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Western Midstream Partners, LP

Western Midstream Partners, LPWESEarnings & Financial Report

NYSE · Utilities · Natural Gas Transmission

Sunoco LP is an American vehicle gasoline master limited partnership company organized under Delaware state law and headquartered in Dallas, Texas. Dating back to 1886, the company has transformed from a vertically integrated energy company to a distributor of fuels and operator of energy infrastructure. It was previously engaged in oil, natural gas exploration and production, refining, chemical manufacturing, and retail fuel sales, but divested these businesses.

What changed in Western Midstream Partners, LP's 10-K — 2024 vs 2025

Top changes in Western Midstream Partners, LP's 2025 10-K

189 paragraphs added · 203 removed · 162 edited across 5 sections

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

36 edited+6 added−2 removed207 unchanged
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.
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; 33 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, 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; 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.
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.
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.
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. 41 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 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.
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. 35 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.
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.
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, 2025, there were no letters of credit or cash-provided assurance of our performance under contractual arrangements with credit-risk-related contingent features.
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.
Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our gathering, processing, and treating assets. 36 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 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.
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 42 Table of Contents also could affect downstream assets, which we do not own or control, but which are critical to certain of our growth projects.
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.
For example, the 39 Table of Contents 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.
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.
A change in the jurisdictional characterization of some of our assets by federal, state, or local 40 Table of Contents 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 material reduction in Occidental’s production that is gathered, treated, processed, or transported by our assets would result in a material decline in our revenues and cash available for distribution. We rely on Occidental for over 50% of revenues related to the natural gas, crude oil, NGLs, and produced water that we gather, treat, process, transport, and/or dispose.
A material reduction in Occidental’s production that is gathered, treated, processed, or transported by our assets would result in a material decline in our revenues and cash available for distribution. We rely on Occidental for over 50% of revenues related to the natural gas, crude oil, NGLs, and produced water that we gather, transport, recycle, treat, supply, and/or dispose.
We are exposed to the credit risk of third-party customers, and any material non-payment or non-performance by these parties, including with respect to our gathering, processing, transportation, and disposal agreements, could reduce our ability to make distributions to our unitholders. Across our asset portfolio, we rely on third-party customers for a substantial amount of our revenues.
We are exposed to the credit risk of third-party customers, and any material non-payment or non-performance by these parties, including with respect to our gathering, processing, transportation, and disposal agreements, could reduce our ability to make distributions to our unitholders. 37 Table of Contents Across our asset portfolio, we rely on third-party customers for a substantial amount of our revenues.
As a result, distributions to non-U.S. unitholders will be reduced by withholding taxes at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.
As a result, distributions to non-U.S. unitholders will be reduced by withholding 47 Table of Contents taxes at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.
By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the above-described provisions. Furthermore, our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law.
By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the partnership agreement, including the above-described provisions. 44 Table of Contents Furthermore, our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law.
Accordingly, we are required to distribute a portion of Chipeta’s cash balances, which are included in the cash balances in our consolidated balance sheets, to the other Chipeta member. We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
Accordingly, we are required to distribute a portion of Chipeta’s cash balances, which are included in the cash balances in our consolidated balance sheets, to the other Chipeta member. 43 Table of Contents We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
Adoption of new or more stringent climate-change or other air-emissions legislation or regulations restricting emissions of GHGs or other air pollutants could negatively impact us, our producer customers, or downstream customers by increasing operating costs and reducing volumetric throughput on our systems due to reduced demand for the gathering, processing, compressing, treating, and transporting services we provide.
Adoption of new or more stringent climate-change or other air-emissions legislation or regulations restricting emissions of GHGs or other air pollutants could negatively impact us, our producer customers, or downstream customers by increasing operating costs and reducing volumetric throughput on our systems due to reduced demand for the gathering, processing, compressing, treating, transporting, supply, and produced-water disposal services we provide.
Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement.
Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from 45 Table of Contents the partnership agreement.
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.
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.
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.
In such a case, the common units’ trading price could decline, and you could lose part or all of your investment. 34 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, transport, recycle, treat, supply, and/or dispose.
Our unitholders likely will be required to file tax returns and pay taxes in some or all of these various jurisdictions, or be subject to penalties for failure to comply with those requirements.
Our unitholders likely will be required to file tax returns and pay taxes in some or all of these various jurisdictions, or be subject to penalties for failure to comply with those requirements. 48 Table of Contents
The operating and financial restrictions and covenants in the indentures governing our publicly traded notes, (collectively, the “Notes”), the RCF, and any future financing arrangements could restrict our ability to finance future operations or capital needs or to expand or pursue business activities associated with our subsidiaries and equity investments.
The operating and financial restrictions and covenants in the indentures governing our publicly traded notes, (collectively, the “Notes”), the RCF, and any future financing arrangements could restrict our ability to finance future operations or capital needs or to expand or pursue business activities associated with our subsidiaries and equity 38 Table of Contents investments.
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.
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.
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.
For example, WES Operating currently has $2.1 billion in total principal amount 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.
In addition, we may be unable to complete maintenance or repairs due to the unavailability of necessary materials as a result of supply chain disruptions (including those caused by geopolitical events, such as the Russian invasion of Ukraine), which may result in the suspension of operations of the impacted assets until such activities can be completed.
In addition, we may be unable to complete maintenance or repairs due to the unavailability of necessary materials as a result of supply chain disruptions (including those caused by domestic and international political events), which may result in the suspension of operations of the impacted assets until such activities can be completed.
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 the year ended December 31, 2025, and excluding the impact of equity investments, 60% of Total revenues and other, 36% of our throughput for natural-gas assets, 91% of our throughput for crude-oil and NGLs assets, and 61% of our throughput for produced-water assets were attributable to production owned or controlled by Occidental.
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.
To pay the announced fourth-quarter 2025 distribution of $0.91000 per unit per quarter, or $3.64000 per unit per year, we require per-quarter available cash of $379.7 million, or $1,518.8 million per year, based on the number of common units outstanding at February 2, 2026.
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.
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 408,141,366 common units outstanding as of December 31, 2025, with Occidental holding 165,681,578 common units, representing 40.6% 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. 45 Table of Contents Our business involves many hazards and operational risks, some of which may not be fully covered by insurance.
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.
If a significant accident or event occurs for which we are not fully insured, our operations and financial results could be adversely affected.
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.
In addition, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. We are subject to increased scrutiny from institutional investors with respect to our governance structure and the social cost of our industry, which may adversely impact our ability to raise capital from such investors.
We are subject to increased scrutiny from institutional investors with respect to our governance structure and the social cost of our industry, which may adversely impact our ability to raise capital from such investors.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
If the IRS were to contest the federal income tax positions we take, it may impact the market for our common units adversely, and the costs of any such contest would reduce the cash available for distribution to our unitholders.
You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units. 46 Table of Contents If the IRS were to contest the federal income tax positions we take, it may impact the market for our common units adversely, and the costs of any such contest would reduce the cash available for distribution to our unitholders.
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.
The Trump administration has also imposed and expanded so called ‘reciprocal’ tariffs on a wide range of United States trading partners with which the United States has sizable trade imbalances and has announced or threatened additional increases on imports from Canada, Mexico, and other key partners. These and other import tariffs could substantially increase our operating and capital costs.
Removed
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.
Added
Additionally, the Trump administration has increased tariffs on most Chinese imports under its renewed Section 301 and International Emergency Economic Powers Act authorities and has significantly increased national security-based tariffs on steel and aluminum imports, including raising the general tariff rate on most steel and aluminum products.
Removed
You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our common units.
Added
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.
Added
In addition, we could construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. We may fail to successfully combine our business with the assets and business of Aris, which could have an adverse impact on our future results. The Aris acquisition closed on October 15, 2025.
Added
The integration of these acquired assets involves 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.
Added
If any of the risks described above or other anticipated or unanticipated liabilities were to materialize, it could have an adverse effect on our business, financial condition, and results of operations.
Added
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

4 edited+1 added−0 removed3 unchanged
The CISO also leads WES’s Cybersecurity Council, which is a cross-functional internal team including members of WES senior management, that meets regularly to review current information-technology and cybersecurity issues and initiatives and to collaborate on key decisions. Additionally, the CISO provides quarterly reports to the Audit Committee of the Board of Directors.
The DCI also leads WES’s Cybersecurity Council, which is a cross-functional internal team, including members of WES senior management, that meets regularly to review current information-technology and cybersecurity issues and initiatives and to collaborate on key decisions. Additionally, the DCI provides quarterly reports to the Audit Committee of the Board of Directors.
In addition, in our continuing commitment to cybersecurity education and preparedness, we also engage with industry peers, vendors, intelligence organizations, and law enforcement communities to evaluate and enhance the effectiveness of our information security policies and procedures.
In addition, as part of our continuing commitment to cybersecurity education and preparedness, we actively engage with industry peers, vendors, intelligence organizations, and law enforcement communities to evaluate and enhance the effectiveness of our information security policies and procedures.
Item 1C. Cybersecurity Our cybersecurity program is designed to promote actions that protect our computer systems and networks, delivering safe, secure, and reliable operations. Our digital technology group is led by a dedicated Chief Information Security Officer (“CISO”).
Item 1C. Cybersecurity Our cybersecurity program is designed to promote actions that protect our computer systems and networks, delivering safe, secure, and reliable operations. Our information technology group is led by our Chief Information Officer (“CIO”).
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.
Our CIO has over 20 years of information security and project management experience and has previously served as the lead information technology officer to one publicly traded enterprise and the cybersecurity and infrastructure lead at a separate publicly traded enterprise, both in the energy industry. Reporting to our CIO is a Director of Cybersecurity and Infrastructure (“DCI”).
Added
Our DCI has over 20 years of information technology and cybersecurity experience and holds a Certified Information Systems Security Professional certification from the International Information System Security Certification Consortium, an internationally recognized association of cybersecurity professionals. This role oversees an enterprise-wide cybersecurity strategy, policy, standards, architecture, governance, and risk management, ensuring alignment with our overall information technology and infrastructure objectives.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

5 edited+0 added−1 removed6 unchanged
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.
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. 50 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, 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
As of December 31, 2025, our general partner owned a 2.2% 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. 51 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 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.
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 13, 2026, there were 94 unitholders of record of our common units. This number does not include unitholders whose units are held in trust by other entities.
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.
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 2025 Purchase Program during the fourth quarter of 2025: 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, 2025 — $ — — $ 250,000,000 November 1-30, 2025 — — — 250,000,000 December 1-31, 2025 — — — 250,000,000 Total — — — ______________________________________________________________________________________ (1) In 2025, the Board authorized WES to buy back up to $250.0 million of our common units through December 31, 2026.
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.
The 2017 LTIP and the 2021 LTIP permit the issuance of up to 3,431,251 and 14,403,998 units, respectively, of which 737,749 and 11,655,238 units, respectively, remained available for future issuance as of December 31, 2025. Read the information under Part III, Item 12 of this Form 10-K, which is incorporated by reference into this Item 5.
Removed
In 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.

Item 7. Management's Discussion & Analysis

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

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In our capacity as a natural - gas processor, we also buy and sell natural gas, NGLs, and condensate on behalf of ourselves and our customers under certain contracts. To provide superior midstream service, we focus on ensuring the reliability and performance of our systems, creating sustainable cost efficiencies, enhancing our safety culture, and protecting the environment.
In our capacity as a natural - gas processor, we also buy and sell residue, NGLs, and condensate on behalf of ourselves and our customers under certain contracts. To provide superior midstream service, we focus on ensuring the reliability and performance of our systems, creating sustainable cost efficiencies, enhancing our safety culture, and protecting the environment.
EXECUTIVE SUMMARY We are a midstream energy company organized as a publicly traded partnership, engaged in the business of gathering, compressing, treating, processing, and transporting natural gas; gathering, stabilizing, and transporting condensate, NGLs, and crude oil; and gathering and disposing of produced water.
EXECUTIVE SUMMARY We are a midstream energy company organized as a publicly traded partnership, engaged in the business of gathering, compressing, treating, processing, and transporting natural gas; gathering, stabilizing, and transporting condensate, NGLs, and crude oil; and gathering, transporting, recycling, treating, supplying, and disposing of produced water.
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.
Discussion of 2023 items, and comparison of the year ended December 31, 2024, to the year ended December 31, 2023, 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, 2024, as filed with the SEC on February 26, 2025, and is available via the SEC’s website at www.sec.gov and our website at www.westernmidstream.com.
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.
For the year ended December 31, 2025, and excluding the impact of equity investments, 97% of our wellhead natural-gas volume and 100% of our crude-oil and produced-water throughput were serviced under fee-based contracts under which fixed and variable fees are received based on the volume or thermal content of the natural gas and on the volume of NGLs, crude oil, and produced water we gather, process, treat, transport, or dispose.
We 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.
We also gather, transport, recycle, treat, supply, 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, New Mexico, and the Rocky Mountains.
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 the year ended December 31, 2025, and excluding the impact of equity investments, 60% of Total revenues and other, 36% of our throughput for natural-gas assets, 91% of our throughput for crude-oil and NGLs assets, and 61% of our throughput for produced-water assets were attributable to production owned or controlled by Occidental.
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.
For example, for the year ended December 31, 2025, and excluding the impact of equity investments, our West Texas / New Mexico and DJ Basin assets provided (i) 58% and 29%, respectively, of Total revenues and other, (ii) 42% and 30%, respectively, of our throughput for natural-gas assets, (iii) 61% and 23%, respectively, of our throughput for crude-oil and NGLs assets, and (iv) all of our throughput for produced-water assets.
In our operations, we contract with customers to provide midstream services focused on natural gas, NGLs, crude oil, and produced water. We gather natural gas from individual wells or production facilities located near our gathering systems, and the natural gas may be compressed and delivered to a processing plant, treating facility, or downstream pipeline, and ultimately to end users.
We gather natural gas from individual wells or production facilities located near our gathering systems, and the natural gas may be compressed and delivered to a processing plant, treating facility, or downstream pipeline, and ultimately to end users.
The 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 following table provides additional information on throughput for the periods presented below: Year Ended December 31, 2025 2024 Inc/ (Dec) Throughput for natural-gas assets (MMcf/d) Delaware Basin 2,042 1,871 9 % DJ Basin 1,470 1,436 2 % Powder River Basin 437 456 (4) % Equity investments 550 517 6 % Other 905 946 (4) % Total throughput for natural-gas assets 5,404 5,226 3 % Throughput for crude-oil and NGLs assets (MBbls/d) Delaware Basin 258 243 6 % DJ Basin 97 92 5 % Powder River Basin 27 25 8 % Equity investments 104 144 (28) % Other 38 37 3 % Total throughput for crude-oil and NGLs assets 524 541 (3) % Throughput for produced-water assets (MBbls/d) Delaware Basin 1,608 1,147 40 % Total throughput for produced-water assets 1,608 1,147 40 % 53 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, 2024 (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 98.1% partnership interest in WES Operating, as of December 31, 2025.
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.
As of December 31, 2025, our assets and investments consisted of the following: Wholly Owned and Operated Operated Interests Equity Interests Gathering systems 13 2 1 Treating facilities 43 3 — Processing plants/trains 27 3 1 Produced-water gathering, treating, recycling, and disposal systems 8 — — NGLs pipelines 3 — 4 Natural - gas pipelines 6 — 1 Crude - oil pipelines 2 1 1 Significant financial and operational events during the year ended December 31, 2025, included the following: • On October 15, 2025, we closed on the acquisition of Aris by merger in an equity-and-cash transaction.
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.
See Items Affecting the Comparability of Our Financial Results within this Item 7 for additional information. • WES Operating completed the public offerings of $1.2 billion in aggregate principal amount of Senior Notes.
We also own and control the entire non-economic general partner interest in WES Operating GP, and our general partner is owned by Occidental.
See Note 1—Summary of Significant Accounting Policies and Basis of Presentation and Note 7—Equity Investments in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. We also own and control the entire non-economic general partner interest in WES Operating GP, and our general partner is owned by Occidental.
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.
Net proceeds from these public offerings (i) will be used to repay the 4.650% Senior Notes due 2026, (ii) were used to repay amounts outstanding under its commercial paper program (including borrowings incurred to fund the cash consideration of the Aris acquisition), and (iii) will be used for general partnership purposes, including the funding of capital expenditures.
Removed
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.
Added
Amounts attributable to noncontrolling interests presented in this Item 7 consist of (i) the 25% third-party interest in Chipeta for all periods presented, and only for natural-gas assets for throughput attributable to WES, and (ii) the 1.9%, 2.0%, and 2.0% limited partner interest in WES Operating as of December 31, 2025, 2024, and 2023, respectively, owned by an Occidental subsidiary.
Removed
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.
Added
See Debt and Credit Facilities within this Item 7 for additional information. 52 Table of Contents • WES Operating retired the total principal amount outstanding of the 3.100% Senior Notes due 2025 at par value during the first quarter of 2025 and the 3.950% Senior Notes due 2025 at par value during the second quarter of 2025. • Our fourth-quarter 2025 per-unit distribution is unchanged from the third-quarter 2025 per-unit distribution of $0.910. • We completed the start-up of the North Loving plant in late-February 2025, increasing gas processing capacity at the West Texas complex by 250 MMcf/d to a total of 2,190 MMcf/d.
Removed
See Reconciliation of Non-GAAP Financial Measures within this Item 7. • Adjusted Gross Margin for natural - gas assets (as defined under the caption Reconciliation of Non-GAAP Financial Measures within this Item 7) averaged $1.30 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.
Added
In our operations, we contract with customers to provide midstream services focused on natural gas, NGLs, crude oil, produced water, and water solutions.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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In addition, certain of our natural-gas processing agreements provide our producer customers with the option to receive an actual or fixed amount of NGLs recoveries (or in some cases, the financial equivalent thereof). Our customers’ election, along with operational plant efficiency and commodity prices, could impact our profitability and cash flows.
In addition, certain of our natural-gas processing agreements provide our producer customers the option to receive an actual or fixed amount of NGLs recoveries (or in some cases, the financial equivalent thereof). Our customers’ election, along with operational plant efficiency and commodity prices, could impact our profitability and cash flows.
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.
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.
For examples of proposed regulations or other regulatory initiatives that could have a potentially material impact on us, see the Environmental Matters and Occupational Health and Safety Regulations section in Business and Properties under Part I, Items 1 and 2 of this Form 10-K. Impact of inflation.
For examples of proposed regulations or other regulatory initiatives that could have a potentially material impact on us, see the Environmental Matters and Occupational Health and Safety Regulations section in Business and Properties under Part I, Items 1 and 2 of this Form 10-K. Impact of inflation and tariffs.
Net cash provided by operating activities increased for the year ended December 31, 2024, primarily due to higher cash operating income and the impact of changes in assets and liabilities, including cash received on certain contracts for which revenue recognition is deferred (See Note 2—Revenue from Contracts with Customers in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K).
Net cash provided by operating activities increased for the year ended December 31, 2025, primarily due to the impact of changes in assets and liabilities, including cash received on certain contracts for which revenue recognition is deferred (See Note 2 — Revenue from Contracts with Customers in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K) and higher cash operating income.
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).
Refer to Operating Results within this Item 7 for a discussion of the components of Gross margin as compared to the prior periods, including Revenue s, Cost of Product (Natural-gas purchases, NGLs purchases, and Other items), and Other Operating Expenses (Depreciation and amortization expense).
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.
As of December 31, 2025, 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.
Annual adjustments are made to cost-of-service rates charged under these agreements, and for certain of them, a cumulative catch-up revenue adjustment related to services already provided may be recorded. 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.
Annual adjustments are made to cost-of-service rates charged under these agreements, and for certain of them, a cumulative catch-up revenue adjustment related to services already provided may be recorded. See Note 1—Summary of Significant Accounting Policies and Basis of Presentation and Note 18—Subsequent Event in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
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.
While a 10% change in the applicable benchmark interest rate would not materially impact interest expense on our outstanding borrowings at December 31, 2025, 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. 81 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. 76 Table of Contents
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.
To the extent our underlying assumptions about, or interpretations of, available information prove incorrect, our actual results may vary materially from expected results. 66 Table of Contents 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.
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.
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. Impairments of equity investments.
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.
Instead, Free Cash Flow represents the amount of cash that is available in aggregate for distributions, debt repayments, and other general partnership purposes. Adjusted Gross Margin, Adjusted EBITDA, and Free Cash Flow are not defined in GAAP. The GAAP measure that is most directly comparable to Adjusted Gross Margin is gross margin.
Our producers’ ability to mitigate or manage such challenges can have a significant impact on the volumes available for us to service in the short term. For this reason, we strive to work proactively with our customers whenever possible to provide high levels of reliability on our systems and help them meet these operational challenges as they arise.
Our producers’ ability to mitigate or manage such challenges can significantly impact the volumes available for us to service in the short term. For this reason, we strive to work proactively with our customers whenever possible to provide high levels of reliability on our systems and help them meet these operational challenges as they arise.
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.
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.
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. 80 Table of Contents Item 7A. Quantitative and Qualitative Disclosures About Market Risk Commodity-price risk.
RECENT ACCOUNTING DEVELOPMENTS See Note 1—Summary of Significant Accounting Policies and Basis of Presentation and Note 8—Income Taxes in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 75 Table of Contents Item 7A. Quantitative and Qualitative Disclosures About Market Risk Commodity-price risk.
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.
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. Noncontrolling interest. WES Operating’s noncontrolling interest consists of the 25% third - party interest in Chipeta. WES Operating distributions.
We define Adjusted EBITDA attributable to Western Midstream Partners, LP (“Adjusted EBITDA”) as net income (loss), plus (i) distributions from equity investments, (ii) non - cash equity - based compensation expense, (iii) interest expense, (iv) income tax expense, (v) depreciation and amortization, (vi) impairments, and (vii) other expense (including lower of cost or market inventory adjustments recorded in cost of product), less (i) gain (loss) on divestiture and other, net, (ii) gain (loss) on early extinguishment of debt, (iii) income from equity investments, (iv) interest income, (v) income tax benefit, (vi) other income, and (vii) the noncontrolling interest owners’ proportionate share of revenues and expenses.
We define Adjusted EBITDA attributable to Western Midstream Partners, LP (“Adjusted EBITDA”) as net income (loss), plus (i) distributions from equity investments, (ii) non - cash equity - based compensation expense, (iii) interest expense, (iv) income tax expense, (v) depreciation and amortization, (vi) impairments, and (vii) other expense (including lower of cost or market inventory adjustments recorded in cost of product), less (i) gain (loss) on divestiture and other, net, (ii) gain (loss) on early extinguishment of debt, (iii) income from equity investments, (iv) income tax benefit, (v) other income, (vi) other items impacting comparability with our core operating performance, and (vii) the noncontrolling interest owners’ proportionate share of revenues and expenses.
The program does not obligate us to acquire any particular amount of common units and the program may be suspended or discontinued at our discretion without prior notice.
The program does not obligate us to acquire any common units, and the program may be suspended or discontinued at our discretion without prior notice.
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.
Our success in maintaining or increasing throughput is impacted by (i) the successful drilling of new wells by producers that are dedicated to our systems, (ii) recompletions of existing wells connected to our systems, (iii) our ability to secure volumes from new wells drilled on non-dedicated acreage, and (iv) our ability to attract natural-gas, crude-oil, NGLs, produced-water, or water-solutions volumes currently serviced by our competitors. 54 Table of Contents Operating and maintenance expenses.
For the year ended December 31, 2025, capital expenditures are expected to range between $625.0 million to $775.0 million (accrual-based, includes equity investments, excludes capitalized interest, and excludes capital expenditures associated with the 25% third-party interest in Chipeta). Management continuously monitors our leverage position and other financial projections to manage the capital structure according to long-term objectives.
For the year ended December 31, 2026, capital expenditures are expected to range between $850.0 million to $1.0 billion (accrual-based, includes equity investments, excludes capitalized interest, and excludes capital expenditures associated with the 25% third-party interest in Chipeta). Management continuously monitors our leverage position and other financial projections to manage the capital structure according to long-term objectives.
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.
For additional information on our senior notes, RCF, and commercial paper program, see Note 13—Debt in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. Finance leases. We have finance leases with third parties for equipment, vehicles, and an NGLs pipeline in Wyoming.
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.
For the year ended December 31, 2025, and excluding the impact of equity investments, 97% of our wellhead natural - gas volume and 100% of our crude - oil and produced - water throughput were serviced under fee - based contracts.
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.
Acquisitions for the year ended December 31, 2025, included the acquisition of Aris. See Items Affecting the Comparability of Our Financial Results within this Item 7.
We are subject to the risk of non - payment or late payment by producers for gathering, processing, transportation, and disposal fees. Additionally, we continue to evaluate counterparty credit risk and, in certain circumstances, are exercising our contractual rights to request adequate assurance of performance.
We examine and monitor the creditworthiness of customers and may establish credit limits for customers. We are subject to the risk of non - payment or late payment by producers for gathering, processing, transportation, and disposal fees. Additionally, we continue to evaluate counterparty credit risk and, in certain circumstances, are exercising our contractual rights to request adequate assurance of performance.
As of December 31, 2024, we had a $155.5 million working capital surplus, which we define as the amount by which current assets exceed current liabilities. As of December 31, 2024, there was $2.0 billion in effective borrowing capacity under the RCF.
As of December 31, 2025, we had a $420.5 million working capital surplus, which we define as the amount by which current assets exceed current liabilities. The effective borrowing capacity under the RCF was $2.0 billion as of December 31, 2025.
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.
For purposes of the following discussion, any increases or decreases “for the year ended December 31, 2025” refer to the comparison of the year ended December 31, 2025, to the year ended December 31, 2024.
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.
Net cash used in investing activities for the year ended December 31, 2024, primarily included (i) 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, (ii) increases to materials and supplies inventory and other, (iii) proceeds related to the sale of several equity investments to third parties, (iv) proceeds related to the sale of our 33.75% interest in the Marcellus Interest systems to a third party, and (v) distributions received from equity investments in excess of cumulative earnings.
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.
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, 2025, we expect to incur asset retirement costs of $9.9 million in 2026, and a total of $427.9 million in years thereafter.
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.
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. 67 Table of Contents Impact of interest rates. Interest rates can be volatile, affecting our interest expense on RCF and commercial paper borrowings.
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.
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.
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.
We recognized long-lived asset and other impairments of $14.8 million and $6.2 million for the years ended December 31, 2025 and 2024, respectively.
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.
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 Comm ittee lowered its target range for the federal funds rate three times in 202 4 and decreased it twice during the year ended December 31, 2025.
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.
The differences between net income (loss) attributable to WES and WES Operating are reconciled as follows: Year Ended December 31, thousands 2025 2024 2023 Net income (loss) attributable to WES $ 1,180,983 $ 1,573,571 $ 1,022,216 Limited partner interest in WES Operating not held by WES (1) 23,835 32,156 20,922 General and administrative expenses (2) 720 1,875 2,943 Other income (expense), net (359) (252) (275) Income taxes 2,734 8 6 Net income (loss) attributable to WES Operating $ 1,207,913 $ 1,607,358 $ 1,045,812 _________________________________________________________________________________________ (1) Represents the portion of net income (loss) allocated to the limited partner interest in WES Operating not held by WES.
Income Tax Expense (Benefit) Year Ended December 31, thousands except percentages 2024 2023 Inc/ (Dec) Income (loss) before income taxes $ 1,629,363 $ 1,052,392 55 % Income tax expense (benefit) 18,111 4,385 NM Effective tax rate 1 % — % We are not a taxable entity for U.S. federal income tax purposes; therefore, our federal statutory rate is zero percent.
Income Tax Expense (Benefit) Year Ended December 31, thousands except percentages 2025 2024 Inc/(Dec) Income (loss) before income taxes $ 1,227,541 $ 1,629,363 (25) % Income tax expense (benefit) 15,086 18,111 (17) % Effective tax rate 1 % 1 % — % We are not a taxable entity for U.S. federal income tax purposes; therefore, our federal statutory rate is zero percent.
Our results of operations do not differ materially from the results of operations and cash flows of WES Operating, which are reconciled below. Reconciliation of net income (loss).
ITEMS AFFECTING THE COMPARABILITY OF FINANCIAL RESULTS WITH WES OPERATING Our consolidated financial statements include the consolidated financial results of WES Operating. Our results of operations do not differ materially from the results of operations and cash flows of WES Operating, which are reconciled below. Reconciliation of net income (loss).
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.
Future increased interest rates would likely 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. Therefore, changes in interest rates may affect investor yield requirements.
See Note 4—Partnership Distributions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
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.
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 2025 2024 2023 WES net cash provided by operating activities $ 2,222,625 $ 2,136,860 $ 1,661,334 General and administrative expenses (1) 720 1,875 2,943 Non - cash equity - based compensation expense (608) (581) (581) Changes in working capital (29,656) (29,198) (15,226) Other income (expense), net (359) (252) (275) Income taxes — 8 6 WES Operating net cash provided by operating activities $ 2,192,722 $ 2,108,712 $ 1,648,201 WES net cash provided by (used in) financing activities $ (1,408,392) $ (1,280,015) $ (67,912) Distributions to WES unitholders (2) 1,431,024 1,246,069 978,430 Distributions to WES from WES Operating (3) (1,435,970) (1,246,702) (1,119,367) Increase (decrease) in outstanding checks 2,411 50 (52) Unit repurchases — — 134,602 Other 27,337 27,316 15,472 WES Operating net cash provided by (used in) financing activities $ (1,383,590) $ (1,253,282) $ (58,827) _________________________________________________________________________________________ (1) Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating.
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.
Discussion of 2023 items and comparison of the year ended December 31, 2024, to the year ended December 31, 2023, 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, 2024, and is available via the SEC’s website at www.sec.gov and our website at www.westernmidstream.com . 56 Table of Contents Throughput Year Ended December 31, 2025 2024 Inc/(Dec) Throughput for natural-gas assets (MMcf/d) Gathering, treating, and transportation 375 453 (17) % Processing 4,479 4,256 5 % Equity investments (1) 550 517 6 % Total throughput 5,404 5,226 3 % Throughput attributable to noncontrolling interests 178 174 2 % Total throughput attributable to WES for natural - gas assets 5,226 5,052 3 % Throughput for crude-oil and NGLs assets (MBbls/d) Gathering, treating, and transportation 420 397 6 % Equity investments (1) 104 144 (28) % Total throughput 524 541 (3) % Throughput attributable to noncontrolling interests 10 11 (9) % Total throughput attributable to WES for crude - oil and NGLs assets 514 530 (3) % Throughput for produced-water assets (MBbls/d) Gathering, disposal, and water solutions 1,608 1,147 40 % Throughput attributable to noncontrolling interests 30 23 30 % Total throughput attributable to WES for produced - water assets (2) 1,578 1,124 40 % _________________________________________________________________________________________ (1) Represents our share of average throughput for investments accounted for under the equity method of accounting.
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.
LIQUIDITY AND CAPITAL RESOURCES Our primary cash uses include equity and debt service, operating expenses, acquisitions, and capital expenditures. Our sources of liquidity, as of December 31, 2025, 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.
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.
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. 65 Table of Contents KEY PERFORMANCE METRICS Year Ended December 31, thousands except percentages and per-unit amounts 2025 2024 Inc/(Dec) Adjusted Gross Margin $ 3,549,557 $ 3,376,793 5 % Per - Mcf Adjusted Gross Margin for natural - gas assets (1) 1.30 1.30 — % Per - Bbl Adjusted Gross Margin for crude - oil and NGLs assets (1) 3.01 2.94 2 % Per - Bbl Adjusted Gross Margin for produced - water assets (1) 0.89 0.96 (7) % Adjusted EBITDA 2,480,782 2,344,038 6 % Free Cash Flow 1,526,025 1,324,164 15 % _________________________________________________________________________________________ (1) Average for period.
Crude-oil and NGLs assets Total throughput attributable to WES for crude - oil and NGLs assets decreased by 122 MBbls/d for the year ended December 31, 2024, primarily due to (i) the divestiture of Whitethorn LLC, Mont Belvieu JV, Saddlehorn, and Panola in the first quarter of 2024.
Crude-oil and NGLs assets Total throughput attributable to WES for crude - oil and NGLs assets decreased by 16 MBbls/d for the year ended December 31, 2025, primarily due to (i) the divestiture of Whitethorn LLC and Saddlehorn in the first quarter of 2024 and (ii) lower volumes on the TEP pipeline.
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.
Natural-gas assets Total throughput attributable to WES for natural - gas assets increased by 174 MMcf/d for the year ended December 31, 2025, primarily due to (i) higher volumes at the West Texas, DJ Basin, and Chipeta complexes due to increased production in the areas and (ii) higher volumes on the Red Bluff Express pipeline due to the addition of a new receipt point into the pipeline beginning in November 2024.
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.
The New York Mercantile Exchange West Texas Intermediate crude - oil daily settlement prices during 2024 ranged from a low of $65.75 per barrel in September 2024 to a high of $86.91 per barrel in April 2024, and prices during the year ended December 31, 2025, ranged from a low of $ 55.27 per barrel in December 2025 to a high o f $80.04 per barrel in January 2025.
See Note 1—Summary of Significant Accounting Policies and Basis of Presentation in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K.
See Note 1—Summary of Significant Accounting Policies and Basis of Presentation and Note 8—Income Taxes in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 61 Table of Contents RECONCILIATION OF NON-GAAP FINANCIAL MEASURES Adjusted 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 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 .
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 2025 2024 Net cash provided by (used in): Operating activities $ 2,222,625 $ 2,136,860 Investing activities (1,085,206) (39,168) Financing activities (1,408,392) (1,280,015) Net increase (decrease) in cash and cash equivalents $ (270,973) $ 817,677 Operating activities .
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.
As of December 31, 2025, we have future operating-lease payments of $66.4 million in 2026, and a total of $133.2 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.
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.
Acquisitions and capital expenditures as presented in the consolidated statements of cash flows and capital incurred were as follows: Year Ended December 31, thousands 2025 2024 Acquisitions $ 368,638 $ 443 Capital expenditures (1) 727,991 833,856 Capital incurred (1) 739,454 798,330 _________________________________________________________________________________________ (1) For the years ended December 31, 2025 and 2024, included $10.2 million and $15.2 million, respectively, of capitalized interest.
The Waha Hub natural-gas price during 2023 ranged from a low of ($3.8400) per MMBtu in January 2023 to a high of $3.2750 per MMBtu in January 2023, and prices during the year ended December 31, 2024, ranged from a low of ($6.2250) per MMBtu in August 2024 to a high of $8.2650 per MMBtu in January 2024.
The Waha Hub natural-gas prices during 2024 ranged from a low of ($6.23) per MMBtu in August 2024 to a high of $8.27 per MMBtu in January 2024, and prices during the year ended December 31, 2025, ranged from a low of ($8.82) per MMBtu in October 2025 to a high of $ 7.50 per MMBtu in January 2025.
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.
Net cash used in investing activities for the year ended December 31, 2025, primarily included (i) capital expenditures, primarily related to expansion, construction, and asset - integrity projects at the West Texas complex, DBM water systems, Powder River Basin complex, DJ Basin complex, DBM oil system, Chipeta complex, and DJ Basin oil system, (ii) cash paid, net of cash received for the acquisition of Aris, and (iii) distributions received from equity investments in excess of cumulative earnings.
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.
See Note 3—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 55 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 2025 2024 Total revenues and other (1) $ 3,843,403 $ 3,605,223 Equity income, net – related parties 85,788 112,385 Total operating expenses (1) 2,316,676 2,043,647 Gain (loss) on divestiture and other, net (11,113) 296,771 Operating income (loss) 1,601,402 1,970,732 Interest expense (390,490) (378,513) Gain (loss) on early extinguishment of debt — 5,403 Other income (expense), net 16,629 31,741 Income (loss) before income taxes 1,227,541 1,629,363 Income tax expense (benefit) 15,086 18,111 Net income (loss) 1,212,455 1,611,252 Net income (loss) attributable to noncontrolling interests 31,472 37,681 Net income (loss) attributable to Western Midstream Partners, LP (2) $ 1,180,983 $ 1,573,571 _________________________________________________________________________________________ (1) Total revenues and other includes amounts earned from services provided to related parties and from the sale of natural gas, condensate, NGLs, and water solutions volumes to related parties.
CRITICAL ACCOUNTING ESTIMATES The preparation of consolidated financial statements in accordance with GAAP requires management to make informed judgments and estimates that affect the amounts of assets and liabilities as of the date of the financial statements and the amounts of revenues and expenses recognized during the periods reported.
See Note 4—Partnership Distributions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 73 Table of Contents CRITICAL ACCOUNTING ESTIMATES The preparation of consolidated financial statements in accordance with GAAP requires management to make informed judgments and estimates that affect the amounts of assets and liabilities as of the date of the financial statements and the amounts of revenues and expenses recognized during the periods reported.
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.
Additionally, even in favorable commodity-price environments, our customers face operational challenges such as severe weather disruptions, oil and gas takeaway constraints, produced water recycling and disposal limitations, seismicity concerns, new regulatory requirements, and optimizing large, complex drilling programs.
This was offset partially by (i) a $118.0 million increase in operation and maintenance expenses, (ii) a $52.0 million decrease in distributions from equity investments, (iii) a $32.9 million increase in general and administrative expenses excluding non - cash equity - based compensation expense, (iv) a $7.8 million increase in cost of product (net of lower of cost or market inventory adjustments), and (v) a $6.2 million increase in property and other taxes. 70 Table of Contents Free Cash Flow.
This amount was offset partially by (i) a $35.3 million increase in operation and maintenance expenses, (ii) a $34.7 million increase in cost of product (net of lower of cost or market inventory adjustments), (iii) a $19.9 million decrease in distributions from equity investments, and (iv) a $6.7 million increase in property taxes. Free Cash Flow.
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.
Free Cash Flow increased by $201.9 million for the year ended December 31, 2025, primarily due to (i) a $105.9 million decrease in capital expenditures, (ii) an $85.8 million increase in net cash provided by operating activities, and (iii) a $9.7 million decrease in contributions to equity investments.
A subsidiary of Occidental held a 2.0% limited partner interest in WES Operating for all periods presented. (2) Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating. Reconciliation of net cash provided by (used in) operating and financing activities.
(2) Represents general and administrative expenses incurred by WES separate from, and in addition to, those incurred by WES Operating. 72 Table of Contents Reconciliation of net cash provided by (used in) operating and financing activities.
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.
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. 74 Table of Contents Fair value.
Per - Bbl Adjusted Gross Margin for crude - oil and NGLs assets increased by $0.46 for the year ended December 31, 2024, primarily due to (i) the sale of our interests in Whitethorn LLC, Mont Belvieu JV, and Saddlehorn in the first quarter of 2024, all of which had lower-than-average per-Bbl margins as compared to our other crude-oil and NGLs assets, and (ii) increased throughput at the DBM oil system, which has a higher-than-average per-Mcf margin as compared to our other crude-oil and NGLs assets, in addition to a higher average fee resulting from a cost-of-service rate redetermination effective January 1, 2024.
Per - Bbl Adjusted gross margin for crude - oil and NGLs assets increased by $0.07 for the year ended December 31, 2025, primarily due to (i) increased throughput at the DBM oil system, which has a higher-than-average per-Bbl margin as compared to our other crude-oil and NGLs assets, (ii) lower throughput at TEP and FRP, which have lower-than-average per-Bbl margins as compared to our other crude-oil and NGLs assets, and (iii) the sale of our interest in Whitethorn LLC which had a lower-than-average per-Bbl margin as compared to our other crude-oil and NGLs assets.
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.
Depreciation and amortization expense Depreciation and amortization expense increased by $60.4 million for the year ended December 31, 2025, primarily due to (i) $31.2 million in capital projects being placed into service at the West Texas complex and (ii) $21.5 million related to the acquisition of Aris.
Investments in non-controlled entities over which the Partnership exercises significant influence are accounted for under the equity method of accounting. Management assesses its equity investments for impairment whenever events or changes in circumstances indicate their carrying amount may have experienced a decline in value that is other than temporary.
Management assesses its equity investments for impairment when events or changes in circumstances indicate their carrying amount may have experienced a decline in value that is other than temporary.
These increases were offset partially by (i) lower volumes at the Marcellus Interest systems due to the sale of the asset during the second quarter of 2024 and (ii) lower volumes at the Granger complex due to a contract expiration in the fourth quarter of 2023.
These increases were offset partially by (i) lower volumes at the Marcellus Interest systems due to the sale of the asset during the second quarter of 2024, (ii) lower volumes at the Springfield gas-gathering system due to decreased production in the area, and (iii) lower volumes at the Mi Vida plant.
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.
Year Ended December 31, thousands except per-unit amounts 2025 2024 Gross margin Gross margin for natural - gas assets (1) $ 2,113,810 $ 2,073,533 Gross margin for crude - oil and NGLs assets (1) 407,211 395,886 Gross margin for produced - water assets (1) 435,501 341,784 Per - Mcf Gross margin for natural - gas assets (2) 1.07 1.08 Per - Bbl Gross margin for crude - oil and NGLs assets (2) 2.13 2.00 Per - Bbl Gross margin for produced - water assets (2) 0.74 0.81 Adjusted Gross Margin Adjusted Gross Margin for natural - gas assets $ 2,471,011 $ 2,411,438 Adjusted Gross Margin for crude - oil and NGLs assets 564,461 570,476 Adjusted Gross Margin for produced - water assets 514,085 394,879 Per - Mcf Adjusted Gross Margin for natural - gas assets (3) 1.30 1.30 Per - Bbl Adjusted Gross Margin for crude - oil and NGLs assets (3) 3.01 2.94 Per - Bbl Adjusted Gross Margin for produced - water assets (3) 0.89 0.96 _________________________________________________________________________________________ (1) Excludes corporate-level depreciation and amortization.
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).
Gross margin increased by $143.1 million for the year ended December 31, 2025, primarily due to a $238.2 million increase in total revenues and other, partially offset by a $60.4 million increase in depreciation and amortization. Net income (loss).
Management compensates for the limitations of Adjusted Gross Margin, Adjusted EBITDA, and Free cash flow as analytical tools by reviewing the comparable GAAP measures, understanding the differences between Adjusted Gross Margin, Adjusted EBITDA, and Free Cash Flow compared to (as applicable) gross margin, net income (loss), and net cash provided by operating activities, and incorporating this knowledge into its decision - making processes.
Management compensates for the limitations of our non-GAAP measures as analytical tools by reviewing the comparable GAAP measures, understanding the differences, and incorporating this knowledge into its decision - making processes.
Net cash used in financing activities for the year ended December 31, 2024, primarily included the following: • $1,275.9 million of distributions paid to WES unitholders and noncontrolling interest owners; • $610.3 million of net repayments under the commercial paper program; • $143.9 million to purchase and retire portions of certain of WES Operating’s senior notes via open-market repurchases; and 75 Table of Contents • $790.3 million of net proceeds from the 5.450% Senior Notes due 2034 issued in August 2024, which will be used to repay a portion of the maturing 3.100% Senior Notes due 2025 and 3.950% Senior Notes due 2025 and for general partnership purposes, including the funding of capital expenditures.
Net cash used in financing activities for the year ended December 31, 2024, primarily included (i) distributions paid to WES unitholders and noncontrolling interest owners, (ii) net repayments under the commercial paper program, (iii) retiring portions of certain of WES Operating’s senior notes via open-market repurchases, and (iv) proceeds from the 5.450% Senior Notes due 2034 issued in August 2024. 70 Table of Contents Debt and credit facilities.
These increases were offset partially by (i) the sale of our interests in the Marcellus Interest systems, Mont Belvieu JV, and Saddlehorn during 2024, (ii) decreased distributions from TEP, (iii) decreased revenues associated with demand volumes and a lower cumulative catch-up adjustment for changes in estimated consideration in 2024 compared to 2023 at the Springfield system, partially offset by increased throughput and higher average fees resulting from cost-of-service rate redeterminations effective January 1, 2024, and (iv) decreased processing fees at the Brasada complex resulting from a change in contract terms effective July 1, 2023, partially offset by increased throughput.
These increases were offset partially by (i) lower annual cumulative catch-up adjustments for cost-of-service changes in estimated consideration in 2025 compared to 2024 and decreased throughput at the Springfield gas-gathering system, (ii) the sale of our interests in the Marcellus Interest systems, Saddlehorn, and Mont Belvieu JV during 2024, (iii) lower annual cumulative catch-up adjustments for cost-of-service changes in estimated consideration in 2025 compared to 2024, partially offset by increased throughput at the DJ Basin oil system, and (iv) decreased throughput at the Granger complex.
Net income (loss) increased by $563.2 million for the year ended December 31, 2024, primarily due to (i) a $498.7 million increase in total revenues and other and (ii) a $306.9 million increase in gain (loss) on divestiture and other, net.
Net income (loss) decreased by $398.8 million for the year ended December 31, 2025, primarily due to (i) a $307.9 million decrease in gain (loss) on divestiture and other, net and (ii) a $273.0 million increase in total operating expenses. These amounts were offset partially by a $238.2 million increase in total revenues and other.
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.
Other items Other items increased by $23.9 million for the year ended December 31, 2025, primarily due to changes in imbalance positions at the West Texas and Powder River Basin complexes.
These increases were offset partially by decreases of (i) $23.7 million at the Marcellus Interest systems due to the sale of the asset during the second quarter of 2024, (ii) $16.8 million and $4.3 million at the Springfield and DJ Basin oil systems, respectively, primarily due to decreased revenues associated with demand volumes and lower cumulative catch-up adjustments for changes in estimated consideration in 2024 compared to 2023, partially offset by increased throughput and higher average fees resulting from cost-of-service rate redeterminations effective January 1, 2024, (iii) $11.8 million at the Granger complex due to a contract expiration in the fourth quarter of 2023, and (iv) $10.5 million at the Brasada complex due to a change in contract terms effective July 1, 2023, partially offset by increased throughput.
These increases were offset partially by decreases of (i) $32.4 million at the Springfield systems due to decreased throughput and lower annual cumulative catch-up adjustments for cost-of-service changes in estimated consideration in 2025 compared to 2024, (ii) $18.7 million at the DJ Basin oil system due to lower annual cumulative catch-up adjustments for cost-of-service changes in estimated consideration in 2025 compared to 2024, partially offset by increased throughput, and (iii) $11.0 million at the Marcellus Interest systems due to the sale of the asset during the second quarter of 2024.
Generally, non - payment or non - performance results from a customer’s inability to satisfy payables to us for services rendered, minimum - volume - commitment deficiency payments owed, or volumes owed pursuant to gas- or NGLs-imbalance agreements. We examine and monitor the creditworthiness of customers and may establish credit limits for customers.
We bear credit risk through exposure to non - payment or non - performance by our counterparties (e.g., Occidental and other customers, financial institutions, and other parties), including risks from a customer’s inability to satisfy payables to us for services rendered, minimum - volume - commitment deficiency payments owed, or volumes owed pursuant to gas- or NGLs-imbalance agreements.
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.
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. 63 Table of Contents Year Ended December 31, thousands 2025 2024 Reconciliation of Net income (loss) to Adjusted EBITDA Net income (loss) $ 1,212,455 $ 1,611,252 Add: Distributions from equity investments 122,364 142,236 Non-cash equity-based compensation expense (1) 50,803 37,994 Interest expense 390,490 378,513 Income tax expense 15,086 18,111 Depreciation and amortization 710,778 650,428 Long-lived asset and other impairments 14,760 6,206 Other expense 303 248 Less: Gain (loss) on divestiture and other, net (11,113) 296,771 Gain (loss) on early extinguishment of debt — 5,403 Equity income, net – related parties 85,788 112,385 Other income 16,629 31,741 Items impacting comparability Acquisition-related expenses (1) (113,188) — Adjusted EBITDA attributable to noncontrolling interests 58,141 54,650 Adjusted EBITDA (2) $ 2,480,782 $ 2,344,038 Reconciliation of Net cash provided by operating activities to Adjusted EBITDA Net cash provided by operating activities $ 2,222,625 $ 2,136,860 Interest (income) expense, net 390,490 378,513 Accretion and amortization of long-term obligations, net (6,945) (9,238) Current income tax expense (benefit) 11,142 3,900 Other (income) expense, net (16,629) (31,741) Distributions from equity investments in excess of cumulative earnings – related parties 31,391 30,850 Changes in assets and liabilities: Accounts receivable, net (36,018) 42,798 Accounts and imbalance payables and accrued liabilities, net 3,969 21,935 Other items, net (174,290) (175,189) Acquisition-related expenses (1) 113,188 — Adjusted EBITDA attributable to noncontrolling interests (58,141) (54,650) Adjusted EBITDA (2) $ 2,480,782 $ 2,344,038 Cash flow information Net cash provided by operating activities $ 2,222,625 $ 2,136,860 Net cash used in investing activities (1,085,206) (39,168) Net cash used in financing activities (1,408,392) (1,280,015) _________________________________________________________________________________________ (1) Acquisition-related expenses include (i) $97.3 million of severance costs and (ii) $15.9 million of third-party consulting and legal fees.
Capital expenditures include maintenance capital expenditures, which include those expenditures required to maintain existing operating capacity and service capability of our assets, and expansion capital expenditures, which include expenditures to construct new midstream infrastructure and expenditures incurred to reduce costs, increase revenues, or increase system throughput or capacity from current levels.
Capital expenditures include (i) maintenance capital expenditures, which include those expenditures required to maintain existing operating capacity and service capability of our assets, such as to replace system components and equipment that have been subject to significant use over time, become obsolete or reached the end of their useful lives, or to remain in compliance with regulatory or legal requirements, and (ii) expansion capital expenditures, which include expenditures to construct new midstream infrastructure and expenditures incurred to reduce costs, increase revenues, or increase system throughput or capacity from current levels.
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.
Adjusted Gross Margin increased by $172.8 million for the year ended December 31, 2025, primarily due to (i) the acquisition of Aris and increased throughput at the DBM water systems and (ii) increased throughput at the West Texas complex and DBM oil system.
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 .
We have offload agreements with third parties providing natural-gas firm-processing capacity through 2028 and produced-water disposal capacity through 2036. As of December 31, 2025, we have future minimum payments under offload agreements totaling $19.6 million for 2026, and a total of $312.8 million in years thereafter. Pipeline commitments. We have transportation contracts with volume commitments on multiple pipelines through 2038.
Per - Mcf Adjusted Gross Margin for natural - gas assets increased by $0.02 for the year ended December 31, 2024, primarily due to (i) increased throughput at the West Texas complex, which has a higher-than-average per-Mcf margin as compared to our other natural-gas assets, in addition to 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, and (ii) increased throughput at the DJ Basin complex, which has a higher-than-average per-Mcf margin as compared to our other natural-gas assets.
Per - Mcf Adjusted gross margin for natural - gas assets was unchanged for the year ended December 31, 2025, primarily due to increased throughput at the West Texas complex, which has a higher-than-average per-Mcf margin as compared to our other natural-gas assets, offset by lower average prices at the DJ Basin complex.
In February 2025, the Board authorized a buyback program of up to $250.0 million of our common units through December 31, 2026 (the “2025 Purchase Program”). The common units may be purchased from time to time in the open market at prevailing market prices or in privately negotiated transactions.
The cash distribution was paid on February 13, 2026, to our unitholders of record at the close of business on February 2, 2026. In February 2025, the Board authorized a buyback program of up to $250.0 million of our common units through December 31, 2026 (the “2025 Purchase Program”).
Capital expenditures increased by $98.8 million for the year ended December 31, 2024, primarily due to increases of (i) $88.3 million at the West Texas complex, primarily attributable to engineering, equipment, and construction milestone payments for the North Loving Plant, (ii) $28.2 million at the Powder River Basin complex primarily attributable to the acquisition of Meritage, (iii) $24.2 million at the DBM water systems due to increased construction of certain water - disposal wells, equipment, facilities, and well-connect projects, and (iv) $8.2 million at the Chipeta complex primarily related to expansion projects.
Capital expenditures decreased by $105.9 million for the year ended December 31, 2025, primarily due to decreases of (i) $216.8 million at the West Texas complex, primarily attributable to construction costs incurred in 2024 associated with the North Loving plant that was completed in the first quarter of 2025 and (ii) $23.3 million at the DBM water systems due to decreased construction of certain water - disposal wells, equipment, facilities, and well-connect projects.
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 6—Related-Party Transactions in the Notes to Consolidated Financial Statements under Part II, Item 8 of this Form 10-K. 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.
These increases were offset partially by (i) decreased revenues associated with demand volumes and lower cumulative catch-up adjustments for changes in estimated consideration in 2024 compared to 2023 at the DJ Basin oil and Springfield systems, partially offset by higher average fees resulting from cost-of-service rate redeterminations effective January 1, 2024, and (ii) decreased distributions at TEP.
These increases were offset partially by decreased revenues associated with lower annual cumulative catch-up adjustments for cost-of-service changes at the DJ Basin oil and Springfield oil-gathering systems that increased revenues in the fourth quarter of 2024 and decreased revenues in the fourth quarter of 2025.
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 Long - lived asset and other impairment expense increased by $8.6 million for the year ended December 31, 2025, primarily due to a $10.8 million impairment at the Granger complex.

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