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What changed in Western Midstream Partners, LP's 10-K — 2023 vs 2024

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Paragraph-level year-over-year comparison of Western Midstream Partners, LP's 2023 and 2024 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 2024 report.

+217 added−236 removedSource: 10-K (2025-02-26) vs 10-K (2024-02-21)

Top changes in Western Midstream Partners, LP's 2024 10-K

217 paragraphs added · 236 removed · 189 edited across 6 sections

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

51 edited+2 added−16 removed192 unchanged
Biggest changeOur 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.
Biggest changeAs a result of these conflicts of interest, our general partner may favor the interests of Occidental or its owners or affiliates over the interest of our unitholders. 37 Table of Contents 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.
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.
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; 35 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.
For example, our partnership agreement: • provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity; • provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith, meaning that it believed that the decision was in the best interest of the Partnership; • provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and • provides that, in the absence of bad faith, our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.
For example, our partnership agreement: • provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity; 46 Table of Contents • provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith, meaning that it believed that the decision was in the best interest of the Partnership; • provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and • provides that, in the absence of bad faith, our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.
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.
In such a case, the common units’ trading price could decline, and you could lose part or all of your investment. 36 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.
While Occidental and other third-party producers have dedicated production from certain of its properties to us, we have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems, or the rate at which production declines.
While Occidental and other third-party producers have dedicated production from certain of their properties to us, we have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems, or the rate at which production declines.
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, WES Operating currently has $2.7 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.
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.
Our profitability may be negatively impacted by inflation in the cost of labor, materials, and services. Although inflation in the United States has declined since 2023, the prices of key inputs to the midstream industry have continued to be significantly impacted by inflation relative to historical levels.
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.
In addition to U.S. federal income taxes, our unitholders are subject to other taxes, including foreign, state, and local taxes; unincorporated business taxes; and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions.
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.
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.
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.
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.
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.
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.
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.
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.
Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our gathering, processing, and treating assets. Because of these factors, producers (including Occidental) may be deterred from developing known oil and natural-gas reserves existing in areas served by our assets.
Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our gathering, processing, and treating assets. 38 Table of Contents Because of these factors, producers (including Occidental) may be deterred from developing known oil and natural-gas reserves existing in areas served by our assets.
The construction of additions or modifications to our existing systems and the construction of new midstream assets involve numerous regulatory, environmental, political, and legal uncertainties that are beyond our control. These uncertainties also could affect downstream assets, which we do not own or control, but which are critical to certain of our growth projects.
The construction of additions or modifications to our existing systems and the construction of new midstream assets involve 44 Table of Contents numerous regulatory, environmental, political, and legal uncertainties that are beyond our control. These uncertainties also could affect downstream assets, which we do not own or control, but which are critical to certain of our growth projects.
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.
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.
The legal requirements related to the disposal of produced water into producing or non-producing geologic formation by means of underground injection wells are subject to change based on concerns of the public or governmental authorities, including concerns relating to recent seismic events near injection wells used for the disposal of produced water.
Additionally, the legal requirements related to the disposal of produced water into producing or non-producing geologic formations by means of underground injection wells are subject to change based on concerns of the public or governmental authorities, including concerns relating to recent seismic events near injection wells used for the disposal of produced water.
For example, the gathering, processing, treating, and transportation of natural gas from our gathering systems, processing facilities, and pipelines are dependent on communications among our facilities and with third-party systems that may be delivering natural gas into or receiving natural gas and other products from our facilities.
For example, the gathering, processing, treating, and transportation of natural gas from our gathering systems, processing facilities, and pipelines are dependent on communications among our facilities and with third-party systems that may be delivering 41 Table of Contents natural gas into or receiving natural gas and other products from our facilities.
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.
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 42 Table of Contents could cause our revenues to decline and operating expenses to increase.
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.
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.
The loss of a portion or all of these customers’ contracted volumes, as a result of competition, creditworthiness, inability to negotiate extensions, replacements of contracts, or otherwise, could reduce our ability to make cash distributions to our unitholders.
The loss of a portion or all of these customers’ contracted volumes, as a result of competition, creditworthiness, inability to negotiate extensions, replacements of contracts, or otherwise, could reduce our ability to make cash distributions to our 39 Table of Contents unitholders.
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”).
Tax-exempt entities should consult a tax advisor before investing in our units. 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”).
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.
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.
The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business.
The limitations on 47 Table of Contents the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business.
These developments could result in additional regulation and restrictions on our use of injection wells to dispose of produced water, including a possible shut down of wells, which could have a material adverse effect on our business, financial condition, and results of operations.
These operational and regulatory developments could result in restrictions on our use of injection wells to dispose of produced water, including a possible shut down of wells, which could have a material adverse effect on our business, financial condition, and results of operations.
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.
Moreover, Occidental and other third-party producers may not develop the acreage they have dedicated to us. If competition or reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, it could reduce our revenue and impair our ability to make cash distributions to our unitholders.
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.
For the year ended December 31, 2024, 60% of Total revenues and other, 34% of our throughput for natural-gas assets (excluding equity-investment throughput), 91% 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.
Adoption of new or more stringent legal standards relating to induced seismic activity associated with produced-water disposal could affect our operations. We dispose of produced water generated from oil and natural-gas production operations.
Physical injection constraints and the adoption of new or more stringent legal standards relating to induced seismic activity could affect our produced-water disposal operations. We dispose of produced water generated from oil and natural-gas production operations.
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.
Occidental’s shelf registration statement currently allows for the offer and sale of approximately 10.8 million common units, or 2.8% of our common units as of December 31, 2024, from time to time.
As a result, sustained lower natural-gas and crude-oil prices could have a material adverse effect on our business, results of operations, financial condition, and our ability to pay cash distributions to our unitholders.
Such declines also potentially affect the ability of our vendors, suppliers, and customers to continue operations. As a result, sustained lower natural-gas and crude-oil prices could have a material adverse effect on our business, results of operations, financial condition, and our ability to pay cash distributions to our unitholders.
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.
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.
For example, Occidental is not prohibited from owning assets or engaging in businesses that directly or indirectly compete with us. Any future credit-rating downgrade could negatively impact our cost of and ability to access capital.
Additional conflicts also may arise in the future associated with future business opportunities that are pursued by Occidental and us. For example, Occidental is not prohibited from owning assets or engaging in businesses that directly or indirectly compete with us. Any future credit-rating downgrade could negatively impact our cost of and ability to access capital.
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.
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 adversely impact our ability to make cash distributions to our 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.
Although we cannot predict any future inflation trends or the impact of current or future import tariffs, higher operating and capital costs 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.
Sustained low natural-gas, NGLs, or oil prices impact natural-gas and oil exploration and production activity levels and can result in a decline in the production of hydrocarbons over the medium to long term, resulting in reduced throughput on our systems. Such declines also potentially affect the ability of our vendors, suppliers, and customers to continue operations.
Sustained low natural-gas, NGLs, or oil prices and volatility of such prices could adversely affect our business. Sustained low natural-gas, NGLs, or oil prices impact natural-gas and oil exploration and production activity levels and can result in a decline in the production of hydrocarbons over the medium to long term, resulting in reduced throughput on our systems.
We may be required to post collateral in the form of letters of credit or cash as financial assurance of our performance under certain contractual arrangements, such as pipeline transportation contracts and NGLs and gas-sales contracts.
We may be required to post collateral in the form of letters of credit or cash as financial assurance of our performance under certain contractual arrangements, such as pipeline transportation contracts and NGLs and gas-sales contracts. At December 31, 2024, there were no letters of credit or cash-provided assurance of our performance under contractual arrangements with credit-risk-related contingent features.
To the extent that PHMSA and/or state regulatory agencies are successful in asserting their jurisdiction in this manner, midstream operators of NGLs fractionation facilities and associated storage facilities may be required to make operational changes or modifications at their facilities to meet standards beyond current OSHA and EPA requirements, where such changes or modifications may result in additional capital costs, possible operational delays, and increased costs of operation that, in some instances, may be significant.
To the extent that PHMSA and/or state regulatory agencies are successful in asserting their jurisdiction in this manner, midstream operators of NGLs fractionation facilities and associated storage facilities may be required to make operational changes or modifications at their facilities to meet standards beyond current OSHA and EPA requirements, where such changes or modifications may result in additional capital costs, possible operational delays, and increased costs of operation that, in some instances, may be significant. 43 Table of Contents Some portions of our pipeline systems have been in service for several decades, and we have a limited ownership history with respect to certain of our assets.
As a result of these activities, natural-gas gathering may begin to receive greater regulatory scrutiny at the state and federal levels. FERC makes jurisdictional determinations for natural-gas gathering and liquids lines on a case-by-case basis. The classification and regulation of our pipelines are subject to change based on future determinations by FERC, the courts, or Congress.
FERC makes jurisdictional determinations for natural-gas gathering and liquids lines on a case-by-case basis. The classification and regulation of our pipelines are subject to change based on future determinations by FERC, the courts, or Congress.
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.
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 380,556,643 common units outstanding as of December 31, 2024. Occidental currently holds 165,681,578 common units, representing 43.5% of our outstanding common units.
Any loss of rights with respect to our real property, through our inability to renew existing rights-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial position, and ability to make cash distributions to our unitholders.
Any loss of rights with respect to our real property, through our inability to renew existing rights-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial position, and ability to make cash distributions to our unitholders. 45 Table of Contents Our business involves many hazards and operational risks, some of which may not be fully covered by insurance.
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.
To pay the announced fourth-quarter 2024 distribution of $0.87500 per unit per quarter, or $3.50000 per unit per year, we require per-quarter available cash of $341.0 million, or $1,364.0 million per year, based on the number of common units outstanding at February 3, 2025.
Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not fully insured, our operations and financial results could be adversely affected.
If a significant accident or event occurs for which we are not fully insured, our operations and financial results could be adversely affected.
We are subject to increased scrutiny from institutional investors with respect to our governance structure and the social cost of our industry, which may adversely impact our ability to raise capital from such investors.
In 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.
Moreover, the costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.
Any contest with the IRS 48 Table of Contents may materially and adversely impact the market for our common units and the price at which they trade. Moreover, the costs of any contest with the IRS will result in a reduction in cash available for distribution to our unitholders and thus will be borne indirectly by our unitholders.
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.
The distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of ongoing litigation and, over time, FERC policy concerning which activities it regulates and which activities are excluded from its regulation has changed. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation.
Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person.
Accordingly, distributions to a non-U.S. unitholder will be subject to a combined withholding tax rate equal to the sum of the highest applicable effective tax rate and 10%. 49 Table of Contents Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person.
Furthermore, our indebtedness and related debt-service costs could impair our ability to obtain additional financing, reduce funds available for operations and business opportunities, make us more vulnerable to competitive pressures or market downturns, and limit our financial and operational flexibility.
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. 40 Table of Contents Furthermore, our indebtedness and related debt-service costs could impair our ability to obtain additional financing, reduce funds available for operations and business opportunities, make us more vulnerable to competitive pressures or market downturns, and limit our financial and operational flexibility.
In general terms, the prices of natural gas, oil, condensate, NGLs, and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty, and a variety of additional factors that are beyond our control. For example, during 2020, oil and natural-gas prices were negatively impacted by the worldwide macroeconomic downturn that followed the global outbreak of COVID-19.
In general terms, the prices of natural gas, oil, condensate, NGLs, and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty, and a variety of additional factors that are beyond our control that could negatively impact our and our customers’ financial outlooks and activity levels.
It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take, and a court may not agree with some or all of those positions. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade.
It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take, and a court may not agree with some or all of those positions.
Therefore, our general partner’s duties to us may conflict with the duties of its officers and directors to Occidental. As a result of these conflicts of interest, our general partner may favor the interests of Occidental or its owners or affiliates over the interest of our unitholders.
Therefore, our general partner’s duties to us may conflict with the duties of its officers and directors to Occidental.
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.
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. Additionally, the Trump administration has recently implemented a 10% tariff on Chinese imports and announced a 25% tariff on imports of steel and aluminum.
State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. In recent years, FERC has regulated the gas-gathering activities of interstate pipeline transmission companies more lightly, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates.
In recent years, FERC has regulated the gas-gathering activities of interstate pipeline transmission companies more lightly, which has resulted in a number of such companies transferring gathering facilities to unregulated affiliates. As a result of these activities, natural-gas gathering may begin to receive greater regulatory scrutiny at the state and federal levels.
Removed
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.
Added
Plans by the Trump administration to impose additional import tariffs on Canada and Mexico are also currently under consideration, as are reciprocal tariffs on all U.S. trading partners that currently impose tariffs on American goods. These and other import tariffs could substantially increase our operating and capital costs.
Removed
Although commodity prices have recovered from those lows, they remain subject to volatility that could negatively impact our and our customers’ financial outlooks and activity levels.
Added
In some instances, operational constraints (e.g., increased wellbore pressures or poor reservoir quality) have limited water injectivity in our areas of operation that have resulted in available injection capacity being lower than our permitted capacity.
Removed
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. 41 Table of Contents On April 16, 2019, Senate Bill 19-181 was signed into law in Colorado.
Removed
This legislation reforms oversight of oil and natural-gas exploration and production activities in the state.
Removed
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.
Removed
The new legislation also authorizes Colorado cities and counties to assume an increased role in regulating oil and natural-gas operations within their jurisdictions in a manner that may be more stringent than state-level rules.
Removed
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.
Removed
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
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.
Removed
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.
Removed
Some portions of our pipeline systems have been in service for several decades, and we have a limited ownership history with respect to certain of our assets.
Removed
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
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
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
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, distributions to a non-U.S. unitholder will be subject to a combined withholding tax rate equal to the sum of the highest applicable effective tax rate and 10%.

Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

2 edited+0 added−0 removed5 unchanged
Biggest changeFor more information on our cybersecurity related risks, see Risk Factors under Part I, Item 1A of this Form 10-K. 53 Table of Contents
Biggest changeFor more information on our cybersecurity related risks, see Risk Factors under Part I, Item 1A of this Form 10-K.
Our CISO has 15 years of experience as a chief information security officer, over four decades of experience in the energy industry, a degree in computer science, and manages a team at WES that is responsible for leading enterprise-wide cybersecurity strategy, policy, standards, architecture, governance, and risk management.
Our CISO has 16 years of experience as a chief information security officer, over four decades of experience in the energy industry, a degree in computer science, and manages a team at WES that is responsible for leading enterprise-wide cybersecurity strategy, policy, standards, architecture, governance, and risk management.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

1 edited+1 added−5 removed1 unchanged
Biggest changeExcept as discussed above, we are not a party to any legal, regulatory, or administrative proceedings other than proceedings arising in the ordinary course of business.
Biggest changeWe are not a party to any legal, regulatory, or administrative proceedings other than proceedings arising in the ordinary course of business.
Removed
Item 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”).
Added
Item 3. Legal Proceedings We have elected to use a $1.0 million threshold for disclosing certain proceedings arising under federal, state, or local environmental laws when a government authority is a party and potential monetary sanctions are involved. We believe proceedings under this threshold are not material to our business and financial proceedings.
Removed
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
Separately, on November 22, 2022, WGR filed suit against Enterprise in the District Court of Harris County, Texas (the “Whitethorn Lawsuit”).
Removed
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
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.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

6 edited+0 added−0 removed6 unchanged
Biggest changeIn November 2022, the Board authorized an increase in the program to $1.25 billion.
Biggest changeIn November 2022, the Board authorized an increase in the program to $1.25 billion. The $1.25 billion Purchase Program expired as of December 31, 2024.
The 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.
The 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 2024: 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, 2024 — $ — — $ 627,807,310 November 1-30, 2024 — — — 627,807,310 December 1-31, 2024 — — — 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. 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.
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. 52 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, 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
As of December 31, 2024, 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. 53 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 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.
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 21, 2025, there were 26 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 1,226,875 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.
The 2017 LTIP and the 2021 LTIP permit the issuance of up to 3,431,251 and 9,500,000 units, respectively, of which 322,228 and 8,385,682 units, respectively, remained available for future issuance as of December 31, 2024. 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

14 edited+2 added−4 removed7 unchanged
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.
Biggest changeThe following table provides additional information on throughput for the periods presented below: Year Ended December 31, 2024 2023 Inc/ (Dec) Throughput for natural-gas assets (MMcf/d) Delaware Basin 1,871 1,635 14 % DJ Basin 1,436 1,322 9 % Powder River Basin 456 120 NM Equity investments 517 466 11 % Other 946 1,050 (10) % Total throughput for natural - gas assets 5,226 4,593 14 % Throughput for crude-oil and NGLs assets (MBbls/d) Delaware Basin 243 214 14 % DJ Basin 92 71 30 % Powder River Basin 25 5 NM Equity investments 144 333 (57) % Other 37 42 (12) % Total throughput for crude - oil and NGLs assets 541 665 (19) % Throughput for produced-water assets (MBbls/d) Delaware Basin 1,147 1,029 11 % Total throughput for produced - water assets 1,147 1,029 11 % _________________________________________________________________________________________ NM — Not meaningful 55 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.
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).
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, 2024 (see Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
We also gather and dispose of produced water. We operate in Texas, New Mexico, Colorado, Utah, Wyoming, and North-central Pennsylvania, with a substantial portion of our business concentrated in West Texas and the Rocky Mountains.
We also gather and dispose of produced water. We operate in Texas, New Mexico, Colorado, Utah, and Wyoming, with a substantial portion of our business concentrated in West Texas and the Rocky Mountains.
This type of contract provides us with a relatively stable revenue stream that is not subject to direct commodity-price risk, except to the extent that (i) we retain and sell drip condensate that is recovered during the gathering of natural gas from the wellhead or production facilities or (ii) actual recoveries differ from contractual recoveries under certain of our processing agreements.
This type of contract provides us with a relatively stable revenue stream that is not subject to direct commodity-price risk, except to the extent that (i) actual recoveries differ from contractual recoveries under certain of our processing agreements or (ii) we retain and sell drip condensate that is recovered during the gathering of natural gas from the wellhead or production facilities and skim oil that is recovered during the produced-water gathering and disposal process.
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.
Discussion of 2022 items and comparison of the year ended December 31, 2023, to the year ended December 31, 2022, 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, 2023, as filed with the SEC on February 21, 2024, and is available via the SEC’s website at www.sec.gov and our website at www.westernmidstream.com.
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, and the Rocky Mountains (Colorado, Utah, and Wyoming).
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.
For the year ended December 31, 2024, 60% of Total revenues and other, 34% of our throughput for natural-gas assets (excluding equity-investment throughput), 91% 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.
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.
For example, for the year ended December 31, 2024, our West Texas and DJ Basin assets provided (i) 53% and 32%, respectively, of Total revenues and other, (ii) 40% and 31%, respectively, of our throughput for natural-gas assets (excluding equity-investment throughput), (iii) 61% and 23%, respectively, of our throughput for crude-oil and NGLs assets (excluding equity-investment throughput), and (iv) all of our throughput for produced-water assets.
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.
As of December 31, 2024, our assets and investments consisted of the following: Wholly Owned and Operated Operated Interests Equity Interests Gathering systems (1) 18 2 1 Treating facilities 42 3 — Natural - gas processing plants/trains 26 3 1 NGLs pipelines 3 — 4 Natural - gas pipelines 6 — 1 Crude - oil pipelines 2 1 1 _________________________________________________________________________________________ (1) Includes the DBM water systems.
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.
For the year ended December 31, 2024, 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.
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.
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.
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.
See Acquisitions and Divestitures within this Item 7 for additional information. • WES Operating completed the public offering of $800.0 million in aggregate principal amount of 5.450% Senior Notes due 2034.
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.
Net proceeds from the offering will be used to repay a portion of certain senior notes due in 2025 and for general partnership purposes, including the funding of capital expenditures.
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.
See Liquidity and Capital Resources within this Item 2 for additional information. • WES Operating purchased and retired $150.0 million of certain of its senior notes via open-market repurchases. 54 Table of Contents • Our regular fourth - quarter 2024 per - unit distribution is unchanged from the third-quarter 2024 per-unit distribution of $0.875. • Natural - gas throughput attributable to WES totaled 5,052 MMcf/d for the year ended December 31, 2024, representing a 14% increase compared to year ended December 31, 2023. • Crude - oil and NGLs throughput attributable to WES totaled 530 MBbls/d for the year ended December 31, 2024, representing a 19% decrease compared to the year ended December 31, 2023. • Produced - water throughput attributable to WES totaled 1,124 MBbls/d for the year ended December 31, 2024, representing an 11% increase compared to the year ended December 31, 2023. • Gross margin was $2.8 billion for the year ended December 31, 2024, representing a 19% increase compared to the year ended December 31, 2023.
Removed
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).
Added
Significant financial and operational events during the year ended December 31, 2024, included the following: • We closed on the sale of (i) our 33.75% interest in the Marcellus Interest systems for proceeds of $206.2 million and (ii) several equity investments to third parties for combined proceeds of $588.6 million, which included $5.9 million in pro-rata distributions through closing.
Removed
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 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 $1.30 per Mcf for the year ended December 31, 2024, representing a 2% increase compared to the year ended December 31, 2023. • 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 $2.94 per Bbl for the year ended December 31, 2024, representing a 19% increase compared to the year ended December 31, 2023. • Adjusted Gross Margin for produced - water assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7) averaged $0.96 per Bbl for the year ended December 31, 2024, representing a 16% increase compared to the year ended December 31, 2023.
Removed
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.
Removed
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.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

115 edited+23 added−22 removed69 unchanged
Biggest changeProduced-water assets Total throughput attributable to WES for produced - water assets increased by 173 MBbls/d for the year ended December 31, 2023, due to higher production and new third-party connections brought online during 2023. 63 Table of Contents Service Revenues Year Ended December 31, thousands except percentages 2023 2022 Inc/ (Dec) Service revenues – fee based $ 2,768,757 $ 2,602,053 6 % Service revenues – product based 191,727 249,692 (23) % Total service revenues $ 2,960,484 $ 2,851,745 4 % Service revenues – fee based Service revenues – fee based increased by $166.7 million for the year ended December 31, 2023, primarily due to increases of (i) $114.1 million at the West Texas complex as a result of increased throughput and electricity-related rates billed to customers, (ii) $42.6 million at the Powder River Basin complex as a result of increased throughput attributable to the acquisition of Meritage (see Items Affecting the Comparability of Our Financial Results—Acquisitions and divestitures within this Item 7), (iii) $22.7 million at the DJ Basin complex due to increased deficiency fees on demand volumes and electricity-related rates billed to customers, (iv) $20.8 million and $12.1 million at the DBM water and DBM oil systems, respectively, due to increased throughput, partially offset by decreased deficiency fees, and (v) $5.6 million at the DJ Basin oil system primarily due to a higher cumulative catch-up adjustment for changes in estimated consideration in 2023 compared to 2022, partially offset by decreased throughput and deficiency fees.
Biggest changeProduced-water assets Total throughput attributable to WES for produced - water assets increased by 115 MBbls/d for the year ended December 31, 2024, due to higher production, partially offset by increased recycling activities in the upstream operations of our producers. 59 Table of Contents Service Revenues Year Ended December 31, thousands except percentages 2024 2023 Inc/ (Dec) Service revenues – fee based $ 3,248,262 $ 2,768,757 17 % Service revenues – product based 215,776 191,727 13 % Total service revenues $ 3,464,038 $ 2,960,484 17 % Service revenues – fee based Service revenues – fee based increased by $479.5 million for the year ended December 31, 2024, primarily due to increases of (i) $184.0 million at the West Texas complex due to increased throughput, a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2024, and increased deficiency fees on certain contracts with increasing throughput minimums, (ii) $140.2 million at the Powder River Basin complex attributable to the acquisition of Meritage, (iii) $89.8 million at the DJ Basin complex primarily due to increased throughput and increased electricity-related rates billed to customers, partially offset by a decrease in deficiency fees, (iv) $87.5 million and $36.7 million at the DBM water and DBM oil systems, respectively, as a result of increased throughput and higher average fees resulting from cost-of-service rate redeterminations effective January 1, 2024, and (v) $6.7 million at the Chipeta complex primarily due to new and amended contracts effective July 2024.
Throughput is a significant operating variable that we use to assess our ability to generate revenues. To maintain or increase throughput on our systems, we must connect to additional wells or production facilities.
Throughput . Throughput is a significant operating variable that we use to assess our ability to generate revenues. To maintain or increase throughput on our systems, we must connect to additional wells or production facilities.
Impairment analyses for long-lived assets, goodwill, equity investments, and the initial recognition of asset retirement obligations use Level-3 inputs. Management also estimates the fair value of assets and liabilities acquired in a third-party business combination or exchanged in non-monetary transactions.
Fair value. Impairment analyses for long-lived assets, goodwill, equity investments, and the initial recognition of asset retirement obligations use Level-3 inputs. Management also estimates the fair value of assets and liabilities acquired in a third-party business combination or exchanged in non-monetary transactions.
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.
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 other; and • $39.1 million of distributions received from equity investments in excess of cumulative earnings.
Property, plant, and equipment and other intangible assets are stated at historical cost less accumulated depreciation or amortization, or fair value if impaired. Prior long-lived asset acquisitions from Anadarko were transfers of net assets between entities under common control; therefore, the assets acquired were initially recorded at Anadarko’s historic carrying value.
Property, plant, and equipment and other intangible assets are stated at historical cost less accumulated depreciation or amortization, or fair value if impaired. Prior long-lived asset acquisitions from Anadarko were transfers of net assets between entities under common control; therefore, the assets acquired were initially recorded at Anadarko’s historical carrying value.
Net cash used in financing activities for the year ended December 31, 2023, primarily included the following: • $1,495.0 million of repayments of outstanding borrowings under the RCF; • $1,008.9 million of distributions paid to WES unitholders and noncontrolling interest owners; • $259.8 million to purchase and retire portions of certain of WES Operating’s senior notes via open-market repurchases; • $213.1 million to redeem the total principal amount outstanding on the Floating-Rate Senior Notes due 2023 at par value; 78 Table of Contents • $134.6 million of unit repurchases; • $1,120.0 million of borrowings under the RCF, which were used for general partnership purposes; • $740.6 million of net proceeds from the 6.150% Senior Notes due 2033 issued in April 2023, which were used to repay borrowings under the RCF and for general partnership purposes; • $609.9 million of net borrowings under the commercial paper program, which were used for general partnership purposes; and • $592.8 million of net proceeds from the 6.350% Senior Notes due 2029 issued in September 2023, which 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.
Net cash used in financing activities for the year ended December 31, 2023, primarily included the following: • $1,495.0 million of repayments of outstanding borrowings under the RCF; • $1,008.9 million of distributions paid to WES unitholders and noncontrolling interest owners; • $259.8 million to purchase and retire portions of certain of WES Operating’s senior notes via open-market repurchases; • $213.1 million to redeem the total principal amount outstanding on the Floating-Rate Senior Notes due 2023 at par value; • $134.6 million of unit repurchases; • $1,120.0 million of borrowings under the RCF, which were used for general partnership purposes; • $740.6 million of net proceeds from the 6.150% Senior Notes due 2033 issued in April 2023, which were used to repay borrowings under the RCF and for general partnership purposes; • $609.9 million of net borrowings under the commercial paper program, which were used for general partnership purposes; and • $592.8 million of net proceeds from the 6.350% Senior Notes due 2029 issued in September 2023, which 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.
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.
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. 79 Table of Contents Impairments of equity investments.
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.
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. 77 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. 81 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. 78 Table of Contents Noncontrolling interest. WES Operating’s noncontrolling interest consists of the 25% third - party interest in Chipeta.
Although Free cash flow is the metric used to assess WES’s ability to make distributions to unitholders, this measure should not be viewed as indicative of the actual amount of cash that is available for distributions or planned for distributions for a given period.
Although Free Cash Flow is the metric used to assess our ability to make distributions to unitholders, this measure should not be viewed as indicative of the actual amount of cash that is available for distributions or planned for distributions for a given period.
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.
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 operating leases for equipment supporting our operations, corporate offices, field offices, and easements, with both Occidental and third parties as lessors.
Certain of the gathering agreements for the West Texas complex, Springfield system, DJ Basin oil system, Marcellus Interest systems, and DBM oil and water systems allow for rate resets that target an agreed-upon rate of return over the life of the agreement.
Certain of the gathering agreements for the West Texas complex, Springfield system, DJ Basin oil system, and DBM oil and water systems allow for rate resets that target an agreed-upon rate of return over the life of the agreement.
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.
For the year ended December 31, 2024, 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.
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.
While a 10% change in the applicable benchmark interest rate would not materially impact interest expense on our outstanding borrowings at December 31, 2024, it would impact the fair value of the senior notes.
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
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. 81 Table of Contents
Refer to Operating Results within this Item 7 for a discussion of the components of Gross margin as compared to the prior periods, including Service Revenue s, Product Sales , Cost of Product (Residue purchases, NGLs purchases, and Other items), and Other Operating Expenses (Depreciation and amortization expense).
Refer to Operating Results within this Item 7 for a discussion of the components of Gross margin as compared to the prior periods, including Service Revenue s, Product Sales , Cost of Product (Natural-gas purchases, NGLs purchases, and Other items), and Other Operating Expenses (Depreciation and amortization expense).
If we require funding beyond our sources of liquidity and are either unable to access the capital markets or find alternative sources of capital at reasonable costs, our strategy may become more challenging to execute. Changes in regulations.
If we require funding beyond our sources of liquidity and are either unable to access the capital markets or find alternative sources of capital at reasonable costs, our strategy may become more challenging to execute. 71 Table of Contents Changes in regulations.
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.
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 four times for the federal funds rate in 2023 and decreased its target range three times during the year ended December 31, 2024.
Our success in maintaining or increasing throughput is impacted by the successful drilling of new wells by producers that are dedicated to our systems, recompletions of existing wells connected to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage, and our ability to attract natural-gas, crude-oil, NGLs, or produced-water volumes currently serviced by our competitors.
Our success in maintaining or increasing throughput is impacted by the successful drilling of new wells by producers that are dedicated to our systems, recompletions of existing wells connected to our systems, our ability to secure volumes from new wells drilled on non-dedicated acreage, and our ability to attract natural-gas, crude-oil, NGLs, or produced-water volumes currently serviced by our competitors. 56 Table of Contents Operating and maintenance expenses.
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.
As of December 31, 2024, 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) no outstanding commercial paper borrowings.
Additionally, even when the commodity-price environments are favorable, our customers must manage numerous operational challenges, including severe weather disruptions, downstream and produced-water takeaway constraints, seismicity concerns, new regulatory requirements, and the ability to optimize the efficiency and results of large, complex drilling programs.
Additionally, even when the commodity-price environments are favorable, our customers must manage numerous operational challenges, including severe weather disruptions, oil and gas takeaway constraints, produced water recycling and disposal limitations, seismicity concerns, new regulatory requirements, and the ability to optimize the efficiency and results of large, complex drilling programs.
For additional information on our senior notes, RCF, and commercial paper program, see Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 79 Table of Contents Finance lease liabilities. WES has finance leases with third parties for equipment, vehicles, and an NGL pipeline in Wyoming.
For additional information on our senior notes, RCF, and commercial paper program, see Note 13—Debt and Interest Expense in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 76 Table of Contents Finance lease liabilities. We have finance leases with third parties for equipment, vehicles, and an NGLs pipeline in Wyoming.
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.
As of December 31, 2024, we have future operating-lease payments of $60.5 million in 2025 and a total of $173.7 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 offload agreements with third parties providing firm-processing capacity through 2025.
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. 74 Table of Contents Impact of inflation and supply-chain disruptions.
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.
For purposes of the following discussion, any increases or decreases “for the year ended December 31, 2023” refer to the comparison of the year ended December 31, 2023, to the year ended December 31, 2022.
For purposes of the following discussion, any increases or decreases “for the year ended December 31, 2024” refer to the comparison of the year ended December 31, 2024, to the year ended December 31, 2023.
Debt and credit facilities. As of December 31, 2023, the carrying value of outstanding debt was $7.9 billion and we have estimated future interest and RCF fee payments totaling $346.3 million in 2024.
Debt and credit facilities. As of December 31, 2024, the carrying value of outstanding debt was $7.9 billion and we have estimated future interest and RCF fee payments totaling $385.1 million in 2025.
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.
Instead, Free Cash Flow represents the amount of cash that is available in aggregate for distributions, debt repayments, and other general partnership purposes. 65 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.
Natural-gas assets Total throughput attributable to WES for natural - gas assets increased by 222 MMcf/d for the year ended December 31, 2023, primarily due to (i) higher volumes at the West Texas complex due to increased production in the area, (ii) higher volumes at the Powder River Basin complex as a result of the Meritage acquisition, (iii) higher volumes at the Springfield gas-gathering system due to new third-party production, (iv) higher volumes on the Red Bluff Express pipeline due to the addition of a new receipt point into the pipeline, and (v) higher volumes at the MIGC system.
Natural-gas assets Total throughput attributable to WES for natural - gas assets increased by 620 MMcf/d for the year ended December 31, 2024, primarily due to (i) higher volumes at the Powder River Basin complex due to the Meritage acquisition, (ii) higher volumes at the West Texas and DJ Basin complexes due to increased production in the areas, (iii) higher volumes at the Red Bluff Express pipeline due to the addition of a new receipt point into the pipeline, and (iv) higher volumes at the Springfield gas-gathering system due to new third-party production.
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.
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, 2024, we expect to incur asset retirement costs of $12.8 million in 2025 and a total of $370.2 million in years thereafter.
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.
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.
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 .
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 2024 2023 Reconciliation of Gross margin to Adjusted Gross Margin Total revenues and other $ 3,605,223 $ 3,106,476 Less: Cost of product 172,251 164,598 Depreciation and amortization 650,428 600,668 Gross margin 2,782,544 2,341,210 Add: Distributions from equity investments 142,236 194,273 Depreciation and amortization 650,428 600,668 Less: Reimbursed electricity-related charges recorded as revenues 117,906 102,109 Adjusted Gross Margin attributable to noncontrolling interests (1) 80,509 70,195 Adjusted Gross Margin $ 3,376,793 $ 2,963,847 _________________________________________________________________________________________ (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. 66 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 .
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.
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.
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.
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.
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.
The differences between net income (loss) attributable to WES and WES Operating are reconciled as follows: Year Ended December 31, thousands 2024 2023 2022 Net income (loss) attributable to WES $ 1,573,571 $ 1,022,216 $ 1,217,103 Limited partner interest in WES Operating not held by WES (1) 32,156 20,922 24,899 General and administrative expenses (2) 1,875 2,943 2,656 Other income (expense), net (252) (275) (45) Income taxes 8 6 7 Net income (loss) attributable to WES Operating $ 1,607,358 $ 1,045,812 $ 1,244,620 _________________________________________________________________________________________ (1) Represents the portion of net income (loss) allocated to the limited partner interest in WES Operating not held by WES.
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 . 62 Table of Contents Throughput Year Ended December 31, 2023 2022 Inc/ (Dec) Throughput for natural-gas assets (MMcf/d) Gathering, treating, and transportation 435 409 6 % Processing 3,692 3,474 6 % Equity investments (1) 466 483 (4) % Total throughput 4,593 4,366 5 % Throughput attributable to noncontrolling interests (2) 161 156 3 % Total throughput attributable to WES for natural - gas assets 4,432 4,210 5 % Throughput for crude-oil and NGLs assets (MBbls/d) Gathering, treating, and transportation 332 317 5 % Equity investments (1) 333 373 (11) % Total throughput 665 690 (4) % Throughput attributable to noncontrolling interests (2) 13 14 (7) % Total throughput attributable to WES for crude - oil and NGLs assets 652 676 (4) % Throughput for produced-water assets (MBbls/d) Gathering and disposal 1,029 853 21 % Throughput attributable to noncontrolling interests (2) 20 17 18 % Total throughput attributable to WES for produced - water assets 1,009 836 21 % _________________________________________________________________________________________ (1) Represents our share of average throughput for investments accounted for under the equity method of accounting.
Discussion of 2022 items and comparison of the year ended December 31, 2023, to the year ended December 31, 2022, 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, 2023, and is available via the SEC’s website at www.sec.gov and our website at www.westernmidstream.com . 58 Table of Contents Throughput Year Ended December 31, 2024 2023 Inc/ (Dec) Throughput for natural-gas assets (MMcf/d) Gathering, treating, and transportation 453 435 4 % Processing 4,256 3,692 15 % Equity investments (1) 517 466 11 % Total throughput 5,226 4,593 14 % Throughput attributable to noncontrolling interests (2) 174 161 8 % Total throughput attributable to WES for natural - gas assets 5,052 4,432 14 % Throughput for crude-oil and NGLs assets (MBbls/d) Gathering, treating, and transportation 397 332 20 % Equity investments (1) 144 333 (57) % Total throughput 541 665 (19) % Throughput attributable to noncontrolling interests (2) 11 13 (15) % Total throughput attributable to WES for crude - oil and NGLs assets 530 652 (19) % Throughput for produced-water assets (MBbls/d) Gathering and disposal 1,147 1,029 11 % Throughput attributable to noncontrolling interests (2) 23 20 15 % Total throughput attributable to WES for produced - water assets 1,124 1,009 11 % _________________________________________________________________________________________ (1) Represents our share of average throughput for investments accounted for under the equity method of accounting.
For further information on Long - lived asset and other impairment expense, 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. 66 Table of Contents Interest Expense Year Ended December 31, thousands except percentages 2023 2022 Inc/ (Dec) Long - term and short - term debt $ (348,393) $ (326,949) 7 % Finance lease liabilities (1,083) (414) 162 % Commitment fees and amortization of debt-related costs (12,395) (12,212) 1 % Capitalized interest 13,643 5,636 142 % Interest expense $ (348,228) $ (333,939) 4 % Interest expense increased by $14.3 million for the year ended December 31, 2023, primarily due to increases of (i) $34.7 million of interest incurred on the 6.150% Senior Notes due 2033 that were issued during the second quarter of 2023, (ii) $10.0 million of interest incurred on the 6.350% Senior Notes due 2029 that were issued during the third quarter of 2023, and (iii) $3.0 million primarily due to borrowings on the commercial paper program that was established during the fourth quarter of 2023.
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. 63 Table of Contents Interest Expense Year Ended December 31, thousands except percentages 2024 2023 Inc/ (Dec) Long - term and short - term debt $ (377,850) $ (348,393) 8 % Finance lease liabilities (2,573) (1,083) 138 % Commitment fees and amortization of debt-related costs (13,305) (12,395) 7 % Capitalized interest 15,215 13,643 12 % Interest expense $ (378,513) $ (348,228) 9 % Interest expense increased by $30.3 million for the year ended December 31, 2024, primarily due to increases of (i) $29.3 million of interest incurred on the 6.350% Senior Notes due 2029 that were issued during the third quarter of 2023, (ii) $16.1 million of interest incurred on the 5.450% Senior Notes due 2034 that were issued during the third quarter of 2024, (iii) $12.1 million of interest incurred on the 6.150% Senior Notes due 2033 that were issued during the second quarter of 2023, and (iv) $2.7 million due to borrowings in 2024 on the commercial paper program that was established during the fourth quarter of 2023.
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.
The New York Mercantile Exchange (“NYMEX”) West Texas Intermediate crude - oil daily settlement prices during 2023 ranged from a low of $66.74 per barrel in March 2023 to a high of $93.68 per barrel in September 2023, and prices during the year ended December 31, 2024, ranged from a low of $65.75 per barrel in September 2024 to a high of $86.91 per barrel in April 2024.
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.
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. 69 Table of Contents KEY PERFORMANCE METRICS Year Ended December 31, thousands except percentages and per-unit amounts 2024 2023 Inc/ (Dec) Adjusted Gross Margin $ 3,376,793 $ 2,963,847 14 % Per - Mcf Adjusted Gross Margin for natural - gas assets (1) 1.30 1.28 2 % Per - Bbl Adjusted Gross Margin for crude - oil and NGLs assets (1) 2.94 2.48 19 % Per - Bbl Adjusted Gross Margin for produced - water assets (1) 0.96 0.83 16 % Adjusted EBITDA 2,344,038 2,068,633 13 % Free cash flow 1,324,164 964,205 37 % _________________________________________________________________________________________ (1) Average for period.
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.
The Board declared a cash distribution to unitholders for the fourth quarter of 2024 of $0.875 per unit, or $341.0 million in the aggregate. The cash distribution was paid on February 14, 2025, to our unitholders of record at the close of business on February 3, 2025.
See Risk Factors under Part I, Item 1A of this Form 10-K. Acquisitions and divestitures. In October 2023, we closed on the acquisition of Meritage for $885.0 million (subject to certain customary post-closing adjustments) funded with cash, including proceeds from our $600.0 million senior note issuance in September 2023 and borrowings on the RCF.
In October 2023, we closed on the acquisition of Meritage for $885.0 million (subject to certain customary post-closing adjustments) funded with cash, including proceeds from our $600.0 million senior note issuance in September 2023 and borrowings on the RCF.
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.
The extent and duration of commodity - price volatility, and the associated direct and indirect impact on our business, cannot be predicted. 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.
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.
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 2024 2023 2022 WES net cash provided by operating activities $ 2,136,860 $ 1,661,334 $ 1,701,426 General and administrative expenses (1) 1,875 2,943 2,656 Non - cash equity - based compensation expense (581) (581) (570) Changes in working capital (29,198) (15,226) (9,341) Other income (expense), net (252) (275) (45) Income taxes 8 6 7 WES Operating net cash provided by operating activities $ 2,108,712 $ 1,648,201 $ 1,694,133 WES net cash provided by (used in) financing activities $ (1,280,015) $ (67,912) $ (1,398,532) Distributions to WES unitholders (2) 1,246,069 978,430 735,755 Distributions to WES from WES Operating (3) (1,246,702) (1,119,367) (1,219,635) Increase (decrease) in outstanding checks 50 (52) 103 Unit repurchases — 134,602 487,590 Other 27,316 15,472 9,326 WES Operating net cash provided by (used in) financing activities $ (1,253,282) $ (58,827) $ (1,385,393) _________________________________________________________________________________________ (1) Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating.
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.
Acquisitions for the year ended December 31, 2023, included the acquisition of Meritage. See Items Affecting the Comparability of Our Financial Results within this Item 7.
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).
Gross margin increased by $441.3 million for the year ended December 31, 2024, primarily due to a $498.7 million increase in total revenues and other. This increase was offset partially by (i) a $49.8 million increase in depreciation and amortization and (ii) a $7.7 million increase in cost of product. Net income (loss).
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 a description of impairments recorded, see Note 9—Property, Plant, and Equipment in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 57 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 2024 2023 Total revenues and other (1) $ 3,605,223 $ 3,106,476 Equity income, net – related parties 112,385 152,959 Total operating expenses (1) 2,043,647 1,869,770 Gain (loss) on divestiture and other, net 296,771 (10,102) Operating income (loss) 1,970,732 1,379,563 Interest expense (378,513) (348,228) Gain (loss) on early extinguishment of debt 5,403 15,378 Other income (expense), net 31,741 5,679 Income (loss) before income taxes 1,629,363 1,052,392 Income tax expense (benefit) 18,111 4,385 Net income (loss) 1,611,252 1,048,007 Net income (loss) attributable to noncontrolling interests 37,681 25,791 Net income (loss) attributable to Western Midstream Partners, LP (2) $ 1,573,571 $ 1,022,216 _________________________________________________________________________________________ (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.
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.
Our sources of liquidity, as of December 31, 2024, included cash and cash equivalents, cash flows generated from operations, effective borrowing capacity under the RCF, our commercial paper program, and potential issuances of additional equity or debt securities.
Other Income (Expense), Net Year Ended December 31, thousands except percentages 2023 2022 Inc/ (Dec) Other income (expense), net $ 5,679 $ 1,603 NM Other income (expense), net increased by $4.1 million for the year ended December 31, 2023, primarily due to interest income earned resulting from higher interest rates and cash and cash equivalent balances throughout 2023, partially offset by interest recorded in 2023 related to a sales tax audit.
Other Income (Expense), Net Year Ended December 31, thousands except percentages 2024 2023 Inc/ (Dec) Other income (expense), net $ 31,741 $ 5,679 NM Other income (expense), net increased by $26.1 million for the year ended December 31, 2024, primarily due to interest income earned resulting from higher cash and cash equivalent balances throughout 2024.
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.
Acquisitions and capital expenditures as presented in the consolidated statements of cash flows and capital incurred were as follows: Year Ended December 31, thousands 2024 2023 Acquisitions $ 443 $ 877,746 Capital expenditures (1) 833,856 735,080 Capital incurred (1) 798,330 752,338 _________________________________________________________________________________________ (1) The years ended December 31, 2024 and 2023, included $15.2 million and $13.6 million, respectively, of capitalized interest.
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.
As of December 31, 2024, we have future minimum payments under offload agreements totaling $3.4 million for 2025. Pipeline commitments. We have transportation contracts with volume commitments on multiple pipelines through 2035. As of December 31, 2024, we have estimated future minimum-volume-commitment fees totaling $15.0 million in 2025 and a total of $50.6 million in years thereafter. Credit risk .
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, 2023, 2022, and 2021. Fair value.
We recognized long-lived asset and other impairments of $6.2 million and $52.9 million for the years ended December 31, 2024 and 2023, respectively. 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 periods presented.
As of December 31, 2023, we have future finance-lease payments of $7.7 million for 2024 and a total of $35.0 million in years thereafter. Asset retirement obligations.
As of December 31, 2024, we have future finance-lease payments of $11.5 million in 2025 and a total of $27.4 million in years thereafter. Asset retirement obligations.
Calculated 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.
Calculated 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. 67 Table of Contents Year Ended December 31, thousands 2024 2023 Reconciliation of Net income (loss) to Adjusted EBITDA Net income (loss) $ 1,611,252 $ 1,048,007 Add: Distributions from equity investments 142,236 194,273 Non - cash equity - based compensation expense 37,994 32,005 Interest expense 378,513 348,228 Income tax expense 18,111 4,385 Depreciation and amortization 650,428 600,668 Impairments 6,206 52,884 Other expense 248 1,739 Less: Gain (loss) on divestiture and other, net 296,771 (10,102) Gain (loss) on early extinguishment of debt 5,403 15,378 Equity income, net – related parties 112,385 152,959 Other income 31,741 6,976 Adjusted EBITDA attributable to noncontrolling interests (1) 54,650 48,345 Adjusted EBITDA $ 2,344,038 $ 2,068,633 Reconciliation of Net cash provided by operating activities to Adjusted EBITDA Net cash provided by operating activities $ 2,136,860 $ 1,661,334 Interest (income) expense, net 378,513 348,228 Accretion and amortization of long - term obligations, net (9,238) (8,151) Current income tax expense (benefit) 3,900 3,341 Other (income) expense, net (31,741) (5,679) Distributions from equity investments in excess of cumulative earnings – related parties 30,850 39,104 Changes in assets and liabilities: Accounts receivable, net 42,798 78,346 Accounts and imbalance payables and accrued liabilities, net 21,935 68,019 Other items, net (175,189) (67,564) Adjusted EBITDA attributable to noncontrolling interests (1) (54,650) (48,345) Adjusted EBITDA $ 2,344,038 $ 2,068,633 Cash flow information Net cash provided by operating activities $ 2,136,860 $ 1,661,334 Net cash provided by (used in) investing activities (39,168) (1,607,291) Net cash provided by (used in) financing activities (1,280,015) (67,912) _________________________________________________________________________________________ (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. 68 Table of Contents Year Ended December 31, thousands 2024 2023 Reconciliation of Net cash provided by operating activities to Free Cash Flow Net cash provided by operating activities $ 2,136,860 $ 1,661,334 Less: Capital expenditures 833,856 735,080 Contributions to equity investments – related parties 9,690 1,153 Add: Distributions from equity investments in excess of cumulative earnings – related parties 30,850 39,104 Free Cash Flow $ 1,324,164 $ 964,205 Cash flow information Net cash provided by operating activities $ 2,136,860 $ 1,661,334 Net cash provided by (used in) investing activities (39,168) (1,607,291) Net cash provided by (used in) financing activities (1,280,015) (67,912) Gross margin.
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 .
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 2024 2023 Net cash provided by (used in): Operating activities $ 2,136,860 $ 1,661,334 Investing activities (39,168) (1,607,291) Financing activities (1,280,015) (67,912) Net increase (decrease) in cash and cash equivalents $ 817,677 $ (13,869) Operating activities .
These decreases were offset partially by (i) increased volumes on the Whitethorn and Saddlehorn pipelines, (ii) higher volumes at the DBM oil system resulting from increased production in the area, and (iii) higher volumes on the Thunder Creek NGL pipeline which was acquired as part of the Meritage acquisition.
These decreases were offset partially by (i) higher volumes at the DBM and DJ Basin oil systems due to increased production in the areas and (ii) higher volumes at the Thunder Creek NGL pipeline, which was acquired as part of the Meritage acquisition.
Depreciation and amortization expense Depreciation and amortization expense increased by $18.3 million for the year ended December 31, 2023, primarily due to increases of (i) $10.1 million and $7.3 million at the West Texas complex and DBM water systems, respectively, primarily related to capital projects being placed into service, (ii) $9.9 million at the Powder River Basin complex associated with the acquisition of Meritage, and (iii) $7.2 million related to depreciation for capitalized information technology implementation costs.
Depreciation and amortization expense Depreciation and amortization expense increased by $49.8 million for the year ended December 31, 2024, primarily due to increases of (i) $44.7 million at the Powder River Basin complex primarily attributable to the acquisition of Meritage and (ii) $22.5 million and $7.2 million at the West Texas complex and DBM water systems, respectively, primarily related to capital projects being placed into service.
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.
Free Cash Flow increased by $360.0 million for the year ended December 31, 2024, primarily due to a $475.5 million increase in net cash provided by operating activities, partially offset by (i) a $98.8 million increase in capital expenditures, (ii) an $8.5 million increase in contributions to equity investments, and (iii) an $8.3 million decrease in distributions from equity investments in excess of cumulative earnings.
As with other yield-oriented securities, our unit price could be impacted by our implied distribution yield relative to market interest rates.
Any future increases in interest rates likely will result in additional increases in financing costs. As with other yield-oriented securities, our unit price could be impacted by our implied distribution yield relative to market interest rates.
However, we expect our cost of capital to remain competitive, as our competitors face similar interest-rate dynamics. Acquisition opportunities. We may pursue certain asset acquisitions where such acquisitions complement our existing asset base or allow us to capture operational efficiencies. However, if we do not make additional acquisitions on an economically accretive basis, our future growth could be limited.
However, we expect our cost of capital to remain competitive, as our peers face similar interest-rate dynamics. Acquisition opportunities. We may pursue certain asset acquisitions where such acquisitions complement our existing asset base or allow us to capture operational efficiencies.
These metrics are significant factors in assessing our operating results and profitability and include (i) throughput, (ii) operating and maintenance expenses, (iii) general and administrative expenses, (iv) capital expenditures, and (v) the following non-GAAP financial measures: Adjusted gross margin, Adjusted EBITDA, and Free cash flow (see Reconciliation of Non-GAAP Financial Measures within this Item 7). Throughput .
HOW WE EVALUATE OUR OPERATIONS Our management relies on certain metrics to analyze our financial and operational results, including (i) throughput, (ii) operating and maintenance expenses, (iii) general and administrative expenses, (iv) capital expenditures, and (v) the following non-GAAP financial measures: Adjusted Gross Margin, Adjusted EBITDA, and Free Cash Flow (see Reconciliation of Non-GAAP Financial Measures within this Item 7).
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.
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.
To assess the appropriateness of our general and administrative expenses and maximize our cash available for distribution, we monitor such expenses by way of comparison to prior periods and to the annual budget. Capital expenditures . Our business is capital intensive, requiring significant investment to maintain and improve existing facilities or to develop new midstream infrastructure.
General and administrative expenses . To assess the appropriateness of our general and administrative expenses and maximize our cash available for distribution, we monitor such expenses by way of comparison to prior periods, the annual budget, and other companies in the midstream industry. Capital expenditures .
Operating and maintenance expenses include, among other things, field labor, chemical and treating services, maintenance and integrity management costs, utility costs, equipment rentals, regulatory compliance, environmental remediation, land-related costs, insurance, and contract services. General and administrative expenses .
We monitor operating and maintenance expenses to assess the impact of these costs on asset profitability and to evaluate the overall efficiency of our operations. Operating and maintenance expenses include, among other things, field labor, chemical and treating services, maintenance and integrity management costs, utility costs, equipment rentals, regulatory compliance, environmental remediation, land-related costs, insurance, and contract services.
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.
Year Ended December 31, thousands except per-unit amounts 2024 2023 Gross margin Gross margin for natural - gas assets (1) $ 2,073,533 $ 1,738,125 Gross margin for crude - oil and NGLs assets (1) 395,886 368,444 Gross margin for produced - water assets (1) 341,784 259,541 Per - Mcf Gross margin for natural - gas assets (2) 1.08 1.04 Per - Bbl Gross margin for crude - oil and NGLs assets (2) 2.00 1.52 Per - Bbl Gross margin for produced - water assets (2) 0.81 0.69 Adjusted Gross Margin Adjusted Gross Margin for natural - gas assets $ 2,411,438 $ 2,067,528 Adjusted Gross Margin for crude - oil and NGLs assets 570,476 589,091 Adjusted Gross Margin for produced - water assets 394,879 307,228 Per - Mcf Adjusted Gross Margin for natural - gas assets (3) 1.30 1.28 Per - Bbl Adjusted Gross Margin for crude - oil and NGLs assets (3) 2.94 2.48 Per - Bbl Adjusted Gross Margin for produced - water assets (3) 0.96 0.83 _________________________________________________________________________________________ (1) Excludes corporate-level depreciation and amortization.
These increases were offset partially by a decrease of $13.0 million at the DJ Basin complex primarily due to acceleration of depreciation expense during 2022. Long-lived asset and other impairment expense Long - lived asset and other impairment expense for the year ended December 31, 2023, was primarily due to a $52.1 million impairment for assets located in the Rockies.
Long - lived asset and other impairment expense for the year ended December 31, 2023, was primarily due to a $52.1 million impairment for assets located in the Rockies.
Adjusted gross margin increased by $38.4 million for the year ended December 31, 2023, primarily due to (i) increased throughput at the West Texas complex and DBM oil system, (ii) increased throughput at the Powder River Basin complex attributable to the acquisition of Meritage, and (iii) increased throughput, partially offset by decreased deficiency fees at the DBM water systems.
Adjusted Gross Margin increased by $412.9 million for the year ended December 31, 2024, primarily due to (i) increased throughput and a higher average fee resulting from cost-of-service rate redeterminations effective January 1, 2024, at the West Texas complex, DBM water systems, and DBM oil system, (ii) increased throughput at the Powder River Basin complex attributable to the acquisition of Meritage, and (iii) increased throughput at the DJ Basin complex.
In addition, we have no senior note borrowings due within the next year and, as of December 31, 2023, have $1.4 billion in effective borrowing capacity under WES Operating’s $2.0 billion RCF, after taking into account the $613.9 million of outstanding commercial paper borrowings, for which we maintain availability under the RCF as support for WES Operating’s commercial paper program.
In addition, we have $1.0 billion senior note borrowings due within the next year and, as of December 31, 2024, have $2.0 billion in effective borrowing capacity under WES Operating’s $2.0 billion RCF.
Fluctuating crude - oil, natural - gas, and NGLs prices can reduce the level of our customers’ activities and change the allocation of capital within their own asset portfolios. Such fluctuations can also impact us directly to the extent we take ownership of and sell certain volumes at the tailgate of our plants for our own account.
Such fluctuations can also impact us directly to the extent we take ownership of and sell certain volumes at the tailgate of our plants for our own account.
Net cash used in investing activities for the year ended December 31, 2022, primarily included the following: • $487.2 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; • $40.1 million of cash paid for the acquisition of the remaining 50% interest in Ranch Westex; • $9.6 million of capital contributions primarily paid to Red Bluff Express; • $9.5 million of increases to materials and supplies inventory; • $263.0 million in proceeds from the sale of our 15.00% interest in Cactus II; and • $63.9 million of distributions received from equity investments in excess of cumulative earnings.
Net cash used in investing activities for the year ended December 31, 2024, primarily included the following: • $833.9 million of capital expenditures, primarily related to expansion, construction, and asset - integrity projects at the West Texas complex, DBM water systems, DJ Basin complex, Powder River Basin complex, and DBM oil system; • $18.3 million of increases to materials and supplies inventory and other; • $582.7 million of proceeds related to the sale of several equity investments to third parties; • $206.2 million of proceeds related to the sale of our 33.75% interest in the Marcellus Interest systems to a third party; and • $30.9 million of distributions received from equity investments in excess of cumulative earnings.
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.
Other items Other items decreased by $11.5 million for the year ended December 31, 2024, primarily due to decreases of $32.5 million and $2.3 million at the West Texas and Chipeta complexes, respectively, due to changes in imbalance positions.
Refer to Operating Results within this Item 7 for a discussion of our results of operations as compared to the prior periods. Investing activities .
These increases were offset partially by lower distributions from equity-investment earnings and higher interest expense. Refer to Operating Results within this Item 7 for a discussion of our results of operations as compared to the prior periods. Investing activities .
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.
Per - Bbl Adjusted Gross Margin for produced - water assets increased by $0.13 for the year ended December 31, 2024, primarily due to higher throughput and a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2024. Adjusted EBITDA.
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. Impact of interest rates.
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. Impact of interest rates. Short- and long-term interest rates can be volatile, resulting in immediate changes to interest expense on RCF borrowings and commercial paper borrowings.
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.
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.
Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove incorrect, our actual results may vary materially from expected results. Impact of producer activity.
To the extent our underlying assumptions about, or interpretations of, available information prove incorrect, our actual results may vary materially from expected results. Impact of producer activity. Our business is primarily driven by the level of production of crude oil and natural gas by producers in our areas of operation.
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.
We recognized long-lived asset and other impairments of $6.2 million and $52.9 million for the years ended December 31, 2024 and 2023, respectively.
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.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk under Part II of this Form 10-K.
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 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. Our expectations are based on assumptions made by us and information currently available to us.
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.
Property and other taxes Property and other taxes increased by $6.2 million for the year ended December 31, 2024, primarily due to increases of (i) $2.4 million at the DJ Basin complex primarily due to a lower ad valorem property tax accrual recorded during 2023 related to the finalization of 2022 assessments, (ii) $2.3 million at the Powder River Basin complex due to the acquisition of Meritage, and (iii) $2.0 million due to higher property tax values from expansion in West Texas.
Our business is primarily driven by the level of production of crude oil and natural gas by producers in our areas of operation. This activity, however, can be impacted negatively by, among other things, commodity-price fluctuations and operational challenges.
This activity, however, can be impacted negatively by, among other things, commodity-price fluctuations and operational challenges. Fluctuating crude - oil, natural - gas, and NGLs prices can reduce the level of our customers’ activities and change the allocation of capital within their own asset portfolios.
Other Operating Expenses Year Ended December 31, thousands except percentages 2023 2022 Inc/ (Dec) General and administrative $ 232,632 $ 194,017 20 % Property and other taxes 56,458 78,559 (28) % Depreciation and amortization 600,668 582,365 3 % Long - lived asset and other impairments 52,884 20,585 157 % Total other operating expenses $ 942,642 $ 875,526 8 % General and administrative expenses General and administrative expenses increased by $38.6 million for the year ended December 31, 2023, primarily due to increases of (i) $16.2 million in personnel costs, including costs related to the acquisition of Meritage, (ii) $9.8 million in information technology costs, and (iii) $7.0 million in consulting and legal costs.
Operation and maintenance expense Including the impact of operating the assets acquired with Meritage, operation and maintenance expense increased by $118.0 million for the year ended December 31, 2024, primarily due to increases of (i) $38.5 million in salaries and wages costs, (ii) $25.1 million in equipment, materials, maintenance, and repair costs, (iii) $16.7 million in chemical and treating services, (iv) $10.2 million in land-related costs, (v) $9.0 million in equipment rental costs, (vi) $7.1 million in water-disposal costs, and (vii) $5.4 million in utility expense. 62 Table of Contents Other Operating Expenses Year Ended December 31, thousands except percentages 2024 2023 Inc/ (Dec) General and administrative $ 271,526 $ 232,632 17 % Property and other taxes 62,668 56,458 11 % Depreciation and amortization 650,428 600,668 8 % Long - lived asset and other impairments 6,206 52,884 (88) % Total other operating expenses $ 990,828 $ 942,642 5 % General and administrative expenses General and administrative expenses increased by $38.9 million for the year ended December 31, 2024, primarily due to increases of (i) $27.5 million in personnel costs, (ii) $10.5 million in information technology costs, and (iii) $7.0 million in other corporate-related expenses.

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