service through our systems.

The Partnership’s assets include assets owned and ownership interests accounted for by us under the equity method of accounting, through our 98.0% partnership interest in WES Operating, as of December 31, 2022 (see Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

The Partnership’s assets include assets owned and ownership interests accounted for by us under the equity method of accounting, through our 98.0% partnership interest in WES Operating, as of December 31, 2023 (see Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).

As of December 31, 2022, our assets and investments consisted of the following: Wholly Owned and Operated Operated Interests Non-Operated Interests Equity Interests Gathering systems (1) 17 2 3 1 Treating facilities 37 3 — — Natural - gas processing plants/trains 25 3 — 3 NGLs pipelines 2 — — 5 Natural - gas pipelines 6 — — 1 Crude - oil pipelines 3 1 — 3 _________________________________________________________________________________________ (1) Includes the DBM water systems.

As of December 31, 2023, our assets and investments consisted of the following: Wholly Owned and Operated Operated Interests Non-Operated Interests Equity Interests Gathering systems (1) 18 2 3 1 Treating facilities 38 3 — — Natural - gas processing plants/trains 24 3 — 3 NGLs pipelines 3 — — 5 Natural - gas pipelines 6 — — 1 Crude - oil pipelines 3 1 — 3 _________________________________________________________________________________________ (1) Includes the DBM water systems.

For example, for the year ended December 31, 2022, our West Texas and DJ Basin assets provided (i) 52% and 32%, respectively, of Total revenues and other, (ii) 38% and 34%, respectively, of our throughput for natural-gas assets (excluding equity-investment throughput), (iii) 62% and 26%, 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 example, for the year ended December 31, 2023, our West Texas and DJ Basin assets provided (i) 53% and 34%, respectively, of Total revenues and other, (ii) 40% and 32%, respectively, of our throughput for natural-gas assets (excluding equity-investment throughput), (iii) 65% and 21%, respectively, of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and (iv) all of our throughput for produced-water assets.

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.

For the year ended December 31, 2022, 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.

In addition, Occidental provides dedications, minimum-volume commitments with associated deficiency payments, and/or cost-of-service commitments under certain of our contracts. 59 Table of Contents For the year ended December 31, 2023, 95% 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.

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.

In our capacity as a natural - gas processor, we also buy and sell natural gas, NGLs, and condensate on behalf of ourselves and our customers under certain contracts. To provide superior midstream service, we focus on ensuring the reliability and performance of our systems, creating sustainable cost efficiencies, enhancing our safety culture, and protecting the environment.

To provide superior midstream service, we focus on ensuring the reliability and performance of our systems, creating sustainable cost efficiencies, enhancing our safety culture, and protecting the environment. We own or have investments in assets located in Texas, New Mexico, the Rocky Mountains (Colorado, Utah, and Wyoming), and North - central Pennsylvania.

We own or have investments in assets located in Texas, New Mexico, the Rocky Mountains (Colorado, Utah, and Wyoming), and North - central Pennsylvania.

Removed

Significant financial and operational events during the year ended December 31, 2022, included the following: • WES Operating redeemed the $502.2 million total principal amount outstanding of the 4.000% Senior Notes due 2022 at par value. • We repurchased 19,532,305 common units, which includes 10,000,000 common units repurchased from Occidental, for an aggregate purchase price of $487.6 million.

Added

Discussion of 2021 items and comparison of the year ended December 31, 2022, to the year ended December 31, 2021, that are not included in this annual report on Form 10-K can be found under Management’s Discussion and Analysis of Financial Condition and Results of Operations, which is included under Part II, Item 7 of our annual report on Form 10-K for the year ended December 31, 2022, and is available via the SEC’s website at www.sec.gov and our website at www.westernmidstream.com.

Removed

In November 2022, the Board authorized an increase in the repurchase program from $1.0 billion to $1.25 billion. • Our fourth - quarter 2022 per - unit distribution is unchanged from the third-quarter 2022 per-unit distribution of $0.50000. • In November 2022, we sold our 15.00% interest in Cactus II to two third parties for $264.8 million, which includes a $1.8 million pro-rata distribution through closing. • In September 2022, we acquired the remaining 50% interest in Ranch Westex from a third party for $40.1 million. 63 Table of Contents • Natural - gas throughput attributable to WES totaled 4,210 MMcf/d for the year ended December 31, 2022, representing a 1% increase compared to the year ended December 31, 2021. • Crude - oil and NGLs throughput attributable to WES totaled 676 MBbls/d for the year ended December 31, 2022, representing a 3% increase compared to the year ended December 31, 2021. • Produced - water throughput attributable to WES totaled 836 MBbls/d for the year ended December 31, 2022, representing a 19% increase compared to the year ended December 31, 2021. • Gross margin was $2.2 billion for the year ended December 31, 2022 representing a 12% increase compared to the year ended December 31, 2021.

Added

Significant financial and operational events during the year ended December 31, 2023, included the following: • On October 13, 2023, we closed on the acquisition of Meritage for $885.0 million (subject to certain customary post-closing adjustments).

Removed

See Reconciliation of Non-GAAP Financial Measures within this Item 7. • Adjusted gross margin for natural - gas assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7) averaged $1.32 per Mcf for the year ended December 31, 2022, representing a 6% increase compared to the year ended December 31, 2021. • Adjusted gross margin for crude - oil and NGLs assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7) averaged $2.46 per Bbl for the year ended December 31, 2022, representing an 8% increase compared to the year ended December 31, 2021. • Adjusted gross margin for produced - water assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7) averaged $0.94 per Bbl for the year ended December 31, 2022, representing a 1% increase compared to the year ended December 31, 2021.

Added

See Items Affecting the Comparability of Our Financial Results within this Item 7 for additional information. • WES Operating completed the public offering of $600.0 million in aggregate principal amount of 6.350% Senior Notes due 2029.

Added

Net proceeds from the offering were used to fund a portion of the aggregate purchase price for the Meritage acquisition, to pay related costs and expenses, and for general partnership purposes.

Added

See Liquidity and Capital Resources within this Item 7 for additional information. • WES Operating completed the public offering of $750.0 million in aggregate principal amount of 6.150% Senior Notes due 2033. Net proceeds from this offering were used to repay borrowings under the RCF and for general partnership purposes.

Added

See Liquidity and Capital Resources within this Item 7 for additional information. 57 Table of Contents • WES Operating redeemed the $213.1 million total principal amount outstanding of the Floating-Rate Senior Notes due 2023 at par value with cash on hand. • WES Operating purchased and retired $276.7 million of certain of its senior notes via open-market repurchases. • In November 2023, WES operating entered into an unsecured commercial paper program under which it may issue (and have outstanding at any one time) an aggregate principal amount up to $2.0 billion.

Added

See Liquidity and Capital Resources within this Item 7 for additional information. • Our fourth - quarter 2023 per - unit distribution is unchanged from the third-quarter 2023 per-unit distribution of $0.575. • The Board approved an Enhanced Distribution of $0.356 per unit, or $140.1 million, related to our 2022 performance.

Added

This Enhanced Distribution was paid, along with our regular first-quarter 2023 distribution, on May 15, 2023, to our unitholders of record at the close of business on May 1, 2023. • We repurchased 5,387,322 common units, which includes 5,100,000 common units repurchased from Occidental, for an aggregate purchase price of $134.6 million. • Natural - gas throughput attributable to WES totaled 4,432 MMcf/d for the year ended December 31, 2023, representing a 5% increase compared to the year ended December 31, 2022. • Crude - oil and NGLs throughput attributable to WES totaled 652 MBbls/d for the year ended December 31, 2023, representing a 4% decrease compared to the year ended December 31, 2022. • Produced - water throughput attributable to WES totaled 1,009 MBbls/d for the year ended December 31, 2023, representing a 21% increase compared to the year ended December 31, 2022. • Gross margin was $2,341.2 million for the year ended December 31, 2023, representing a 4% increase compared to the year ended December 31, 2022.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

109 edited+23 added−98 removed74 unchanged

2022 filing

2023 filing

Biggest changeCalculated as Adjusted Gross margin for natural - gas assets, crude - oil and NGLs assets, or produced - water assets, divided by the respective total throughput (MMcf or MBbls) attributable to WES for natural - gas assets, crude - oil and NGLs assets, or produced - water assets. 79 Table of Contents Year Ended December 31, thousands 2022 2021 2020 Reconciliation of Net income (loss) to Adjusted EBITDA Net income (loss) $ 1,251,456 $ 943,999 $ 516,852 Add: Distributions from equity investments 250,050 254,901 278,797 Non - cash equity - based compensation expense 27,783 27,676 22,462 Interest expense 333,939 376,512 380,058 Income tax expense 4,187 4,403 10,278 Depreciation and amortization 582,365 551,629 491,086 Impairments (1) 20,585 30,543 644,906 Other expense 555 1,468 1,953 Less: Gain (loss) on divestiture and other, net 103,676 44 8,634 Gain (loss) on early extinguishment of debt 91 (24,944) 11,234 Equity income, net – related parties 183,483 204,645 226,750 Interest income – Anadarko note receivable — — 11,736 Other income 1,648 585 2,785 Income tax benefit — 14,210 4,280 Adjusted EBITDA attributable to noncontrolling interests (2) 54,049 49,901 50,607 Adjusted EBITDA $ 2,127,973 $ 1,946,690 $ 2,030,366 Reconciliation of Net cash provided by operating activities to Adjusted EBITDA Net cash provided by operating activities $ 1,701,426 $ 1,766,852 $ 1,637,418 Interest (income) expense, net 333,939 376,512 368,322 Accretion and amortization of long - term obligations, net (7,142) (7,635) (8,654) Current income tax expense (benefit) 2,188 (37) 2,702 Other (income) expense, net (1,603) 623 (1,025) Cash paid to settle interest - rate swaps — — 25,621 Distributions from equity investments in excess of cumulative earnings – related parties 63,897 41,385 32,160 Changes in assets and liabilities: Accounts receivable, net 116,296 (16,366) 193,688 Accounts and imbalance payables and accrued liabilities, net 7,812 (114,887) (144,437) Other items, net (34,791) (49,856) (24,822) Adjusted EBITDA attributable to noncontrolling interests (2) (54,049) (49,901) (50,607) Adjusted EBITDA $ 2,127,973 $ 1,946,690 $ 2,030,366 Cash flow information Net cash provided by operating activities $ 1,701,426 $ 1,766,852 $ 1,637,418 Net cash used in investing activities (218,237) (257,538) (448,254) Net cash provided by (used in) financing activities (1,398,532) (1,752,237) (844,204) _________________________________________________________________________________________ (1) Includes goodwill impairment for the year ended December 31, 2020.

Biggest changeCalculated as Adjusted gross margin for natural - gas assets, crude - oil and NGLs assets, or produced - water assets, divided by the respective total throughput (MMcf or MBbls) attributable to WES for natural - gas assets, crude - oil and NGLs assets, or produced - water assets. 70 Table of Contents Year Ended December 31, thousands 2023 2022 Reconciliation of Net income (loss) to Adjusted EBITDA Net income (loss) $ 1,048,007 $ 1,251,456 Add: Distributions from equity investments 194,273 250,050 Non - cash equity - based compensation expense 32,005 27,783 Interest expense 348,228 333,939 Income tax expense 4,385 4,187 Depreciation and amortization 600,668 582,365 Impairments 52,884 20,585 Other expense 1,739 555 Less: Gain (loss) on divestiture and other, net (10,102) 103,676 Gain (loss) on early extinguishment of debt 15,378 91 Equity income, net – related parties 152,959 183,483 Other income 6,976 1,648 Adjusted EBITDA attributable to noncontrolling interests (1) 48,345 54,049 Adjusted EBITDA $ 2,068,633 $ 2,127,973 Reconciliation of Net cash provided by operating activities to Adjusted EBITDA Net cash provided by operating activities $ 1,661,334 $ 1,701,426 Interest (income) expense, net 348,228 333,939 Accretion and amortization of long - term obligations, net (8,151) (7,142) Current income tax expense (benefit) 3,341 2,188 Other (income) expense, net (5,679) (1,603) Distributions from equity investments in excess of cumulative earnings – related parties 39,104 63,897 Changes in assets and liabilities: Accounts receivable, net 78,346 116,296 Accounts and imbalance payables and accrued liabilities, net 68,019 7,812 Other items, net (67,564) (34,791) Adjusted EBITDA attributable to noncontrolling interests (1) (48,345) (54,049) Adjusted EBITDA $ 2,068,633 $ 2,127,973 Cash flow information Net cash provided by operating activities $ 1,661,334 $ 1,701,426 Net cash used in investing activities (1,607,291) (218,237) Net cash provided by (used in) financing activities (67,912) (1,398,532) _________________________________________________________________________________________ (1) Includes (i) the 25% third - party interest in Chipeta and (ii) the 2.0% limited partner interest in WES Operating owned by an Occidental subsidiary, which collectively represent WES’s noncontrolling interests. 71 Table of Contents Year Ended December 31, thousands 2023 2022 Reconciliation of Net cash provided by operating activities to Free cash flow Net cash provided by operating activities $ 1,661,334 $ 1,701,426 Less: Capital expenditures 735,080 487,228 Contributions to equity investments – related parties 1,153 9,632 Add: Distributions from equity investments in excess of cumulative earnings – related parties 39,104 63,897 Free cash flow $ 964,205 $ 1,268,463 Cash flow information Net cash provided by operating activities $ 1,661,334 $ 1,701,426 Net cash used in investing activities (1,607,291) (218,237) Net cash provided by (used in) financing activities (67,912) (1,398,532) Gross margin.

For additional information, see Note 12—Asset Retirement Obligations in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Operating leases. We have entered into operating leases for corporate offices, field offices, easements, and equipment supporting our operations, with both Occidental and third parties as lessors.

For additional information, see Note 12—Asset Retirement Obligations in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Operating leases. We have entered into operating leases for corporate offices, shared field offices, easements, and equipment supporting our operations, with both Occidental and third parties as lessors.

This Enhanced Distribution is subject to Board discretion, the establishment of cash reserves for the proper conduct of our business, and is also contingent on the attainment of prior year-end net leverage levels (the ratio of our total principal debt outstanding less total cash on hand as of the end of such period, as compared to our trailing twelve months Adjusted EBITDA), after taking the Enhanced Distribution for such prior year into effect.

This Enhanced Distribution is subject to Board discretion, the establishment of cash reserves for the proper conduct of our business and is also contingent on the attainment of prior year-end net leverage thresholds (the ratio of our total principal debt outstanding less total cash on hand as of the end of such period, as compared to our trailing-twelve-months Adjusted EBITDA), after taking the Enhanced Distribution for such prior year into effect.

The primary assumptions used to estimate undiscounted future net cash flows include long-range customer production forecasts and revenue, capital, and operating expense estimates. Management applies judgment in the grouping of assets for impairment assessment, determining whether there is an impairment indicator, and determinations about the future use of such assets.

The primary assumptions used to estimate undiscounted future net cash flows include long-range customer throughput forecasts and revenue, capital, and operating expense estimates. Management applies judgment in the grouping of assets for impairment assessment, determining whether there is an impairment indicator, and determinations about the future use of such assets.

See Note 9—Property, Plant, and Equipment and Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K for a description of impairments recorded during the years ended December 31, 2022, 2021, and 2020. Fair value.

Additionally, as with other yield-oriented securities, our unit price could be impacted by our implied distribution yield relative to market interest rates.

As with other yield-oriented securities, our unit price could be impacted by our implied distribution yield relative to market interest rates.

Management’s estimate of the asset’s fair value may be determined based on the estimates of future discounted net cash flows or values at which similar assets were transferred in the market in recent transactions, if such data is available. 93 Table of Contents Impairments of equity investments.

Management’s estimate of the asset’s fair value may be determined based on the estimates of future discounted net cash flows or values at which similar assets were transferred in the market in recent transactions, if such data is available. 82 Table of Contents Impairments of equity investments.

Instead, Free cash flow should be considered indicative of the amount of cash that is available for distributions, debt repayments, and other general partnership purposes. 77 Table of Contents Adjusted gross margin, Adjusted EBITDA, and Free cash flow are not defined in GAAP. The GAAP measure that is most directly comparable to Adjusted gross margin is gross margin.

Instead, Free cash flow should be considered indicative of the amount of cash that is available for distributions, debt repayments, and other general partnership purposes. 68 Table of Contents Adjusted gross margin, Adjusted EBITDA, and Free cash flow are not defined in GAAP. The GAAP measure that is most directly comparable to Adjusted gross margin is gross margin.

Our ability to make cash distributions to our unitholders may be adversely impacted if Occidental becomes unable to perform under the terms of gathering, processing, transportation, and disposal agreements. 91 Table of Contents ITEMS AFFECTING THE COMPARABILITY OF FINANCIAL RESULTS WITH WES OPERATING Our consolidated financial statements include the consolidated financial results of WES Operating.

Our ability to make cash distributions to our unitholders may be adversely impacted if Occidental becomes unable to perform under the terms of gathering, processing, transportation, and disposal agreements. 80 Table of Contents ITEMS AFFECTING THE COMPARABILITY OF FINANCIAL RESULTS WITH WES OPERATING Our consolidated financial statements include the consolidated financial results of WES Operating.

See Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 92 Table of Contents Noncontrolling interest. WES Operating’s noncontrolling interest consists of the 25% third - party interest in Chipeta.

See Note 4—Partnership Distributions and Note 5—Equity and Partners’ Capital in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 81 Table of Contents Noncontrolling interest. WES Operating’s noncontrolling interest consists of the 25% third - party interest in Chipeta.

We are subject to the risk of non - payment or late payment by producers for gathering, processing, transportation, and disposal fees. Additionally, we continue to evaluate counterparty credit risk and, in certain circumstances, are exercising our rights to request adequate assurance.

A 10% increase or decrease in commodity prices would not have a material impact on our operating income (loss), financial condition, or cash flows for the next 12 months, excluding the effect of the below - described imbalances.

In addition to cash and cash equivalents and cash flows generated from operations, we have historically accessed the debt and equity capital markets to raise money to fund capital expenditures, to refinance long-term debt, to fund unit repurchases, and to fund acquisitions.

Liquidity and access to capital markets. In addition to cash and cash equivalents and cash flows generated from operations, we have historically accessed the debt and equity capital markets to raise money to fund capital expenditures, to refinance long-term debt, to fund unit repurchases, and to fund acquisitions.

While a 10% change in the applicable benchmark interest rate would not materially impact interest expense on our outstanding borrowings at December 31, 2022, it would impact the fair value of the senior notes.

While a 10% change in the applicable benchmark interest rate would not materially impact interest expense on our outstanding borrowings at December 31, 2023, it would impact the fair value of the senior notes.

Net cash provided by operating activities decreased for the year ended December 31, 2022, primarily due to (i) the impact of changes in assets and liabilities and (ii) lower distributions from equity investments. These decreases were partially offset by (i) higher cash operating income and (ii) lower interest expense.

Net cash provided by operating activities decreased for the year ended December 31, 2023, primarily due to (i) lower distributions from equity investments, (ii) higher interest expense, and (iii) lower cash operating income. These decreases were partially offset by the impact of changes in assets and liabilities.

The number and scope of the regulations with which we and our customers must comply has a meaningful impact on our and their businesses, and new or revised regulations, reinterpretations of existing regulations, and permitting delays or denials could adversely affect the throughput on and profitability of our assets. Impact of inflation and supply-chain disruptions.

Increases in inflationary pressure could materially and negatively impact our financial results. To the extent permitted by regulations and escalation provisions in certain of our existing agreements, we have the ability to recover a portion of increased costs in the form of higher fees. 84 Table of Contents Impact of interest rates.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk under Part II of this Form 10-K. 65 Table of Contents HOW WE EVALUATE OUR OPERATIONS Our management relies on certain financial and operational metrics to analyze our performance.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk under Part II of this Form 10-K. HOW WE EVALUATE OUR OPERATIONS Our management relies on certain financial and operational metrics to analyze our performance.

(2) For all periods presented, includes (i) the 2.0% limited partner interest in WES Operating owned by an Occidental subsidiary and (ii) for natural - gas assets, the 25% third - party interest in Chipeta, which collectively represent WES’s noncontrolling interests.

(2) Includes (i) the 2.0% limited partner interest in WES Operating owned by an Occidental subsidiary and (ii) for natural - gas assets, the 25% third - party interest in Chipeta, which collectively represent WES’s noncontrolling interests.

The electricity-related expenses included in our Adjusted gross margin definition relate to pass-through expenses that are reimbursed by certain customers (recorded as revenue with an offset recorded as Operation and maintenance expense). Adjusted EBITDA.

The electricity-related expenses included in our Adjusted gross margin definition relate to pass-through expenses that are recorded as Operation and maintenance expense with an offset recorded as revenue for the reimbursement by certain customers. Adjusted EBITDA.

Changes in our business and economic conditions are evaluated for their implications on recoverability of the assets’ carrying values. Significant downward revisions in production forecasts or changes in future development plans by producers, to the extent they affect our operations, may necessitate an impairment assessment.

Changes in our business and economic conditions are evaluated for their implications on recoverability of the assets’ carrying values. Significant downward revisions in throughput forecasts or changes in future development plans by producers, to the extent they affect our operations, may trigger an impairment assessment.

LIQUIDITY AND CAPITAL RESOURCES Our primary cash uses include equity and debt service, operating expenses, and capital expenditures. Our sources of liquidity as of December 31, 2022, included cash and cash equivalents, cash flows generated from operations, available borrowing capacity under the RCF, and potential issuances of additional equity or debt securities.

LIQUIDITY AND CAPITAL RESOURCES Our primary cash uses include equity and debt service, operating expenses, and capital expenditures. Our sources of liquidity, as of December 31, 2023, included cash and cash equivalents, cash flows generated from operations, available borrowing capacity under the RCF, our commercial paper program, and potential issuances of additional equity or debt securities.

For the year ended December 31, 2023, 95% 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.

Cost of product expenses include (i) costs associated with the purchase of natural gas and NGLs pursuant to our percent - of - proceeds, percent - of - product, and keep - whole contracts, (ii) costs associated with the valuation of gas and NGLs imbalances, and (iii) costs associated with our obligations under certain contracts to redeliver a volume of natural gas to shippers, which is thermally equivalent to condensate retained by us and sold to third parties.

Cost of product expenses include (i) costs associated with the purchase of natural gas and NGLs pursuant to our percent - of - proceeds, percent - of - product, and keep - whole contracts, (ii) costs associated with the valuation of gas and NGLs imbalances, (iii) costs associated with our obligations under certain contracts to redeliver a volume of natural gas to shippers, which is thermally equivalent to condensate retained by us and sold to third parties, and (iv) costs associated with our offload commitments with third parties providing firm-processing capacity.

See General Trends and Outlook under Part II, Item 7 and Risk Factors under Part I, Item 1A of this Form 10-K. Interest-rate risk. The Federal Open Market Committee made no changes to its target range for the federal funds rate in 2021 and increased its target range seven times during the year ended December 31, 2022.

See General Trends and Outlook under Part II, Item 7 and Risk Factors under Part I, Item 1A of this Form 10-K. Interest-rate risk. The Federal Open Market Committee increased its target range seven times for the federal funds rate in 2022 and increased its target range four times during the year ended December 31, 2023.

When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying amount of the investment to determine whether the investment has been impaired.

When evidence of an other-than-temporary loss in value has occurred, management compares the estimated fair value of the investment to the carrying amount of the investment to determine whether the investment has been impaired.

Certain of our processing services are provided under percent - of - proceeds and keep - whole agreements. Under percent - of - proceeds agreements, we receive a specified percentage of the net proceeds from the sale of residue and/or NGLs.

Quantitative and Qualitative Disclosures About Market Risk Commodity-price risk. Certain of our processing services are provided under percent - of - proceeds and keep - whole agreements. Under percent - of - proceeds agreements, we receive a specified percentage of the net proceeds from the sale of residue and/or NGLs.

Revisions in estimated asset retirement obligations may result from changes in estimated asset retirement costs, inflation rates, discount rates, and the estimated timing of settlement. As of December 31, 2022, we expect to incur asset retirement costs of $10.5 million in 2023 and a total of $290.0 million in years thereafter.

Revisions in estimated asset retirement obligations may result from changes in estimated asset retirement costs, inflation rates, discount rates, and the estimated timing of settlement. As of December 31, 2023, we expect to incur asset retirement costs of $7.6 million in 2024 and a total of $359.2 million in years thereafter.

More specifically, the bottlenecks and disruptions from the lingering effects of the COVID-19 crisis have caused difficulties within the U.S. and global supply chains, creating logistical delays along with labor shortages. Continued inflation has raised our costs for labor, materials, fuel, and services, which has increased our operating costs and capital expenditures.

More specifically, the continued bottlenecks and disruptions have caused difficulties within the U.S. and global supply chains, creating logistical delays along with labor shortages. Continued inflation has raised our costs for steel products, automation components, power supply, labor, materials, fuel, and services, which has increased our operating costs and capital expenditures.

See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. RECENT ACCOUNTING DEVELOPMENTS See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 83 Table of Contents Item 7A.

The differences between net income (loss) attributable to WES and WES Operating are reconciled as follows: Year Ended December 31, thousands 2022 2021 2020 Net income (loss) attributable to WES $ 1,217,103 $ 916,292 $ 527,012 Limited partner interest in WES Operating not held by WES (1) 24,899 18,765 10,830 General and administrative expenses (2) 2,656 2,932 3,552 Other income (expense), net (45) (11) (17) Income taxes 7 9 — Net income (loss) attributable to WES Operating $ 1,244,620 $ 937,987 $ 541,377 _________________________________________________________________________________________ (1) Represents the portion of net income (loss) allocated to the limited partner interest in WES Operating not held by WES.

The differences between net income (loss) attributable to WES and WES Operating are reconciled as follows: Year Ended December 31, thousands 2023 2022 2021 Net income (loss) attributable to WES $ 1,022,216 $ 1,217,103 $ 916,292 Limited partner interest in WES Operating not held by WES (1) 20,922 24,899 18,765 General and administrative expenses (2) 2,943 2,656 2,932 Other income (expense), net (275) (45) (11) Income taxes 6 7 9 Net income (loss) attributable to WES Operating $ 1,045,812 $ 1,244,620 $ 937,987 _________________________________________________________________________________________ (1) Represents the portion of net income (loss) allocated to the limited partner interest in WES Operating not held by WES.

Although inflation in the United States has been relatively low in recent years, the U.S. economy currently is experiencing significant inflation relative to historical precedent, from, among other things, supply-chain disruptions caused by, or governmental stimulus or fiscal policies adopted in response to, the COVID-19 crisis and in connection with the war in Ukraine.

The U.S. economy has recently experienced significant inflation relative to historical precedent, from, among other things, supply-chain disruptions caused by, or governmental stimulus or fiscal policies adopted in response to, the COVID-19 crisis and in connection with the war in Ukraine.

Per - Bbl Adjusted gross margin for crude - oil and NGLs assets increased by $0.18 for the year ended December 31, 2022, primarily due to (i) increased throughput and increased deficiency fee revenues at the DBM oil system, which has a higher - than - average per - Bbl margin as compared to our other crude - oil and NGLs assets, (ii) a higher cumulative catch-up adjustment for changes in estimated consideration in 2022 compared to 2021 at the DJ Basin oil system, and (iii) an increase in distributions from Cactus II.

Per - Bbl Adjusted gross margin for crude - oil and NGLs assets increased by $0.02 for the year ended December 31, 2023, primarily due to (i) decreases in throughput and distributions from Cactus II, which was sold in the fourth quarter of 2022 and had lower-than-average per-Bbl margin as compared to our other crude-oil and NGLs assets, (ii) a higher cumulative catch-up adjustment for changes in estimated consideration in 2023 as compared to 2022, partially offset by decreased throughput and deficiency fees at the DJ Basin oil system, which has a higher-than-average per-Bbl margin as compared to our other crude-oil and NGLs assets, and (iii) an increase in distributions from FRP.

The differences between net cash provided by (used in) operating and financing activities for WES and WES Operating are reconciled as follows: Year Ended December 31, thousands 2022 2021 2020 WES net cash provided by operating activities $ 1,701,426 $ 1,766,852 $ 1,637,418 General and administrative expenses (1) 2,656 2,932 3,552 Non - cash equity - based compensation expense (570) 6,912 (7,858) Changes in working capital (9,341) (11,315) 7,556 Other income (expense), net (45) (11) (17) Income taxes 7 9 — WES Operating net cash provided by operating activities $ 1,694,133 $ 1,765,379 $ 1,640,651 WES net cash provided by (used in) financing activities $ (1,398,532) $ (1,752,237) $ (844,204) Distributions to WES unitholders (2) 735,755 533,758 695,834 Distributions to WES from WES Operating (3) (1,219,635) (734,034) (756,112) Increase (decrease) in outstanding checks 103 (68) (35) Unit repurchases 487,590 217,465 32,535 Other 9,326 4,336 — WES Operating net cash provided by (used in) financing activities $ (1,385,393) $ (1,730,780) $ (871,982) _________________________________________________________________________________________ (1) Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating.

The differences between net cash provided by (used in) operating and financing activities for WES and WES Operating are reconciled as follows: Year Ended December 31, thousands 2023 2022 2021 WES net cash provided by operating activities $ 1,661,334 $ 1,701,426 $ 1,766,852 General and administrative expenses (1) 2,943 2,656 2,932 Non - cash equity - based compensation expense (581) (570) 6,912 Changes in working capital (15,226) (9,341) (11,315) Other income (expense), net (275) (45) (11) Income taxes 6 7 9 WES Operating net cash provided by operating activities $ 1,648,201 $ 1,694,133 $ 1,765,379 WES net cash provided by (used in) financing activities $ (67,912) $ (1,398,532) $ (1,752,237) Distributions to WES unitholders (2) 978,430 735,755 533,758 Distributions to WES from WES Operating (3) (1,119,367) (1,219,635) (734,034) Increase (decrease) in outstanding checks (52) 103 (68) Unit repurchases 134,602 487,590 217,465 Other 15,472 9,326 4,336 WES Operating net cash provided by (used in) financing activities $ (58,827) $ (1,385,393) $ (1,730,780) _________________________________________________________________________________________ (1) Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating.

As of December 31, 2022, we had a $3.4 million working capital deficit, which we define as the amount by which current liabilities exceed current assets. Our working capital deficit was primarily due to the Floating-Rate Senior Notes being classified as short-term debt on the consolidated balance sheet as of December 31, 2022.

As of December 31, 2023, we had a $311.6 million working capital deficit, which we define as the amount by which current liabilities exceed current assets. Our working capital deficit was primarily due to the outstanding commercial paper borrowings being classified as short-term debt on the consolidated balance sheet.

Acquisitions for the year ended December 31, 2022, include the acquisition of the remaining 50% interest in Ranch Westex (see Acquisitions and Divestitures within this Item 7).

Acquisitions for the year ended December 31, 2023, include the acquisition of Meritage. Acquisitions for the year ended December 31, 2022, include the acquisition of the remaining 50% interest in Ranch Westex. See Items Affecting the Comparability of Our Financial Results within this Item 7.

The program does not obligate us to purchase any specific dollar amount or number of units and may be suspended or discontinued at any time. During the year ended December 31, 2022, we repurchased 19,532,305 common units, which includes 10,000,000 common units repurchased 85 Table of Contents from Occidental, for an aggregate purchase price of $487.6 million.

The program does not obligate us to purchase any specific dollar amount or number of units and may be suspended or discontinued at any time. During the year ended December 31, 2023, we repurchased 5,387,322 common units, which includes 5,100,000 common units repurchased from Occidental, for an aggregate purchase price of $134.6 million. The units were canceled immediately upon receipt.

We recognized long-lived asset and other impairments of $20.6 million, $30.5 million, and $203.9 million (all of which include an other-than-temporary impairment expense of an equity investment) for the years ended December 31, 2022, 2021, and 2020, respectively.

We recognized long-lived asset and other impairments of $52.9 million for the year ended December 31, 2023, and $20.6 million (which includes an other-than-temporary impairment expense of an equity investment) for the year ended December 31, 2022.

Refer to Historical cash flow within this Item 7 for a discussion of the primary components of Net cash provided by operating activities as compared to the prior periods. 81 Table of Contents KEY PERFORMANCE METRICS Year Ended December 31, thousands except percentages and per-unit amounts 2022 2021 Inc/ (Dec) 2020 Inc/ (Dec) Adjusted gross margin $ 2,925,475 $ 2,667,516 10 % $ 2,718,205 (2) % Per - Mcf Adjusted gross margin for natural - gas assets (1) 1.32 1.24 6 % 1.16 7 % Per - Bbl Adjusted gross margin for crude - oil and NGLs assets (1) 2.46 2.28 8 % 2.54 (10) % Per - Bbl Adjusted gross margin for produced - water assets (1) 0.94 0.93 1 % 0.98 (5) % Adjusted EBITDA 2,127,973 1,946,690 9 % 2,030,366 (4) % Free cash flow 1,268,463 1,490,128 (15) % 1,226,588 21 % _________________________________________________________________________________________ (1) Average for period.

Refer to Historical cash flow within this Item 7 for a discussion of the primary components of Net cash provided by operating activities as compared to the prior periods. 72 Table of Contents KEY PERFORMANCE METRICS Year Ended December 31, thousands except percentages and per-unit amounts 2023 2022 Inc/ (Dec) Adjusted gross margin $ 2,963,847 $ 2,925,475 1 % Per - Mcf Adjusted gross margin for natural - gas assets (1) 1.28 1.32 (3) % Per - Bbl Adjusted gross margin for crude - oil and NGLs assets (1) 2.48 2.46 1 % Per - Bbl Adjusted gross margin for produced - water assets (1) 0.83 0.94 (12) % Adjusted EBITDA 2,068,633 2,127,973 (3) % Free cash flow 964,205 1,268,463 (24) % _________________________________________________________________________________________ (1) Average for period.

Net cash used in investing activities for the year ended December 31, 2021, primarily included the following: • $313.7 million of capital expenditures, primarily related to construction, expansion, and asset - integrity projects at the West Texas complex, DBM water systems, DJ Basin complex, and DBM oil system; • $4.4 million of capital contributions primarily paid to Cactus II; 87 Table of Contents • $41.4 million of distributions received from equity investments in excess of cumulative earnings; • $11.1 million of decreases to materials and supplies inventory; and • $8.0 million related to the sale of the Bison treating facility.

Net cash used in investing activities for the year ended December 31, 2023, primarily included the following: • $877.7 million of cash paid, net of cash received, for the acquisition of Meritage; • $735.1 million of capital expenditures, primarily related to expansion, construction, and asset - integrity projects at the West Texas complex, DBM water systems, DJ Basin complex, and DBM oil system; • $32.3 million of increases to materials and supplies inventory; and • $39.1 million of distributions received from equity investments in excess of cumulative earnings.

We believe that cash flows generated from these sources will be sufficient to satisfy our short - term working capital requirements and long - term capital - expenditure and debt-service requirements. The amount of future distributions to unitholders will be determined by the Board on a quarterly basis.

The following tables present (i) a reconciliation of the GAAP financial measure of gross margin to the non - GAAP financial measure of Adjusted gross margin, (ii) a reconciliation of the GAAP financial measures of net income (loss) and net cash provided by operating activities to the non - GAAP financial measure of Adjusted EBITDA, and (iii) a reconciliation of the GAAP financial measure of net cash provided by operating activities to the non - GAAP financial measure of Free cash flow: Year Ended December 31, thousands 2022 2021 2020 Reconciliation of Gross margin to Adjusted gross margin Total revenues and other $ 3,251,721 $ 2,877,155 $ 2,772,592 Less: Cost of product 420,900 322,285 188,088 Depreciation and amortization 582,365 551,629 491,086 Gross margin 2,248,456 2,003,241 2,093,418 Add: Distributions from equity investments 250,050 254,901 278,797 Depreciation and amortization 582,365 551,629 491,086 Less: Reimbursed electricity-related charges recorded as revenues 81,764 74,405 79,261 Adjusted gross margin attributable to noncontrolling interests (1) 73,632 67,850 65,835 Adjusted gross margin $ 2,925,475 $ 2,667,516 $ 2,718,205 _________________________________________________________________________________________ (1) For all periods presented, includes (i) the 25% third - party interest in Chipeta and (ii) the 2.0% limited partner interest in WES Operating owned by an Occidental subsidiary, which collectively represent WES’s noncontrolling interests. 78 Table of Contents To facilitate investor and industry analyst comparisons between us and our peers, we also disclose per-Mcf Adjusted gross margin for natural-gas assets, per-Bbl Adjusted gross margin for crude-oil and NGLs assets, and per-Bbl Adjusted gross margin for produced-water assets .

The following tables present (i) a reconciliation of the GAAP financial measure of gross margin to the non - GAAP financial measure of Adjusted gross margin, (ii) a reconciliation of the GAAP financial measures of net income (loss) and net cash provided by operating activities to the non - GAAP financial measure of Adjusted EBITDA, and (iii) a reconciliation of the GAAP financial measure of net cash provided by operating activities to the non - GAAP financial measure of Free cash flow: Year Ended December 31, thousands 2023 2022 Reconciliation of Gross margin to Adjusted gross margin Total revenues and other $ 3,106,476 $ 3,251,721 Less: Cost of product 164,598 420,900 Depreciation and amortization 600,668 582,365 Gross margin 2,341,210 2,248,456 Add: Distributions from equity investments 194,273 250,050 Depreciation and amortization 600,668 582,365 Less: Reimbursed electricity-related charges recorded as revenues 102,109 81,764 Adjusted gross margin attributable to noncontrolling interests (1) 70,195 73,632 Adjusted gross margin $ 2,963,847 $ 2,925,475 _________________________________________________________________________________________ (1) Includes (i) the 25% third - party interest in Chipeta and (ii) the 2.0% limited partner interest in WES Operating owned by an Occidental subsidiary, which collectively represent WES’s noncontrolling interests. 69 Table of Contents To facilitate investor and industry analysis, we also disclose per-Mcf Adjusted gross margin for natural-gas assets, per-Bbl Adjusted gross margin for crude-oil and NGLs assets, and per-Bbl Adjusted gross margin for produced-water assets .

As of December 31, 2022, we have future operating-lease payments of $10.5 million in 2023 and a total of $41.7 million in years thereafter. See Note 14—Leases in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Pipeline commitments.

As of December 31, 2023, we have future operating-lease payments of $11.6 million in 2024 and a total of $67.7 million in years thereafter. See Note 14—Leases in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Offload commitments. We have entered into offload agreements with third parties providing firm-processing capacity through 2025.

Acquisitions and capital expenditures as presented in the consolidated statements of cash flows and capital incurred were as follows: Year Ended December 31, thousands 2022 2021 2020 Acquisitions $ 40,127 $ — $ — Capital expenditures (1) 487,228 313,674 423,602 Capital incurred (1) 534,342 324,150 307,644 _________________________________________________________________________________________ (1) For the years ended December 31, 2022, 2021, and 2020, included $5.6 million, $3.6 million, and $4.8 million, respectively, of capitalized interest.

Acquisitions and capital expenditures as presented in the consolidated statements of cash flows and capital incurred were as follows: Year Ended December 31, thousands 2023 2022 Acquisitions $ 877,746 $ 40,127 Capital expenditures (1) 735,080 487,228 Capital incurred (1) 752,338 534,342 _________________________________________________________________________________________ (1) For the years ended December 31, 2023 and 2022, included $13.6 million and $5.6 million, respectively, of capitalized interest.

These increases were offset partially by decreased throughput on certain fee-based contracts at the DJ Basin complex, which has a higher - than - average per - Mcf margin as compared to our other natural-gas assets.

These decreases were partially offset by (i) increased throughput at the West Texas complex, which has a higher-than-average per-Mcf margin as compared to our other natural-gas assets, and (ii) increased deficiency fees at the DJ Basin complex.

For example, NYMEX West Texas Intermediate crude - oil daily settlement prices during 2021 ranged from a low of $47.62 per barrel in January 2021 to a high of $84.65 per barrel in October 2021, and prices during the year ended December 31, 2022, ranged from a high of $123.70 per barrel in March 2022 to a low of $71.02 per barrel in December 2022.

For example, the New York Mercantile Exchange (“NYMEX”) West Texas Intermediate crude - oil daily settlement prices during 2022 ranged from a high of $123.70 per barrel in March 2022 to a low of $71.02 per barrel in December 2022, and prices during the year ended December 31, 2023, ranged from a low of $66.74 per barrel in March 2023 to a high of $93.68 per barrel in September 2023.

Free cash flow increased by $263.5 million for the year ended December 31, 2021, primarily due to (i) an increase of $129.4 million in net cash provided by operating activities, (ii) a decrease of $109.9 million in capital expenditures, (iii) a decrease of $15.0 million in contributions to equity investments, and (iv) a $9.2 million increase in distributions from equity investments in excess of cumulative earnings.

Free cash flow decreased by $304.3 million for the year ended December 31, 2023, primarily due to (i) a $247.9 million increase in capital expenditures, (ii) a $40.1 million decrease in net cash provided by operating activities, and (iii) a $24.8 million decrease in distributions from equity investments in excess of cumulative earnings.

Per - Bbl Adjusted gross margin for produced - water assets decreased by $0.05 for the year ended December 31, 2021, primarily due to a lower average fee resulting from a cost - of - service rate redetermination effective January 1, 2021. Adjusted EBITDA.

These increases were partially offset by decreases in distributions from Whitethorn LLC, Mont Belvieu JV, and Saddlehorn. Per - Bbl Adjusted gross margin for produced - water assets decreased by $0.11 for the year ended December 31, 2023, primarily due to a lower average fee resulting from a cost-of-service rate redetermination effective January 1, 2023, and lower deficiency fee revenues.

Long-lived asset and other impairment expense Long - lived asset and other impairment expense for the year ended December 31, 2022, was primarily due to a $19.9 million other-than-temporary impairment of our investment in White Cliffs. 75 Table of Contents Long - lived asset and other impairment expense for the year ended December 31, 2021, was primarily due to (i) $14.2 million of impairments at the DJ Basin complex due to cancellation of projects and (ii) an $11.8 million other-than-temporary impairment of our investment in Ranch Westex.

Long - lived asset and other impairment expense for the year ended December 31, 2022, was primarily due to a $19.9 million other-than-temporary impairment of our investment in White Cliffs.

The following table and discussion present a summary of our net cash flows provided by (used in) operating, investing, and financing activities: Year Ended December 31, thousands 2022 2021 2020 Net cash provided by (used in): Operating activities $ 1,701,426 $ 1,766,852 $ 1,637,418 Investing activities (218,237) (257,538) (448,254) Financing activities (1,398,532) (1,752,237) (844,204) Net increase (decrease) in cash and cash equivalents $ 84,657 $ (242,923) $ 344,960 Operating activities .

The following table and discussion present a summary of our net cash flows provided by (used in) operating, investing, and financing activities: Year Ended December 31, thousands 2023 2022 Net cash provided by (used in): Operating activities $ 1,661,334 $ 1,701,426 Investing activities (1,607,291) (218,237) Financing activities (67,912) (1,398,532) Net increase (decrease) in cash and cash equivalents $ (13,869) $ 84,657 Operating activities .

See Note 14—Leases in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Asset retirement obligations. When assets are acquired or constructed, the initial estimated asset retirement obligation is recognized in an amount equal to the net present value of the settlement obligation, with an associated increase in properties, plant, and equipment.

When assets are acquired or constructed, the initial estimated asset retirement obligation is recognized in an amount equal to the net present value of the settlement obligation, with an associated increase in property, plant, and equipment.

Property and other taxes decreased by $4.1 million for the year ended December 31, 2021, primarily due to ad valorem tax decreases at the West Texas complex due to realized tax savings during 2021, partially offset by ad valorem tax increases in the DJ Basin due to higher tax rates.

Property and other taxes Property and other taxes decreased by $22.1 million for the year ended December 31, 2023, primarily due to decreases in the ad valorem property tax accrual during 2023 related to the finalization of 2022 assessments at the DJ Basin complex.

Net income (loss) increased by $307.5 million for the year ended December 31, 2022, primarily due to (i) a $374.6 million increase in total revenues and other, (ii) a $103.6 million increase in gain (loss) on divestiture and other, net, and (iii) a $42.6 million decrease in interest expense.

Net income (loss) decreased by $203.4 million for the year ended December 31, 2023, primarily due to (i) a $145.2 million decrease in total revenues and other, (ii) a $113.8 million decrease in gain (loss) on divestiture and other, net, (iii) a $30.5 million decrease in equity income, net – related parties, and (iv) a $14.3 million increase in interest expense.

In November 2022, we sold our 15.00% interest in Cactus II to two third parties for $264.8 million, which includes a $1.8 million pro-rata distribution through closing.

For purposes of the discussion included in Results of Operations , the Powder River Basin complex includes our previously owned Hilight system and the assets acquired from Meritage. In November 2022, we sold our 15.00% interest in Cactus II to two third parties for $264.8 million, which includes a $1.8 million pro-rata distribution through closing.

Capital expenditures increased by $173.6 million for the year ended December 31, 2022, primarily due to increases of (i) $119.9 million at the West Texas complex, primarily attributable to facility expansion, including ongoing construction of Mentone Train III, and pipeline projects, (ii) $31.8 million at the DBM water systems due to construction of additional water - disposal wells and facilities and pipeline projects, and (iii) $17.3 million at the DBM oil system, primarily related to an increase in pipeline, oil treating, and oil pumping projects.

Capital expenditures increased by $247.9 million for the year ended December 31, 2023, primarily due to increases of (i) $130.4 million at the West Texas complex, primarily attributable to facility expansion, including ongoing construction of Mentone Train III and engineering and equipment milestone payments for the North Loving Plant, and pipeline projects, (ii) $55.0 million at the DBM water systems due to construction of additional water - disposal wells and facilities, pipeline build-out, and replacement projects, (iii) $39.0 million at the DBM oil system, primarily related to an increase in pipeline, oil treating, and oil pumping projects, (iv) $10.0 million related to the acquisition of Meritage, (v) $9.9 million at the DJ Basin oil system due to an increase in pipeline projects, and (vi) $8.3 million at the DJ Basin complex due to an increase in well connection and pipeline projects. 77 Table of Contents Historical cash flow .

Gross margin increased by $245.2 million for the year ended December 31, 2022, due to a $374.6 million increase in total revenues and other, partially offset by (i) a $98.6 million increase in cost of product and (ii) a $30.7 million increase in depreciation and amortization.

Gross margin increased by $92.8 million for the year ended December 31, 2023, due to a $256.3 million decrease in cost of product. This amount was offset partially by (i) a $145.2 million decrease in total revenues and other and (ii) an $18.3 million increase in depreciation and amortization. Net income (loss).

As of December 31, 2022, we had (i) $375.0 million of outstanding borrowings under the RCF that bear interest at a rate based on SOFR or an alternative base rate at WES Operating’s option, and (ii) the Floating - Rate Senior Notes (repaid in January 2023) that bear interest at a rate based on LIBOR.

As of December 31, 2023, WES Operating had (i) no outstanding borrowings under the RCF that bear interest at a rate based on the Secured Overnight Financing Rate (“SOFR”) or an alternative base rate at WES Operating’s option and (ii) $613.9 million of outstanding commercial paper borrowings.

This increase was offset partially by (i) decreased volumes at the Ranch Westex plant, which we acquired in the third quarter of 2022 and is included as part of the West Texas complex subsequent to the acquisition (see Acquisitions and Divestitures within this Item 7), and (ii) decreased volumes at the Rendezvous system due to production declines in the area.

These increases were offset partially by (i) lower volumes at the Granger complex and Marcellus Interest systems due to production declines in the surrounding areas, (ii) decreased volumes at the Ranch Westex plant, which we acquired in the third quarter of 2022 and is included as part of the West Texas complex subsequent to the acquisition, and (iii) lower volumes at the Mi Vida plant.

These increases were offset partially by decreases of (i) $31.7 million at the DJ Basin complex due to decreased throughput, partially offset by increased deficiency fees, and (ii) $4.9 million at the Springfield system primarily due to lower cumulative catch-up adjustments for changes in estimated consideration in 2022 compared to 2021.

These increases were partially offset by decreases of (i) $17.5 million at the Springfield system primarily due to decreased demand-fee revenue and a lower cumulative catch-up adjustment for changes in estimated consideration in 2023 as compared to 2022, partially offset by increased throughput, (ii) $12.5 million at the Brasada complex due to a change in contract terms effective July 1, 2023, and (iii) $12.1 million at the Chipeta complex due to decreased deficiency fees.

Additionally, we intend to continue to evaluate the crude - oil, NGLs, and natural - gas price environments and adjust our capital spending plans to reflect our customers’ anticipated activity levels, while maintaining appropriate liquidity and financial flexibility. Liquidity and access to capital markets.

To address the risks posed by fluctuating commodity prices, we intend to continue evaluating the relevant price environments and adjust our capital spending plans to reflect our customers’ anticipated activity levels, while maintaining appropriate liquidity and financial flexibility.

See Capital Expenditures and Historical Cash Flow within this Item 7 for further information. 83 Table of Contents GENERAL TRENDS AND OUTLOOK We expect our business to be affected by the below - described key trends and uncertainties. Our expectations are based on assumptions made by us and information currently available to us.

These amounts were offset partially by an $8.5 million decrease in contributions to equity investments. 73 Table of Contents See Capital Expenditures and Historical Cash Flow within this Item 7 for further information. GENERAL TRENDS AND OUTLOOK We expect our business to be affected by the below - described key trends and uncertainties.

See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 67 Table of Contents RESULTS OF OPERATIONS OPERATING RESULTS The following tables and discussion present a summary of our results of operations: Year Ended December 31, thousands 2022 2021 2020 Total revenues and other (1) $ 3,251,721 $ 2,877,155 $ 2,772,592 Equity income, net – related parties 183,483 204,645 226,750 Total operating expenses (1) 1,950,992 1,745,573 2,129,063 Gain (loss) on divestiture and other, net 103,676 44 8,634 Operating income (loss) 1,587,888 1,336,271 878,913 Interest income – Anadarko note receivable — — 11,736 Interest expense (333,939) (376,512) (380,058) Gain (loss) on early extinguishment of debt 91 (24,944) 11,234 Other income (expense), net 1,603 (623) 1,025 Income (loss) before income taxes 1,255,643 934,192 522,850 Income tax expense (benefit) 4,187 (9,807) 5,998 Net income (loss) 1,251,456 943,999 516,852 Net income (loss) attributable to noncontrolling interests 34,353 27,707 (10,160) Net income (loss) attributable to Western Midstream Partners, LP (2) $ 1,217,103 $ 916,292 $ 527,012 _________________________________________________________________________________________ (1) Total revenues and other includes amounts earned from services provided to related parties and from the sale of natural gas, condensate, and NGLs to related parties.

For a description of impairments recorded, see Note 9—Property, Plant, and Equipment and Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 61 Table of Contents RESULTS OF OPERATIONS OPERATING RESULTS The following tables and discussion present a summary of our results of operations: Year Ended December 31, thousands 2023 2022 Total revenues and other (1) $ 3,106,476 $ 3,251,721 Equity income, net – related parties 152,959 183,483 Total operating expenses (1) 1,869,770 1,950,992 Gain (loss) on divestiture and other, net (10,102) 103,676 Operating income (loss) 1,379,563 1,587,888 Interest expense (348,228) (333,939) Gain (loss) on early extinguishment of debt 15,378 91 Other income (expense), net 5,679 1,603 Income (loss) before income taxes 1,052,392 1,255,643 Income tax expense (benefit) 4,385 4,187 Net income (loss) 1,048,007 1,251,456 Net income (loss) attributable to noncontrolling interests 25,791 34,353 Net income (loss) attributable to Western Midstream Partners, LP (2) $ 1,022,216 $ 1,217,103 _________________________________________________________________________________________ (1) Total revenues and other includes amounts earned from services provided to related parties and from the sale of natural gas, condensate, and NGLs to related parties.

For the year ended December 31, 2023, we estimate that our total capital expenditures will be between $575.0 million to $675.0 million (accrual-based, includes equity investments, excludes capitalized interest, and excludes capital expenditures associated with the 25% third-party interest in Chipeta).

As of December 31, 2023, we had an authorized amount of $627.8 million remaining under the program. For the year ended December 31, 2024, capital expenditures are expected to range between $700.0 million to $850.0 million (accrual-based, includes equity investments, excludes capitalized interest, and excludes capital expenditures associated with the 25% third-party interest in Chipeta).

Crude-oil and NGLs assets Gathering, treating, and transportation throughput increased by 11 MBbls/d for the year ended December 31, 2022, primarily due to higher volumes at the DBM oil system resulting from increased production in the area, partially offset by lower volumes at the DJ Basin oil system resulting from production declines in the area.

Crude-oil and NGLs assets Total throughput attributable to WES for crude - oil and NGLs assets decreased by 24 MBbls/d for the year ended December 31, 2023, primarily due to (i) lower volumes on the Cactus II pipeline, which was sold in the fourth quarter of 2022, and (ii) lower volumes at the DJ Basin oil system resulting from production declines in the area.

See Note 10—Goodwill and Other Intangibles in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

See Note 8—Income Taxes in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 67 Table of Contents RECONCILIATION OF NON-GAAP FINANCIAL MEASURES Adjusted gross margin.

We may, from time to time, seek to retire, rearrange, or amend some or all of our outstanding debt or debt agreements through cash purchases, exchanges, open - market repurchases, privately negotiated transactions, tender offers, or otherwise. Such transactions, if any, will depend on prevailing market conditions, our liquidity position and requirements, contractual restrictions, and other factors.

Management continuously monitors our leverage position and other financial projections to manage the capital structure according to long-term objectives. We may, from time to time, seek to retire, rearrange, or amend some or all of our outstanding debt or financing agreements through cash purchases, exchanges, open - market repurchases, privately negotiated transactions, tender offers, or otherwise.

Overall, short- and long-term interest rates increased during 2021 and have continued to increase during 2022, resulting in increased interest expense on RCF borrowings and the Floating - Rate Senior Notes. Any future increases in interest rates likely will result in additional increases in financing costs.

Short- and long-term interest rates can be volatile resulting in immediate changes to interest expense on RCF borrowings, commercial paper borrowings, and other floating-rate debt securities. Any future increases in interest rates likely will result in additional increases in financing costs.

Other items decreased by $2.6 million for the year ended December 31, 2021, primarily due to a decrease of $25.4 million at the DJ Basin complex due to changes in imbalance positions, partially offset by increases of $16.1 million at the West Texas complex and $5.1 million at the Chipeta complex, primarily due to changes in imbalance positions.

Other items Other items decreased by $6.4 million for the year ended December 31, 2023, primarily due to decreases of (i) $11.5 million at the West Texas complex due to changes in imbalance positions, partially offset by higher offload costs, and (ii) $3.8 million and $2.9 million at the Red Desert complex and MIGC system, respectively, attributable to changes in imbalance positions.

NGLs sales increased by $99.8 million for the year ended December 31, 2021, primarily due to increases of (i) $73.8 million at the West Texas complex attributable to an increase in average prices, partially offset by a decrease in volumes sold, (ii) $22.3 million at the Chipeta complex and $11.3 million at the Granger complex attributable to increases in average prices, and (iii) $6.5 million at the DJ Basin complex attributable to an increase in average prices and volumes sold.

These decreases were partially offset by an increase of $7.7 million at the DJ Basin complex as a result of contract mix, partially offset by decreased volumes sold and average prices. 64 Table of Contents NGLs sales NGLs sales decreased by $165.5 million for the year ended December 31, 2023, primarily due to decreases of (i) $94.7 million at the West Texas complex due to changes in contract mix and decreased average prices, (ii) $22.9 million, $10.0 million, and $3.6 million at the Chipeta, Granger, and Red Desert complexes, respectively, due to decreased average prices and volumes sold, (iii) $22.9 million at the DJ Basin complex due to decreased average prices, partially offset by increased volumes sold, and (iv) $7.5 million at the Brasada complex due to a contract expiration in the third quarter of 2022.

These increases were offset partially by (i) lower cash operating income, (ii) lower distributions from equity-investment earnings, and (iii) lower interest income. Refer to Operating Results within this Item 7 for a discussion of our results of operations as compared to the prior periods. Investing activities .

Refer to Operating Results within this Item 7 for a discussion of our results of operations as compared to the prior periods. Investing activities .

Adjusted EBITDA decreased by $83.7 million for the year ended December 31, 2021, primarily due to (i) a $134.1 million increase in cost of product (net of lower of cost or market inventory adjustments), (ii) a $34.6 million increase in general and administrative expenses excluding non - cash equity - based compensation expense, and (iii) a $23.9 million decrease in distributions from equity investments.

Adjusted EBITDA decreased by $59.3 million for the year ended December 31, 2023, primarily due to (i) a $145.2 million decrease in total revenues and other, (ii) a $108.0 million increase in operation and maintenance expenses, (iii) a $55.8 million decrease in distributions from equity investments, and (iv) a $34.4 million increase in general and administrative expenses excluding non - cash equity - based compensation expense.

The cash distribution was paid on February 13, 2023, to our unitholders of record at the close of business on February 1, 2023.

The Board declared a cash distribution to unitholders for the fourth quarter of 2023 of $0.575 per unit, or $223.4 million in the aggregate. The cash distribution was paid on February 13, 2024, to our unitholders of record at the close of business on February 1, 2024.

In 2021, prices began to increase and in the first quarter of 2022, commodity prices increased significantly in connection with the war in Ukraine.

During 2020, oil and natural - gas prices were negatively impacted by the worldwide macroeconomic downturn that followed the global outbreak of COVID - 19. In 2021, prices began to increase and in the first quarter of 2022, commodity prices increased significantly in connection with the war in Ukraine.

For further information on Long - lived asset and other impairment expense, see Note 9—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.

See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Impairments. We recognized long-lived asset and other impairments of $52.9 million and $20.6 million for the years ended December 31, 2023 and 2022, respectively.

Capital expenditures associated with growth and maintenance projects is closely monitored. Rates of return are analyzed before capital projects are approved, spending is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approved.

Rates of return are analyzed before capital projects are approved, spending is closely monitored throughout the development of the project, and the subsequent operational performance is compared to the assumptions used in the economic analysis performed for the capital investment approved. 60 Table of Contents ITEMS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS Our historical results of operations and cash flows for the periods presented may not be comparable to future or historic results of operations or cash flows for the reasons described below.

In addition, the transition from LIBOR to SOFR as a result of reference rate reform is not expected to materially impact interest expense on our outstanding borrowings. Additional variable - rate debt may be issued in the future, either under the RCF or other financing sources, including commercial paper borrowings or debt issuances. 95 Table of Contents

Additional short-term or variable - rate debt may be issued in the future, either under the RCF or other financing sources, including commercial paper borrowings or debt issuances. 84 Table of Contents

Year Ended December 31, thousands except per-unit amounts 2022 2021 2020 Gross margin Gross margin for natural - gas assets (1) $ 1,676,732 $ 1,536,163 $ 1,537,075 Gross margin for crude - oil and NGLs assets (1) 346,406 287,391 354,784 Gross margin for produced - water assets (1) 245,274 197,821 213,834 Per - Mcf Gross margin for natural - gas assets (2) 1.05 0.98 0.95 Per - Bbl Gross margin for crude - oil and NGLs assets (2) 1.38 1.17 1.37 Per - Bbl Gross margin for produced - water assets (2) 0.79 0.76 0.82 Adjusted gross margin Adjusted gross margin for natural - gas assets $ 2,031,600 $ 1,882,726 $ 1,820,926 Adjusted gross margin for crude - oil and NGLs assets 607,769 547,134 647,390 Adjusted gross margin for produced - water assets 286,106 237,656 249,889 Per - Mcf Adjusted gross margin for natural - gas assets (3) 1.32 1.24 1.16 Per - Bbl Adjusted gross margin for crude - oil and NGLs assets (3) 2.46 2.28 2.54 Per - Bbl Adjusted gross margin for produced - water assets (3) 0.94 0.93 0.98 _________________________________________________________________________________________ (1) Excludes corporate-level depreciation and amortization.

Year Ended December 31, thousands except per-unit amounts 2023 2022 Gross margin Gross margin for natural - gas assets (1) $ 1,738,125 $ 1,676,732 Gross margin for crude - oil and NGLs assets (1) 368,444 346,406 Gross margin for produced - water assets (1) 259,541 245,274 Per - Mcf Gross margin for natural - gas assets (2) 1.04 1.05 Per - Bbl Gross margin for crude - oil and NGLs assets (2) 1.52 1.38 Per - Bbl Gross margin for produced - water assets (2) 0.69 0.79 Adjusted gross margin Adjusted gross margin for natural - gas assets $ 2,067,528 $ 2,031,600 Adjusted gross margin for crude - oil and NGLs assets 589,091 607,769 Adjusted gross margin for produced - water assets 307,228 286,106 Per - Mcf Adjusted gross margin for natural - gas assets (3) 1.28 1.32 Per - Bbl Adjusted gross margin for crude - oil and NGLs assets (3) 2.48 2.46 Per - Bbl Adjusted gross margin for produced - water assets (3) 0.83 0.94 _________________________________________________________________________________________ (1) Excludes corporate-level depreciation and amortization.

Our ability to generate cash flows is subject to a number of factors, some of which are beyond our control. Read Risk Factors under Part I, Item 1A of this Form 10-K. Working capital . Working capital is an indication of liquidity and potential needs for short - term funding.

Such transactions, if any, will depend on prevailing market conditions, our liquidity position and requirements, contractual restrictions, and other factors and the amounts involved may be material. Our ability to generate cash flows is subject to a number of factors, some of which are beyond our control. Read Risk Factors under Part I, Item 1A of this Form 10-K.

In December 2020, we entered into a five-year transportation contract, which became effective on January 1, 2021, with a volume commitment on the Red Bluff Express pipeline. As of December 31, 2022, we have estimated future minimum-volume-commitment fees of $3.7 million in 2023 and a total of $7.4 million in years thereafter. Offload commitments.

As of December 31, 2023, we have future minimum payments under offload agreements totaling $7.7 million for 2024 and a total of $3.4 million in years thereafter. Pipeline commitments. We have entered into transportation contracts with volume commitments on multiple pipelines through 2033.

Other items Other items decreased by $61.3 million for the year ended December 31, 2022, primarily due to decreases of $45.8 million and $21.0 million at the West Texas and DJ Basin complexes, respectively, attributable to changes in imbalance positions.

NGLs purchases NGLs purchases decreased by $109.3 million for the year ended December 31, 2023, primarily due to decreases of (i) $61.5 million and $30.7 million at the West Texas and DJ Basin complexes, respectively, attributable to lower average prices and (ii) $7.7 million at the Brasada complex due to a contract expiration in the third quarter of 2022.

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Top changes in Western Midstream Partners, LP's 2023 10-K

Item 1A. Risk Factors

Item 3. Legal Proceedings

Item 5. Market for Registrant's Common Equity

Item 7. Management's Discussion & Analysis

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Other WES 10-K year-over-year comparisons