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oke-20251231

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2025.

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________ to __________.

Commission file number 001-13643

ONEOK, Inc.

(Exact name of registrant as specified in its charter)

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code (918) 588-7000

Securities registered pursuant to Section 12(b) of the Act:

Title of each class Trading Symbol(s) Name of each exchange on which registered

Common stock, par value of $0.01 OKE New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes☒ No ☐.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No☒.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐

Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒.

Aggregate market value of registrant’s common stock held by non-affiliates based on the closing trade price on June 30, 2025, was $51.1 billion.

On February 16, 2026, the Company had 629,783,634 shares of common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the definitive proxy statement to be delivered to shareholders in connection with the Annual Meeting of Shareholders to be held May 20, 2026, are incorporated by reference in Part III.

ONEOK, Inc.

2025 ANNUAL REPORT

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Part I. Page No.

Item 1. Business 6

Item 1A. Risk Factors 30

Item 1B. Unresolved Staff Comments 44

Item 1C. Cybersecurity 45

Item 2. Properties 45

Item 3. Legal Proceedings 45

Item 4. Mine Safety Disclosures 46

Part II.

Item 6. [Reserved] 47

Item 7A. Quantitative and Qualitative Disclosures about Market Risk 62

Item 8. Financial Statements and Supplementary Data

Notes to Consolidated Financial Statements

A. Summary of Significant Accounting Policies 71

B. Acquisitions and Divestitures 80

C. Fair Value Measurements 87

D. Risk-Management and Hedging Activities using Derivatives 87

E. Property, Plant and Equipment 91

F. Goodwill and Intangible Assets 92

H. Equity 96

I. Variable Interest Entities 98

J. Earnings Per Share 99

K. Share-Based Payments 99

L. Employee Benefit Plans 102

M. Income Taxes 106

N. Unconsolidated Affiliates 108

O. Commitments and Contingencies 109

Item 9A. Controls and Procedures 115

Item 9B. Other Information 116

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 116

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Part III.

Item 10. Directors, Executive Officers and Corporate Governance 116

Item 11. Executive Compensation 116

Item 14. Principal Accounting Fees and Services 117

Part IV.

Item 15. Exhibits, Financial Statement Schedules 118

As used in this Annual Report, references to “ONEOK,” “we,” “our,” or “us” refer to ONEOK, Inc., an Oklahoma corporation, and its predecessors and subsidiaries, including Magellan, EnLink and Medallion, unless the context indicates otherwise.

The statements in this Annual Report that are not historical information, including statements concerning plans and objectives of management for future operations, economic performance or related assumptions, are forward-looking statements. Forward-looking statements may include words such as “anticipates,” “believes,” “continues,” “could,” “estimates,” “expects,” “forecasts,” “goal,” “guidance,” “intends,” “may,” “might,” “outlook,” “plans,” “potential,” “projects,” “scheduled,” “should,” “target,” “will,” “would” and other words and terms of similar meaning. Although we believe that our expectations regarding future events are based on reasonable assumptions, we can give no assurance that such expectations or assumptions will be achieved. Important factors that could cause actual results to differ materially from those in the forward-looking statements are described under Part I, Item 1A, Risk Factors.

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GLOSSARY

The abbreviations, acronyms and industry terminology used in this Annual Report are defined as follows:

AFUDC Allowance for funds used during construction

Annual Report Annual Report on Form 10-K for the year ended December 31, 2025

Ascension Ascension Pipeline Company, LLC, a 50% owned joint venture

Bbl Barrels, 1 barrel is equivalent to 42 United States gallons

Bcf Billion cubic feet

Bcf/d Billion cubic feet per day

EnLink Revolving Credit Facility EnLink’s $1.4 billion unsecured credit facility

EPS Earnings per share of common stock

ESG Environmental, social and governance

Exchange Act Securities Exchange Act of 1934, as amended

FERC Federal Energy Regulatory Commission

Fitch Fitch Ratings, Inc.

GAAP Accounting principles generally accepted in the United States of America

GHG Greenhouse gas

Guardian Guardian Pipeline, L.L.C.

Magellan Magellan Midstream Partners, L.P., a wholly owned subsidiary of ONEOK

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Matterhorn MXP Parent, LLC, a 15% owned joint venture

MBbl/d Thousand barrels per day

MBTC Pipeline MBTC Pipeline LLC, an 80% owned joint venture

MDth/d Thousand dekatherms per day

MMBbl Million barrels

MMcf/d Million cubic feet per day

Moody’s Moody’s Investors Service, Inc.

MVP MVP Terminalling, LLC, a 25% owned joint venture

Natural Gas Act Natural Gas Act of 1938, as amended

NGL(s) Natural gas liquid(s)

Northern Border Northern Border Pipeline Company, a 50% owned joint venture

NYMEX New York Mercantile Exchange

NYSE New York Stock Exchange

ONEOK ONEOK, Inc.

ONEOK Partners ONEOK Partners, L.P., a wholly owned subsidiary of ONEOK

Overland Pass Overland Pass Pipeline Company, LLC, a 50% owned joint venture

POP Percent of Proceeds

Quarterly Report(s) Quarterly Report(s) on Form 10-Q

Roadrunner Roadrunner Gas Transmission Holdings, LLC, a 50% owned joint venture

S&P S&P Global Ratings

Saddlehorn Saddlehorn Pipeline Company, LLC, a 40% owned joint venture

SEC Securities and Exchange Commission

Securities Act Securities Act of 1933, as amended

Texas City Logistics Texas City Logistics, LLC, a 50% owned joint venture

Viking Viking Gas Transmission Company

XBRL eXtensible Business Reporting Language

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PART I

ITEM 1. BUSINESS

GENERAL

We are incorporated under the laws of the state of Oklahoma, and our common stock is listed on the NYSE under the trading symbol “OKE.” We deliver energy products and services vital to an advancing world. We are a leading midstream service provider of gathering, processing, fractionation, transportation, storage and marine export services. As one of the largest integrated energy infrastructure companies in North America, we are delivering energy that makes a difference in the lives of people in the U.S. and around the world. Through our approximately 60,000-mile pipeline network, we transport the natural gas, NGLs, Refined Products and crude oil that help meet domestic and international energy demand, contribute to energy security and provide safe, reliable and responsible energy solutions needed today and into the future.

Midstream Value Chain

The midstream value chain is a vital part of the energy industry. After crude oil and natural gas are produced from upstream wells, we use our extensive infrastructure to process and transport these raw materials, readying them for end use. For transportation of crude oil, natural gas, Refined Products and NGLs, pipelines are generally the most reliable, lowest cost, least carbon intensive and safest alternative for intermediate and long-haul movements between markets and end users.

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EXECUTIVE SUMMARY

EnLink Acquisition - On January 31, 2025, we completed the EnLink Acquisition. Pursuant to the EnLink Merger Agreement, each publicly held common unit of EnLink was exchanged for a fixed ratio of 0.1412 shares of ONEOK common stock, including EnLink Units that were exchanged for all previously outstanding Series B Preferred Units immediately prior to closing. We issued 41 million shares of common stock with a fair value of $4.0 billion as of the closing date of the EnLink Acquisition. EnLink is now a wholly owned subsidiary.

For additional information on the EnLink Acquisition, see Part II, Item 8, Note B of the Notes to Consolidated Financial Statements in this Annual Report.

Business Update and Market Conditions - Over the past year, we experienced earnings growth across our value chain due primarily to a full year of earnings from EnLink and Medallion across our segments and higher NGL and natural gas processing volumes. Our extensive and integrated assets are located in, and connected with, some of the most productive shale basins, as well as refineries and demand centers, in the United States.

With changes in the commodity price environment, we continue to monitor producers’ drilling and completion plans. Our counterparties are primarily major and independent crude oil and natural gas producers that are able to produce in a lower commodity price environment and continue to find ways to lower costs or enhance production, resulting in profitable projects across our footprint. With our large asset base, multi-basin exposure and continued asset integration, most of our growth opportunities are not contingent on improving commodity prices.

Although the energy industry has experienced many commodity cycles, we have positioned ourselves to reduce exposure to direct commodity price volatility. Each of our four reportable segments are primarily fee-based, and our consolidated earnings were approximately 90% fee-based in 2025.

In addition, our Natural Gas Gathering and Processing and Natural Gas Liquids segments are exposed to volumetric risk as a result of drilling and completion activity, severe weather disruptions, operational outages, global crude oil, NGL and natural gas demand and normal volumetric well declines. Our Refined Products and Crude segment is exposed to volumetric risk due to demand for Refined Products and crude oil in the markets we serve. Our Natural Gas Pipelines segment is not exposed to significant volumetric risk due to the majority of our capacity being subscribed under long-term, firm fee-based contracts.

For additional information regarding the potential impact of volumetric risk on our business, see Item 1A “Risk Factors.”

Capital Allocation - We continue to focus on maintaining prudent financial strength and flexibility. In January 2026, our Board of Directors increased our quarterly dividend to $1.07 per share, an increase of 4% compared with the same quarter in the prior year. In 2024, our Board of Directors authorized a share repurchase program to buy up to $2.0 billion of our outstanding common stock. As of December 31, 2025, we repurchased $234 million of our outstanding common shares under the program. As of December 31, 2025, we also had $78 million of cash and cash equivalents on hand and $3.5 billion of available capacity under our $3.5 Billion Credit Agreement.

Sustainability and Social Responsibility - In 2025, we received an MSCI ESG Rating of AA, and our ESG Risk Rating, as assessed by Morningstar Sustainalytics, was in the top 10% of the refiners and pipelines industry.

Natural Gas Gathering and Processing - In our Natural Gas Gathering and Processing segment, earnings increased in 2025, compared with 2024, due to a full year of earnings from EnLink and higher volumes in the Mid-Continent and Rocky Mountain regions, offset partially by lower realized NGL prices, net of hedging, and the impact from the divestiture of certain nonstrategic assets in 2024. Our 2024 results include the impact of the EnLink Controlling Interest Acquisition from the period of October 15, 2024, to December 31, 2024.

On May 28, 2025, we completed the Delaware Basin JV Acquisition for $941 million. Following the completion of the transaction, it is now a wholly owned subsidiary.

In August 2025, we announced plans to construct the Bighorn natural gas processing plant in the Permian Basin, with processing capacity of 300 MMcf/d and the ability to treat natural gas containing high levels of carbon dioxide. We expect the Bighorn plant, including the carbon dioxidetreater, to cost approximately $365 million. The Bighorn plant is supported by acreage dedications with long-term primarily fee-based contracts and is expected to be completed in mid-2027.

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We are also relocating a 150 MMcf/d processing plant to the Permian Basin from North Texas, which will be completed in the first quarter of 2026, and expanding two existing facilities in the Permian Basin, which will provide an incremental 110 MMcf/d of processing capacity and is expected to be completed in the third quarter of 2026.

Natural Gas Liquids - In our Natural Gas Liquids segment, earnings increased in 2025, compared with 2024, due primarily to a full year of earnings from EnLink, higher exchange services and higher optimization and marketing, offset partially by higher operating costs. Our 2024 results include the impact of the EnLink Controlling Interest Acquisition from the period of October 15, 2024, to December 31, 2024.

In 2025, we completed construction of our Elk Creek pipeline expansion project, which increased capacity to 435 MBbl/d and brought our total pipeline capacity out of the Rocky Mountain region to 575 MBbl/d.

In February 2025, we announced definitive agreements to form the Texas City Logistics and MBTC Pipeline joint ventures with MPLX LP to construct a 400 MBbl/d liquified petroleum gas export terminal in Texas City, Texas, and a new 24-inch pipeline from our Mont Belvieu, Texas, storage facility to the new terminal. We expect to invest a total of approximately $1.0 billion into these projects, which are expected to be completed in early 2028.

Natural Gas Pipelines - In our Natural Gas Pipelines segment, earnings decreased in 2025, compared with 2024, due primarily to the impact of the interstate pipeline divestiture in 2024, offset partially by a full year of earnings from EnLink in 2025 and higher optimization and marketing. Our 2024 results include the impact of the EnLink Controlling Interest Acquisition from the period of October 15, 2024, to December 31, 2024.

In 2025, we, WhiteWater, MPLX LP and Enbridge Inc., through the existing Matterhorn joint venture, announced the new approximately 450-mile, 48-inch Eiger Express Pipeline, designed to transport up to approximately 3.7 Bcf/d of natural gas from the Permian Basin to Katy, Texas. We expect to invest a total of approximately $350 million into this project, which is expected to be completed in mid-2028.

Refined Products and Crude - In our Refined Products and Crude segment, earnings increased in 2025, compared with 2024, due primarily to a full year of earnings from Medallion and EnLink and lower operating costs, offset partially by lower earnings on BridgeTex associated with the nonrecurring recognition of deferred revenue in 2024. Our 2024 results include the impact of the EnLink Controlling Interest Acquisition from the period of October 15, 2024, to December 31, 2024, and the impact of the Medallion Acquisition from the period of November 1, 2024, to December 31, 2024.

On July 22, 2025, we completed the BridgeTex Additional Interest Acquisition. Pursuant to the purchase agreement, we paid approximately $270 million in cash. Following the completion of the transaction, we now have a 60% ownership interest in BridgeTex.

We have a capital project to expand our Refined Products pipeline capacity, connecting Mid-Continent and Gulf Coast supply with the greater Denver area, to meet growing demand and increase connectivity with the Denver International Airport (DIA). The project includes construction of a new 230-mile, 16-inch diameter pipeline from Scott City, Kansas, to DIA and the addition or upgrading of certain pump stations along the existing Refined Products pipeline system. Total system capacity will increase by 35 MBbl/d and will have additional expansion capabilities. This project is fully subscribed under long-term contracts and is expected to be completed in mid-2026.

See Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in this Annual Report for more information on our capital projects, results of operations, liquidity and capital resources.

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BUSINESS STRATEGY

Our mission is to deliver energy products and services vital to an advancing world. Our vision is to create exceptional value for our stakeholders by providing solutions for an evolving energy future. Our business strategy is focused on:

•Zero incidents - We commit to developing processes to drive a zero-incident culture for the well-being of our employees, contractors and communities. Safety and environmental responsibility continue to be primary areas of focus for us.

•Highly engaged workforce - We strive to be an employer of choice and continue to focus on attracting, selecting and retaining talent, advancing an inclusive, diverse and engaged culture and developing individuals and leaders.

•Sustainable business model - We aim to maintain prudent financial strength and flexibility while operating a safe, reliable and resilient asset base. We seek to maintain investment-grade credit ratings and a strong balance sheet. We expect our internally generated cash flows will allow us to fund high-return capital projects in our existing operating regions, grow our dividend, reduce debt and fund our $2.0 billion share repurchase program. We aim to focus on capital projects that provide value-added products and services that contribute to long-term growth, profitability and business diversification. We continue to actively seek out opportunities that will complement our extensive assets and expertise.

•Maximizing total shareholder return - We plan to grow earnings through high-return capital projects that will allow us to increase our dividend and repurchase shares under our $2.0 billion share repurchase program. We seek consistent and strong returns on invested capital that will allow us to reward our shareholders and provide the means and opportunity to serve our additional stakeholders, including employees and the communities in which we operate.

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NARRATIVE DESCRIPTION OF BUSINESS

We report operations in the following four business segments:

•Natural Gas Gathering and Processing;

•Natural Gas Liquids;

•Natural Gas Pipelines; and

•Refined Products and Crude.

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Natural Gas Gathering and Processing

Overview of Operations - In our Natural Gas Gathering and Processing segment, raw natural gas is typically gathered at the wellhead, compressed and transported through pipelines to our processing facilities. Most raw natural gas produced at the wellhead also contains a mixture of NGL components, including ethane, propane, iso-butane, normal butane and natural gasoline. Gathered wellhead natural gas is directed to our processing plants to remove NGLs resulting in residue natural gas (primarily methane). Residue natural gas is then recompressed and delivered to natural gas pipelines, storage facilities and end users. The NGLs separated from the raw natural gas are delivered through NGL pipelines to fractionation facilities for further processing. Some of the heavier NGLs may separate upstream of processing and fractionation and are sold as condensate at NGL or crude oil markets. Our Natural Gas Gathering and Processing segment provides these midstream services to producers in the regions listed below.

Rocky Mountain region - The Williston Basin is located in portions of North Dakota and Montana and includes the oil-producing, NGL-rich Bakken Shale and Three Forks formations. We have more than 3 million dedicated acres in the Williston Basin. The Powder River Basin is primarily located in Eastern Wyoming, which includes the NGL-rich Niobrara, Frontier, Turner and Mowry formations. We have more than 300 thousand dedicated acres in the Powder River Basin.

Mid-Continent region - The Mid-Continent region includes the natural gas and oil-producing Anadarko Basin, which includes the NGL-rich SCOOP and STACK areas, Cana-Woodford Shale, Woodford Shale, Arkoma-Woodford Shale, Springer Shale, Meramec, Granite Wash, Cherokee and Mississippian Lime formations of Oklahoma. We also have a significant presence in the Barnett Shale of North Texas, one of the largest onshore natural gas fields in the United States, where we provide gathering and processing services. We have more than 1 million dedicated acres in the Mid-Continent region.

Permian Basin - The Permian Basin is a large, natural gas and oil-rich sedimentary basin composed of the Midland Basin, located in West Texas, and the Delaware Basin, located in West Texas and Southeastern New Mexico. We have more than 400 thousand dedicated acres in the Permian Basin, providing gathering and processing services in the Midland and Delaware Basins.

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Property - Our Natural Gas Gathering and Processing segment includes the following wholly owned assets:

•22,600 miles of natural gas gathering pipelines; and

•Natural gas processing plants with 1.9 Bcf/d of processing capacity in the Rocky Mountain region, 3.5 Bcf/d in the Mid-Continent region and 1.8 Bcf/d of processing capacity in the Permian Basin, which were 78% and 84% utilized in 2025 and 2024, respectively.

We calculate utilization rates using a weighted-average approach, adjusting for the dates that assets were placed in or removed from service.

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We are in the process of relocating a 150 MMcf/d natural gas processing plant to the Permian Basin from North Texas and expanding two existing facilities in the Permian Basin, which will provide an incremental 110 MMcf/d of processing capacity. We also recently announced plans to construct our Bighorn natural gas processing plant, with capacity of 300 MMcf/d, in the Permian Basin. The additional capacity from these projects is excluded from the assets listed above.

See “Recent Developments” in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, in this Annual Report for more information on our capital projects.

Sources of Earnings - Earnings for this segment are derived primarily from the following types of service contracts:

•Fee with POP contracts with no producer take-in-kind rights - We purchase raw natural gas and charge contractual fees for providing midstream services, which include gathering, treating, compressing and processing the producers’ natural gas. After performing these services, we sell the commodities and remit a portion of the commodity sales proceeds to the producers less our contractual fees.

•Fee with POP contracts with producer take-in-kind rights - We purchase a portion of the raw natural gas stream, charge fees for providing the midstream services listed above, return certain commodities to the producer, sell the remaining commodities and remit a portion of the commodity sales proceeds to the producer less our contractual fees.

•Fee-only - Under this type of contract, we charge a fee for the midstream services we provide based on volumes gathered, processed, treated and/or compressed.

For commodity sales, we contract to deliver residue natural gas, condensate and/or unfractionated NGLs to downstream customers at a specified delivery point. Our sales of NGLs are primarily to our affiliate in the Natural Gas Liquids segment.

Unconsolidated Affiliates - Our unconsolidated affiliates in this segment are not material.

See Note N of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of our unconsolidated affiliates.

Government Regulation - The FERC traditionally has maintained that a natural gas processing plant is not a facility for the transportation or sale of natural gas in interstate commerce and, therefore, is not subject to jurisdiction under the Natural Gas Act. Although the FERC has made no specific declaration as to the jurisdictional status of our natural gas processing operations or facilities, our natural gas processing plants are primarily involved in extracting NGLs and, therefore, are exempt from FERC jurisdiction. The Natural Gas Act also exempts natural gas gathering facilities from the jurisdiction of the FERC. We believe our natural gas gathering facilities, upstream of our natural gas processing plants, meet the criteria used by the FERC for non-jurisdictional natural gas gathering facility status. Interstate transmission facilities remain subject to FERC jurisdiction. The FERC has historically distinguished between these two types of facilities, either interstate or intrastate, on a fact-specific basis. We transport residue natural gas from certain of our natural gas processing plants to interstate pipelines in accordance with Section 311(a) of the Natural Gas Policy Act of 1978, as amended. The states where we operate have statutes regulating, to varying degrees, the gathering of natural gas in those states. In each state, regulation is applied on a case-by-case basis if a complaint is filed against the gatherer with the appropriate state regulatory agency.

See further discussion in the “Regulatory, Environmental and Safety Matters” section.

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Natural Gas Liquids

Overviewof Operations - In our Natural Gas Liquids segment, NGLs extracted at our own and third-party natural gas processing plants are gathered by our NGL gathering pipelines. Gathered NGLs are directed to our downstream fractionators to be separated into Purity NGLs. Purity NGLs are stored or distributed to our customers, such as petrochemical companies, propane distributors, diluent users, ethanol producers, refineries and exporters.

We provide midstream services to producers of NGLs in the Rocky Mountain region, Mid-Continent region, Permian Basin and Gulf Coast region and deliver those products to the market. Our primary markets include the Mid-Continent in Conway, Kansas, the Gulf Coast in Mont Belvieu, Texas, Louisiana and the upper Midwest. The majority of the pipeline-connected natural gas processing plants in the Williston Basin, Oklahoma, Kansas and the Texas Panhandle as well as a large number in the Permian Basin, Barnett Shale, East Texas and Louisiana regions are connected to our NGL gathering systems. Through our NGL gathering and distribution pipelines, and fractionation, terminal and storage facilities, we provide needed midstream services while connecting key supply and demand areas.

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Property - Our Natural Gas Liquids segment includes the following assets, which are wholly owned, except where noted:

•10,100 miles of gathering pipelines;

•4,800 miles of distribution pipelines (includes gross mileage of a consolidated, partially owned subsidiary);

•NGL fractionators with combined operating capacity of 1.2 MMBbl/d (includes interests in our proportional share of operating capacity), including 310 MBbl/d in the Mid-Continent region and 890 MBbl/d in the Gulf Coast region, which were 94% and 92% utilized in 2025 and 2024, respectively;

•one isomerization unit with operating capacity of 10 MBbl/d;

•one ethane/propane splitter with operating capacity of 40 MBbl/d;

•NGL storage facilities with operating storage capacity of 40 MMBbl; and

•eight Purity NGLs terminals.

In 2025, we completed the expansion of our Elk Creek pipeline, which is included in the assets listed above.

We are in the process of reconstructing our 210 MBbl/d fractionator in Medford, Oklahoma. We are also in the process of constructing the 24-inch MBTC Pipeline, which is consolidated through a partially owned subsidiary. These assets are excluded from the assets listed above.

Sources of Earnings - Earnings for our Natural Gas Liquids segment are derived primarily from fee-based services and commodity sales and purchases. We purchase NGLs and condensate from third parties, as well as from our Natural Gas Gathering and Processing segment. We also sell NGLs to our affiliate in the Refined Products and Crude segment. Our business activities are categorized as follows:

•Exchange services - We utilize our assets to gather, transport, treat and fractionate NGLs, converting them into marketable Purity NGLs, and deliver them to a market center or customer-designated location. Some of these exchange volumes are under contracts with minimum volume commitments that provide a minimum level of revenues regardless of volumetric throughput. Our exchange services activities are primarily fee-based and include some rate-regulated tariffs; however, we also capture certain product price differentials through the fractionation process.

•Transportation and storage services - We transport Purity NGLs and certain Refined Products, primarily under regulated tariffs. Tariffs specify the maximum rates we may charge our customers and the general terms and conditions for transportation service on our pipelines. Our storage activities consist primarily of fee-based NGL storage services at our Mid-Continent and Gulf Coast storage facilities.

•Optimization and marketing - We utilize our assets, contract portfolio and market knowledge to capture location, product and seasonal price differentials through the purchase and sale of unfractionated NGLs and Purity NGLs. We transport Purity NGLs between the Mid-Continent region, upper Midwest and Gulf Coast regions to capture the location price differentials between market centers. Our marketing activities also include utilizing our NGL storage facilities to capture seasonal price differentials and serving marine, truck and rail markets. Our isomerization activities capture the price differential when normal butane is converted into the more valuable iso-butane at our isomerization unit in Conway, Kansas.

In the majority of our exchange services contracts, we purchase the unfractionated NGLs at the tailgate of the processing plant and deduct contractual fees related to the transportation and fractionation services we must perform before we can sell them as Purity NGLs. To the extent we hold unfractionated NGLs in inventory, the related contractual fees are not recognized until the unfractionated inventory is fractionated and sold.

Unconsolidated Affiliates - We have a 50% ownership interest in Overland Pass, which operates an interstate NGL pipeline system extending 760 miles, originating in Wyoming and Colorado and terminating in Kansas. We also have a 38.75% ownership interest in Gulf Coast Fractionators, which owns an NGL fractionator in Mont Belvieu, Texas, with 145 MBbl/d of operating capacity that is excluded from the combined operating capacity listed above. The fractionator resumed operations in 2025.

In 2025, we announced a joint venture with MPLX LP to construct a 400 MBbl/d liquified petroleum gas export terminal in Texas City, Texas. Texas City Logistics, the export terminal joint venture, is owned 50% by us and 50% by MPLX LP, with MPLX LP constructing and operating the facility. The export terminal is expected to be completed in early 2028. Our other unconsolidated affiliates in this segment are not material.

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See Note N of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of unconsolidated affiliates.

Government Regulation - The operations and revenues of our NGL pipelines are regulated by various state and federal government agencies. Our interstate NGL pipelines are regulated under the Interstate Commerce Act, which gives the FERC jurisdiction to regulate the terms and conditions of service, rates, including depreciation and amortization policies, and initiation of service. Certain aspects of our intrastate NGL pipelines that provide common carrier service are subject to the jurisdiction of various state agencies in the states where we operate.

See further discussion in the “Regulatory, Environmental and Safety Matters” section.

Natural Gas Pipelines

Overview of Operations - In our Natural Gas Pipelines segment, we receive residue natural gas from third parties and our own natural gas processing plants and interconnecting pipelines. Residue natural gas is transported or stored for end users, such as large industrial customers, natural gas and electric utilities serving commercial and residential consumers and can ultimately reach international markets through liquified natural gas exports and cross border pipelines.

Our assets are connected to key supply areas and demand centers, including export markets in Mexico via Roadrunner and supply areas in Canada and the United States via our interstate and intrastate natural gas pipelines, Northern Border and Matterhorn, which enables us to provide essential natural gas transportation and storage services. Growing demand from data centers and continued demand from local distribution companies, electric-generation facilities and large industrial companies position us well for capital projects and low-cost expansions to provide additional services to our customers when needed.

Intrastate Pipelines and Storage - Our intrastate natural gas pipeline and storage assets are located in Oklahoma, Texas, Louisiana and Kansas. Our Oklahoma intrastate pipeline and storage assets have access to major natural gas production areas in the Mid-Continent region. Our Texas intrastate pipeline and storage assets have access to major natural gas producing formations in the Texas Panhandle and North Texas. Our Louisiana intrastate pipeline and storage assets have access to major natural gas production areas in the Haynesville region and access to export markets in the Gulf Coast. These assets provide shippers access to western markets, several markets to the southeast along the Gulf Coast, including the Houston Ship Channel, the Mid-Continent market to the north and exports to Mexico. Our storage facilities provide 74 Bcf of working gas storage capacity. Our intrastate pipeline and storage companies primarily include:

•ONEOK Gas Transportation, which transports natural gas throughout the state of Oklahoma and has access to the major natural gas production areas in the Mid-Continent region, which include the SCOOP and STACK areas and the Cana-Woodford Shale, Woodford Shale, Springer Shale, Meramec, Granite Wash and Mississippian Lime formations. ONEOK Gas Transportation is connected to our ONEOK Gas Storage facilities in Oklahoma, which provide 50 Bcf of working gas storage capacity;

•ONEOK WesTex Transmission, which transports natural gas throughout the western portion of the state of Texas, including the Waha Hub area where other pipelines may be accessed for transportation to western markets, exports to Mexico, several markets along the Gulf Coast, including the Houston Ship Channel and the Mid-Continent market to the north. It has access to major natural gas producing formations in the Texas Panhandle, including the Granite Wash formation and Delaware and Midland Basins in the Permian Basin. ONEOK WesTex Transmission is connected to our ONEOK Texas Gas Storage facilities, which provide 8 Bcf of working gas storage capacity;

•Bridgeline Pipeline, which provides transportation and storage services to a variety of customers including South Louisiana industrial companies, power companies, utilities and Gulf Coast LNG facilities. Bridgeline Pipeline is connected to our Napoleonville and Sorrento storage facilities, which provide 8 Bcf and 3 Bcf of working gas storage capacity, respectively;

•Louisiana Intrastate Gas Pipeline, which is a natural gas pipeline system that has access to the Haynesville Shale and connects to several other natural gas pipelines, including Bridgeline Pipeline, providing additional system supply, and to our Jefferson Island Storage Hub facility, which provides 2 Bcf of working gas storage capacity; and

•Acacia Pipeline, which provides transportation services to connect production from the Barnett Shale to markets in North Texas.

Interstate Pipelines - Sabine Pipeline is an interstate natural gas pipeline that transports natural gas between Port Arthur, Texas, and the Henry Hub located in Erath, Louisiana. The Sabine Pipeline also owns and operates the Henry Hub, the official delivery mechanism and pricing point for Chicago Mercantile Exchange’s NYMEX natural gas futures.

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Property - Our Natural Gas Pipelines segment includes the following wholly owned assets:

•8,300 miles of natural gas pipelines, which were 91% and 97% subscribed in 2025 and 2024, respectively; and

•eleven underground natural gas storage facilities with 74 Bcf of total active working natural gas storage capacity which were 83% and 75% subscribed in 2025 and 2024, respectively.

Our storage includes two underground natural gas storage facilities in Oklahoma, two underground natural gas storage facilities in Kansas, four underground natural gas storage facilities in Texas and three underground natural gas storage facilities in Louisiana.

We are expanding our Jefferson Island Storage Hub facility in Louisiana to increase the working gas storage capacity from 2 Bcf to 11 Bcf, which is excluded from the working natural gas storage capacity listed above. This project is expected to be completed in two phases, with the first phase expected to be completed in the second half of 2028 and the second phase to be completed in early 2029.

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Sources of Earnings - Earnings for our Natural Gas Pipelines segment are derived primarily from fee-based services and our business activities are categorized as follows:

•Transportation services - Our regulated natural gas transportation services contracts are based upon rates stated in the respective tariffs, which have generally been established through shipper specific negotiation, discounts and negotiated settlements. The rates are filed with FERC or the appropriate state jurisdictional agencies. In addition, customers typically are assessed fees, such as a commodity charge, and we may retain a percentage of natural gas in-kind for our compression services. Our transportation earnings are primarily fee-based and utilize the following types of contracts:

◦Firm service - Customers reserve a fixed quantity of pipeline capacity for a specified period of time, which obligates the customer to pay regardless of usage. Under this type of contract, the customer pays a monthly fixed fee and incremental fees, known as commodity charges, which are based on the actual volumes of natural gas they transport or store. Under the firm service contract, the customer generally is guaranteed access to the capacity they reserve. Our firm service contracts typically have terms longer than one year.

◦Interruptible service - Under interruptible service transportation agreements, the customer may utilize available capacity after firm service requests are satisfied. The customer is not guaranteed use of our pipelines unless excess capacity is available.

•Storage services - Our storage earnings are primarily fee-based and utilize the following types of contracts:

◦Firm service - Customers reserve a specific quantity of storage capacity, including injection and withdrawal rights, and generally pay fixed fees based on the quantity of capacity reserved plus an injection and withdrawal fee based on actual usage. Our firm storage contracts typically have terms longer than one year.

◦Park-and-loan service - An interruptible storage service offered to customers providing the ability to park (inject) or loan (withdraw) natural gas into or out of our storage, typically for monthly or seasonal terms. Customers reserve the right to park or loan natural gas based on a specified quantity, including injection and withdrawal rights when capacity is available.

•Optimization and marketing - We utilize our assets, contract portfolio and market knowledge to capture location and price differentials through the purchase and sale of natural gas.

Unconsolidated Affiliates - Our Natural Gas Pipelines segment includes the following unconsolidated affiliates:

•50% ownership interest in Northern Border, which owns a FERC-regulated interstate pipeline that transports natural gas from the Montana-Saskatchewan border near Port of Morgan, Montana, and the Williston Basin in North Dakota to a terminus near North Hayden, Indiana.

•50% ownership interest in Roadrunner, a bidirectional pipeline, which has the capacity to transport 570 MMcf/d of natural gas from the Permian Basin in West Texas to the Mexican border near El Paso, Texas, and has capacity to transport approximately 1.0 Bcf/d of natural gas from the Delaware Basin to the Waha Hub area. We are the operator of Roadrunner.

•15% ownership interest in Matterhorn, a bidirectional pipeline, which has capacity to transport 2.5 Bcf/d of natural gas from the Waha Hub to Katy, Texas.

In 2025, we, WhiteWater, MPLX LP and Enbridge Inc., through the existing Matterhorn joint venture, announced the new approximately 450-mile, 48-inch Eiger Express Pipeline, designed to transport up to approximately 3.7 Bcf/d of natural gas from the Permian Basin to Katy, Texas. WhiteWater will construct and operate the pipeline, which is expected to be completed in mid-2028. Our total ownership interest in the pipeline will be 25.5%, which includes a 15% interest held directly in the Eiger joint venture with the remainder held through Matterhorn.

See Note N of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of unconsolidated affiliates.

Government Regulation - Interstate - Our interstate natural gas pipelines are regulated under the Natural Gas Act, which gives the FERC jurisdiction to regulate virtually all aspects of this business, such as transportation of natural gas, rates and charges for services, construction of new facilities, depreciation and amortization policies, acquisition and disposition of facilities and the initiation and discontinuation of services.

Intrastate - Our intrastate natural gas pipelines in Oklahoma, Kansas, Louisiana and Texas are subject to rate regulation by state regulators and by the FERC under the Natural Gas Policy Act of 1978, as amended, for certain services where we deliver natural gas into FERC-regulated natural gas pipelines. While we have flexibility in establishing natural gas transportation rates with customers, there is a maximum rate that we can charge our customers in Oklahoma and Kansas and for the services regulated by the FERC. In Texas and Kansas, natural gas storage may be regulated by the state and by the FERC for certain

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types of services. In Oklahoma, natural gas storage operations are not subject to rate regulation by the state, and we have market-based rate authority from the FERC for certain types of intrastate services.

See further discussion in the “Regulatory, Environmental and Safety Matters” section.

Refined Products and Crude

Overviewof Operations - Our Refined Products and Crude segment is principally engaged in the transportation, storage and distribution of Refined Products and crude oil. We are also engaged in the gathering of crude oil. Products transported on our Refined Products pipeline system include gasoline, distillates, aviation fuel and certain NGLs. Shipments originate on our Refined Products pipeline system from direct connections to refineries or through interconnections with other pipelines or terminals for transportation and ultimate distribution to retail fueling stations, convenience stores, travel centers, railroads, airports and other end users. Our Refined Products pipeline system is one of the longest common carrier pipeline systems for Refined Products in the United States, extending from the Texas Gulf Coast and covering a 15-state area across the central and western United States.

Our crude oil assets are strategically located to gather, transport and store crude oil and are connected to refineries, export facilities and multiple trading and demand centers. We have crude oil gathering pipelines in the Permian Basin and Mid-Continent region. Our crude oil transportation pipelines are located in Kansas and Oklahoma, and from the Permian Basin in West Texas to our East Houston terminal.

Throughout our Refined Products and crude oil distribution systems, terminals play a key role in facilitating product movements and marketing by providing storage, distribution, blending and other ancillary services. Our Houston distribution system connects our East Houston terminal through several interchanges to various points, including multiple refineries throughout the Houston area and crude oil import and export facilities. Our Cushing terminal primarily receives and distributes crude oil via the multiple pipelines that terminate in and originate from the Cushing hub. Our Corpus Christi terminal provides terminalling services and includes our splitter.

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Property - Our Refined Products and Crude segment includes the following wholly owned assets:

•9,800 miles of Refined Products pipelines;

•1,100 miles of crude oil transportation pipelines;

•2,100 miles of crude oil gathering pipelines;

•53 Refined Products terminals;

•two marine terminals; and

•100 MMBbl of operating storage capacity.

We are in the process of constructing our greater Denver area Refined Products pipeline expansion project. The project includes construction of a new 230-mile, 16-inch diameter pipeline from Scott City, Kansas, to DIA and the addition or upgrading of certain pump stations and will increase total system capacity by 35 MBbl/d and have additional expansion capabilities. This project is excluded from the assets listed above.

Sources of Earnings -Earnings in this segment are derived primarily from transportation, storage and terminal services and product sales:

•Transportation services - We utilize our Refined Products and crude oil pipeline systems to gather and transport products. The fees we charge vary depending upon where the product originates and where ultimate delivery occurs. Transportation fees are in published tariffs filed with the FERC or the appropriate state agency or established by negotiated rates.

•Storage and terminal services - We generate additional revenue from providing pipeline capacity and tank storage services, as well as providing services such as terminalling, ethanol and biodiesel unloading and loading, and additive injection, which are performed under short-term and long-term agreements.

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•Optimization and marketing - We utilize our assets, contract portfolio and market knowledge to capture location, product and seasonal price differentials through liquids blending and purchase and sale of Refined Products and crude oil, including transmix, which is a mixture that forms when different Refined Products are transported in pipelines.

In some crude oil transportation contracts, we purchase the product at the wellhead and deduct contractual fees related to the gathering and transportation services we perform to move the product to market.

Unconsolidated Affiliates - Our Refined Products and Crude segment includes the following unconsolidated affiliates:

•a 60% ownership interest in BridgeTex, which owns an approximately 400-mile crude oil pipeline with transport capacity of up to 440 MBbl/d that connects Permian Basin crude oil to our East Houston terminal;

•a 40% ownership interest in Saddlehorn, which owns an undivided joint interest in an approximately 600-mile pipeline, with transport capacity of up to 290 MBbl/d of crude oil from the Denver-Julesburg Basin and Rocky Mountain region to storage facilities in Cushing, including our Cushing terminal; and

•a 25% ownership in MVP, which owns a Refined Products marine terminal along the Houston Ship Channel in Pasadena, Texas, including more than 5 MMBbl of storage, two ship docks and truck loading facilities.

Our other unconsolidated affiliates in this segment are not material.

See Note N of the Notes to Consolidated Financial Statements in this Annual Report for additional discussion of unconsolidated affiliates.

Government Regulation - Our interstate common carrier pipelines are subject to rate regulation by the FERC under the Interstate Commerce Act, the Energy Policy Act of 1992 and related rules and orders. Most of the tariff rates on our long-haul pipelines are established under market-based rate authority or via negotiated rates that generally allow for annual inflation-based adjustments. Some shipments on our pipeline systems are considered to be in intrastate commerce and are subject to certain regulations with respect to such intrastate transportation by state regulatory authorities in Colorado, Kansas, Minnesota, Oklahoma, Texas or Wyoming. In future rate or rulemaking proceedings, the FERC or state regulatory authorities could reduce rates prospectively, limit our ability to increase future rates or modify the way rates are currently established. In certain circumstances, a change could also require the payment of refunds to shippers.

See further discussion in the “Regulatory, Environmental and Safety Matters” section.

Market Conditions and Seasonality

Supply and Demand-Supply for each of our segments depends on crude oil and natural gas drilling and production activities, which are driven by the strength of the economy and impacts of geopolitical events; crude oil, natural gas, NGL and Refined Products prices; the demand for each of these products from end users; changes in gas-to-oil ratios; refinery maintenance cycles; producer access to capital and investment in the industry; connections to pipelines and refineries; and producer firm commitments to transportation pipelines.

Demand for gathering and processing services is dependent on natural gas and crude oil production by producers in the regions in which we operate. Demand for NGLs and the ability of natural gas processors to sustain their operations successfully and economically affect the volume of unfractionated NGLs produced by natural gas processing plants, thereby affecting the demand for NGL gathering, transportation and fractionation services. Natural gas and Purity NGLs are affected by the demand associated with the various industries that utilize the commodities, such as butanes and natural gasoline used by the refining industry as blending stocks for motor fuel, denaturant for ethanol and diluents for crude oil. Ethane, propane, butanes and natural gasoline are also used by the petrochemical industry to produce chemical components, used for a range of products that improve our daily lives and promote economic growth, including health care products, recyclable food packaging, clothing, technology, building materials, industrial, manufacturing and energy infrastructure, lightweight vehicle components and batteries. Propane is also used to heat homes and businesses. Demand for Refined Products is influenced by many factors, including driving patterns, consumer preferences, economic conditions, population changes, government regulations, changes in vehicle fuel efficiency and the development of alternative energy sources. The demand for Refined Products in the market areas served by our pipeline system has historically been stable. Demand for shipments on our crude oil pipelines is driven primarily by crude oil production and takeaway demand in the regions in which we operate. Demand for natural gas, NGLs, Refined Products and crude oil is also impacted by global macroeconomic factors.

See additional discussion regarding the impacts of the recent market conditions on supply and demand under "Business Update and Market Conditions" in our Executive Summary at the beginning of this Item 1. Business.

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Commodity Prices - Although the energy industry has experienced many commodity cycles, we have positioned ourselves to reduce exposure to direct commodity price volatility. Our earnings are primarily fee-based in all of our segments; however, we are exposed to some commodity price risk. As part of our hedging strategy, we use commodity derivative financial instruments and physical-forward contracts to reduce the impact of price fluctuations related to natural gas, NGLs, Refined Products and crude oil. Our Natural Gas Gathering and Processing segment is exposed to commodity price risk as a result of retaining a portion of the commodity sales proceeds associated with our fee with POP contracts and our POP contracts with take-in-kind rights. Our Natural Gas Gathering and Processing segment follows a programmatic approach to hedging commodity price risk and expects to hedge approximately 75% of its monthly equity volumes over time. Under certain fee with POP contracts, our contractual fees and POP percentage may increase or decrease if production volumes, delivery pressures or commodity prices change relative to specified thresholds. In our Natural Gas Liquids segment, we are exposed to commodity price risk associated with changes in the price of NGLs; the location differential between the Conway, Kansas, upper Midwest region, Mont Belvieu, Texas, and Louisiana; and the relative price differential between natural gas, NGLs and individual Purity NGLs, which affect our NGL purchases and sales, our exchange services, transportation and storage services, and optimization and marketing financial results. We are also exposed to changes in the price of power, which can impact our fractionation and transportation costs. In our Natural Gas Pipelines segment, we are exposed to some commodity price risk associated with changes in the price of natural gas and location differentials primarily from our optimization and marketing activities. In our Refined Products and Crude segment, we are exposed to some commodity price risk, including product price and location differentials primarily from our optimization and marketing activities, as well as product retained during the operations of our pipelines and terminals. See additional discussion regarding our commodity price risk and related hedging activities under “Commodity Price Risk” in Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk, in this Annual Report.

Seasonality - Cold temperatures usually increase demand for natural gas and certain Purity NGLs, such as propane, a heating fuel for homes and businesses. Warm temperatures usually increase demand for natural gas used in gas-fired electric generation for residential and commercial cooling, as well as agriculture-related equipment like irrigation pumps and crop dryers. Demand for butanes and natural gasoline, which are used by the refining industry as blending stocks for motor fuel, denaturant for ethanol and diluents for crude oil, are also subject to some variability during seasonal periods when certain government restrictions on motor fuel blending products change. Additionally, our liquids blending activities are limited by seasonal changes in gasoline vapor pressure specifications and by the varying quantity of the gasoline delivered to us. During periods of peak demand for a certain commodity, prices for that product typically increase.

Extreme weather conditions, seasonal temperature changes and the impact of temperature and humidity on the mechanical abilities of equipment impact the volumes of natural gas gathered and processed, NGL volumes gathered, transported and fractionated, and Refined Products and crude oil volumes transported and stored. Power interruptions and inaccessible well sites as a result of severe storms or freeze-offs, a phenomenon where water vapor from the well bore freezes at the wellhead or within the natural gas gathering system, may cause a temporary interruption in the flow of natural gas, NGLs, Refined Products and crude oil.

In our Natural Gas Pipelines segment, natural gas storage is necessary to balance the relatively steady natural gas supply with the seasonal demand of our local natural gas distribution and electric-generation customers as a result of the demand from their residential and commercial customers.

Competition- We compete for natural gas, NGL, Refined Products and crude oil volumes with other midstream companies, major integrated oil companies and independent exploration and production companies that have gathering and processing assets, fractionators, pipelines, terminals and storage facilities. The factors that typically affect our ability to compete for natural gas, NGL, Refined Products and crude oil volumes are:

•quality and quantity of services provided;

•producer drilling activity;

•proceeds remitted and/or fees charged under our contracts;

•proximity of our assets to natural gas, NGL, Refined Products and crude oil supply areas and markets;

•proximity of our assets to alternative energy production;

•location of our assets relative to those of our competitors;

•efficiency and reliability of our operations;

•receipt and delivery capabilities for natural gas, NGLs, Refined Products and crude oil that exist in each pipeline system, plant, fractionator, terminal and storage location;

•the petrochemical industry’s level of capacity utilization and feedstock requirements;

•current and forward natural gas, NGLs, Refined Products and crude oil prices; and

•cost of and access to capital.

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We have remained competitive by executing strategic acquisitions; making capital investments to access and connect new supplies with end-user demand; increasing gathering, processing, fractionation and pipeline capacity; increasing storage, withdrawal and injection capabilities; and improving operating efficiency. Our infrastructure projects, along with those of our competitors, may affect commodity prices and could displace supply volumes from the Mid-Continent and Rocky Mountain regions and the Permian Basin where our assets are located. We believe our assets are located strategically, connecting diverse supply areas to market and demand centers.

Customers - Our Natural Gas Gathering and Processing, Natural Gas Liquids and Refined Products and Crude segments derive fees for services from major and independent crude oil and natural gas producers. Our Natural Gas Liquids segment’s customers also include other NGL and natural gas gathering and processing companies. Our downstream commodity sales customers are primarily petrochemical, refining and marketing companies, utilities, large industrial companies, natural gasoline distributors, propane distributors, exporters and municipalities. Our Refined Products and Crude segment’s customers also include crude oil producers, refiners, wholesalers, retailers, traders, railroads, airlines and regional farm cooperatives. End markets for Refined Products deliveries are primarily retail gasoline stations, truck stops, farm cooperatives, railroad fueling depots, military bases and commercial airports. Our Natural Gas Pipeline segment’s assets primarily serve local distribution companies, electric-generation facilities, large industrial companies, municipalities, producers, processors and marketing companies. Our utility customers generally require our services regardless of commodity prices. See discussion regarding our customer credit risk under “Counterparty Credit Risk” in Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk, in this Annual Report.

For additional information regarding the potential impact of market conditions and seasonality on our business, see Item 1A “Risk Factors.”

Other

Through ONEOK Leasing Company, L.L.C. and ONEOK Parking Company, L.L.C., we own a 17-story office building (ONEOK Plaza) and a parking garage in downtown Tulsa, Oklahoma, where our headquarters are located. ONEOK Leasing Company, L.L.C. primarily operates our headquarters office building. ONEOK Parking Company, L.L.C. owns and operates a parking garage adjacent to our headquarters. We have a wholly owned captive insurance company, which was formed in 2022.

REGULATORY, ENVIRONMENTAL AND SAFETY MATTERS

We are subject to a variety of historical preservation and environmental and safety laws and/or regulations that affect many aspects of our present and future operations. Regulated activities include, but are not limited to, those involving air emissions, storm water and wastewater discharges, handling and disposal of solid and hazardous waste, wetland and waterway preservation, wildlife conservation, cultural resource protection, hazardous materials transportation, cleanup of spills or releases of hazardous substances and pipeline and facility construction. These laws and regulations require us to obtain and/or comply with a wide variety of environmental clearances, registrations, licenses, permits and other approvals. Failure to comply with these laws, regulations, licenses and permits may expose us to fines, penalties, reputational harm, claims or lawsuits from third parties, and/or interruptions in our operations that could be material to our results of operations or financial condition. We may also incur material costs for cleanup of spills or releases of hazardous substances. In addition, emissions controls and/or other regulatory or permitting mandates under the Federal Clean Air Act, as amended (Clean Air Act), and other similar federal and state laws could require unexpected capital expenditures at our facilities. We cannot ensure that existing environmental statutes and regulations will not be revised or that new regulations will not be adopted or become applicable to us. We also cannot ensure that existing permits will not be revised or cancelled, potentially impacting facility construction activities or ongoing operations.

Air and Water Emissions - The Clean Air Act, the Federal Water Pollution Control Act Amendments of 1972, as amended (Clean Water Act), the Oil Pollution Act of 1990 and analogous state laws and/or regulations impose restrictions and controls regarding the release of pollutants into the air and water in the United States. Under the Clean Air Act, a federal operating permit is required for sources of significant air emissions. We may be required to incur certain capital expenditures for air pollution-control equipment in connection with obtaining or maintaining permits and approvals for sources of air emissions. The Clean Water Act imposes substantial potential liability for pollutants discharged into waters of the United States and requires remediation of waters affected by such discharge. The Oil Pollution Act aims at preventing and responding to oil spills in U.S. waters and shorelines.

GHG Emissions - In 2024, GHG emissions were approximately 3.9 million metric tons of carbon dioxide equivalents of Scope 1 emissions and 3.6 million metric tons of carbon dioxide equivalents of Scope 2 emissions. Scope 1 emissions originate from

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the combustion of fuel in our equipment, such as compressor engines and heaters, as well as fugitive methane emissions. Scope 2 emissions are generated from purchased power sources.

In 2021, we announced a companywide absolute GHG emissions reduction target of 2.2 million metric tons of carbon dioxide equivalents from our combined Scope 1 and Scope 2 GHG emissions by 2030 for our legacy ONEOK assets. The target represents a 30% reduction in combined operational Scope 1 and location-based Scope 2 GHG emissions attributable to ONEOK assets as of December 31, 2019. As of December 31, 2025, we have achieved reductions totaling approximately 1.8 million metric tons of the targeted 2.2 million metric tons of carbon dioxide equivalents, primarily as a result of methane emissions mitigation, system utilization and optimizations, electrification of certain natural gas compression equipment and lower carbon-based electricity in states in which we operate. GHG emission reductions as reported may be modified, updated, changed or supplemented based on available information. For the years ended December 31, 2025, 2024 and 2023, we did not have any material dedicated capital expenditures specifically for climate-related projects, nor did we purchase or sell carbon credits or offsets. Progress to date on our goal has been accomplished through routine capital projects and asset optimizations that were primarily performed for operational improvements that inherently improved our emissions profile. We continue to anticipate several potential pathways toward achieving our emissions reduction target. In 2026, we intend to work towards further reductions in our emissions toward our target through improved methane management practices and system optimization that will not require material capital expenditures. We do not anticipate purchasing or selling carbon credits or offsets in 2026.

We currently participate in Our Nation’s Energy (ONE) Future Coalition to voluntarily report methane emission reductions and to calculate our methane intensity for our natural gas transmission and storage assets. We continue to focus on maintaining low methane gas release rates through expanded implementation of improved practices to limit the release of natural gas during pipeline and facility maintenance and operations.

We are a participant in the American Petroleum Institute’s The Environmental Partnership and are enrolled in environmental performance programs that are designed to further reduce emissions using proven, cost-effective controls.

Regulation

United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) - On January 17, 2025, the PHMSA issued a final rule, which has been submitted to the Federal Register underscoring to pipeline and pipeline facility operator’s requirements to minimize methane emissions in the Protecting our Infrastructure of Pipelines and Enhancing Safety (PIPES) Act of 2020. The PIPES Act directs pipeline operators to update their inspection and maintenance plans to address the elimination of hazardous leaks and to minimize natural gas releases from pipeline facilities. The updated plans must also address the replacement or remediation of pipeline facilities that historically have been known to experience leaks. We have completed and continue to update our pipeline maintenance procedures to identify and reduce methane leaks.

United States Environmental Protection Agency (EPA) - The EPA’s Mandatory Greenhouse Gas Reporting Rule requires annual GHG emissions reporting from our affected facilities and the carbon dioxide emission equivalents for all hydrocarbon liquids produced by us as if all products were combusted, even if they are used otherwise. The additional cost to gather and report this emission data did not have, and we do not expect it to have, a material impact on our results of operations, financial position or cash flows. In September 2025, the EPA proposed to permanently remove program obligations for 46 source categories of the Greenhouse Gas Reporting Program (GHGRP). Under the proposal, facilities, suppliers and underground injection sites under these 46 source categories would no longer report to the EPA after reporting year 2024. In accordance with the new administration’s Executive Order (E.O.) 14192, “Unleashing Prosperity Through Deregulation,” the EPA has reviewed the GHGRP and determined that there is no statutory requirement to collect GHG emissions information for sectors other than the petroleum and natural gas source category (subpart W) segments subject to the Waste Emissions Charge (WEC) rule. For subpart W, the EPA’s proposed amendments consist of two parts. First, the EPA is proposing to permanently remove program obligations for facilities in the natural gas distribution segment. Under the proposal, facilities in the natural gas distribution segment of subpart W would no longer report to the EPA after reporting year 2024. Second, for the remaining nine segments of subpart W, the EPA is proposing to suspend program reporting requirements until reporting year 2034 in accordance with the One Big Beautiful Bill Act. We do not anticipate the proposal to materially change our internal reporting requirements or external disclosures of our GHG emissions.

In 2024, the EPA finalized its rule targeting oil and gas sector emissions of greenhouse gases (primarily methane) and volatile organic compounds (VOCs). The rule includes (i) new source performance standards (NSPS) codified in 40 C.F.R. Part 60 Subpart OOOOb for new sources (i.e., facilities that commence construction, reconstruction, or modification after December 6, 2022), (ii) emission guidelines codified in 40 C.F.R. Part 60 Subpart OOOOc that states must use to develop performance standards for existing sources (i.e., facilities that existed on or before December 6, 2022). This final rule was challenged in

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court by states and industry stakeholders and that litigation is ongoing. In addition, in January 2025, the new administration issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise or rescind all agency actions that are unduly burdensome on the identification, development or use of domestic energy resources. In July 2025, the EPA issued an interim final rule (IFR) to extend multiple compliance deadlines under NSPS OOOOb/c. On December 3, 2025, the EPA issued a final rule that largely affirms the extended compliance deadlines announced in the IFR. At this time, we do not anticipate a material impact to our planned capital, operations and maintenance costs resulting from compliance with the current or pending regulations and proposed EPA actions. However, the EPA and/or state regulators may issue additional regulations, responses, amendments and/or policy guidance, which could alter our present expectations.

Renewable Fuel Standard - We are an obligated party under the Renewable Fuel Standard (RFS) promulgated by the EPA and are required to satisfy our Renewable Volume Obligation (RVO) on an annual basis. To meet our RVO, we must either ensure that the transportation fuel we produce in our optimization and marketing activities contains the mandated renewable fuel components or purchase credits to cover any shortfall. We generally satisfy our RVO requirements through the purchase of RINs. RINs are generated when a gallon of renewable fuel is produced and may be separated when the renewable fuel is blended into gasoline or diesel fuel, at which point the RIN is available for use in compliance or available for sale on the open market. As the RFS program is currently structured, the RVO of all obligated parties may increase over time unless adjusted by the EPA. The ability to incorporate increasing volumes of renewable fuel components into fuel products and the availability of RINs may be limited, which could increase our RFS compliance costs or limit our ability to blend.

We are subject to the EPA federal gasoline distribution regulations.We do not anticipate a material impact to our planned capital, operations and maintenance costs resulting from compliance with the current regulations.

Additionally, we are subject to the EPA’s fuels compliance regulations. These regulations include standards for fuel parameters and require rigorous product sampling and testing, recordkeeping and reporting. Our ongoing compliance with these regulations is not expected to have a material adverse effect on our business.

Federal Regulation - In August 2022, the Inflation Reduction Act of 2022 (IRA) was signed into law. The IRA includes tax credits and other incentives intended to combat climate change by advancing decarbonization and promoting increased investment in renewable and low carbon intensity energy. In addition, the IRA directed the EPA to impose and collect “Waste Emissions Charges,” or “Methane Fees,” for specific facilities that report more than 25,000 metric tons of carbon dioxide equivalent of GHG emissions per year and have a methane emissions intensity in excess of the relevant statutory threshold. In January 2025, industry associations and certain states challenged the Waste Emissions Charge rule in the D.C. Circuit, and the new administration issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise or rescind all agency actions that are unduly burdensome on the identification, development or use of domestic energy resources. In May 2025, aligning with the Congressional resolution to disapprove the WEC rule, the EPA removed the fee implementation regulations from the Code of Federal Regulations. However, the IRA still requires the EPA to collect methane fees, but the implementation has been postponed until reporting year 2034 in accordance with the One Big Beautiful Bill Act. Consequently, future implementation and enforcement of these rules remain uncertain at this time.

We believe it is likely that continued future governmental legislation and/or regulation may require us to limit GHG emissions associated with our operations, pay additional fees associated with our GHG emissions or purchase allowances for such emissions. However, we cannot predict precisely what form these future regulations will take, the stringency of the regulations, when they will become effective or the impact on our capital expenditures, competitive position and results of operations. On February 12, 2026, the EPA issued a final rule eliminating the 2009 GHG endangerment finding, which underpins U.S. federal regulation of GHG emissions under the Clean Air Act. The final rule is expected to be subject to extensive litigation, and the impact is difficult to predict at this time. In addition to activities on the federal level, state and regional initiatives could also lead to the regulation of GHG emissions sooner than or independent of federal regulation, and these regulations could be more stringent than requirements in any future federal legislation and/or regulation. We monitor all relevant legislation and regulatory initiatives to assess the potential impact on our operations and otherwise take steps to limit GHG emissions from our facilities, including methane.

For additional information regarding the potential impact of laws and regulations on our operations, see Item 1A “Risk Factors.”

Waste - Our operations generate waste, including hazardous waste, that is subject to the requirements of the Resource Conservation and Recovery Act, as amended (RCRA), and comparable state statutes. We are not currently required to comply with a substantial portion of the RCRA requirements as our operations routinely generate only small quantities of hazardous waste, and we are not a hazardous waste treatment, storage or disposal facility operator that is required to obtain a RCRA

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permit. While the RCRA currently exempts a number of types of waste from being subject to hazardous waste requirements, including many oil and gas exploration and production wastes, the EPA could consider the adoption of stricter disposal standards for nonhazardous waste. Moreover, it is possible that additional waste, which could include nonhazardous waste currently generated during operations, may be designated as hazardous waste. Hazardous waste is subject to more rigorous and costly storage and disposal requirements than nonhazardous waste. Changes in the regulations could materially increase our operating expenses.

We own or lease properties where hydrocarbons have been handled for many years, during which operating and disposal standards have evolved. Although we believe we have utilized operating and disposal practices that meet prevailing industry standards, hydrocarbons or other waste may have been disposed of or released on, under or from the properties owned or leased by us or at offsite disposal facilities. In addition, many of these properties were previously operated by third parties whose treatment and disposal or release of hydrocarbons or other waste was not under our control. These properties and waste disposal facilities may be subject to Comprehensive Environmental Response Compensation and Liability Act, as amended, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed waste, including waste disposed of or released by prior owners or operators, to remediate contaminated property, including groundwater contaminated by prior owners or operators, or to make capital improvements to prevent future contamination.

Pipeline and Facility Safety - We are subject to PHMSA safety regulations, including pipeline asset integrity-management regulations. The Pipeline Safety Improvement Act of 2002 requires pipeline companies operating high-pressure pipelines to perform integrity assessments on pipeline segments that pass through densely populated areas or near specifically designated high-consequence areas (HCAs). The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (the 2011 Pipeline Safety Act) increased maximum penalties for violating federal pipeline safety regulations, directs the United States Department of Transportation (DOT) and Secretary of Transportation to conduct further review or studies on issues that may or may not be material to us and may result in the imposition of more stringent regulations. Penalty amounts have since been regularly adjusted for inflation with the most recent adjustment taking effect on December 30, 2025. For the years 2020 through 2023, PHMSA’s Mega Rule increased requirements for operating and maintenance, integrity management, public awareness and civil/criminal penalties with full compliance deadlines extending into 2035; however, we do not anticipate a material impact to our planned capital or operations and maintenance costs resulting from compliance with these requirements.

Our NGL, Refined Products and crude oil pipeline systems are subject to regulation by the DOT and PHMSA under the Hazardous Liquid Pipeline Safety Act of 1979, as amended (HLPSA). The HLPSA prescribes and enforces minimum federal safety standards for the transportation of hazardous liquids by pipeline, including the design, construction, testing, operation and maintenance, spill response planning and overall reporting and management related to our pipeline facilities. In addition to the amended HLPSA covered in Title 49 of the Code of Federal Regulations, subsequent statutes provide the framework for the pipeline hazardous liquid safety program and include provisions related to PHMSA’s authorities, administration and regulatory activities.

In 2020, legislation was passed to reauthorize PHMSA through 2023. Legislation is currently pending to extend this authorization. Certain requirements for operations and maintenance, integrity management, leak detection and public awareness will be subject to future rulemaking as a result. The potential capital and operating expenditures related to the new regulations are not fully known, but we do not anticipate a material impact to our planned capital or operations and maintenance costs resulting from compliance with the new regulations.

Our marine terminals along coastal waterways are subject to U.S. Coast Guard regulations and comparable state and municipal statutes relating to the design, installation, construction, testing, operation, replacement and management of these assets.

Certain of our field injection and withdrawal wells and water disposal wells are subject to the jurisdiction of the Railroad Commission of Texas (RRC). The RRC regulations require that we report the volumes of natural gas and water disposal associated with the operations of such wells on a monthly and annual basis, respectively. Results of periodic mechanical integrity tests must also be reported to the RRC.

PHMSA regulates safety issues related to downhole facilities located at both intrastate and interstate underground natural gas storage facilities. PHMSA mandates certain reporting requirements for operators of underground natural gas storage facilities and sets minimum federal safety standards. In addition, all intrastate transportation-related underground natural gas storage facilities are subject to minimum federal safety standards and are inspected by PHMSA or by a state entity that has chosen to expand its authority to regulate these facilities under a certification filed with PHMSA. State entities that exercise jurisdiction over our underground natural gas storage facilities include the RRC (for our underground natural gas storage facilities in Texas) and LDNR (for our underground natural gas storage facilities in Louisiana). We do not believe continued compliance with

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safety standards and other requirements applicable to our underground natural gas storage facilities will have a material impact on results of operations, financial position or cash flows.

Pipeline Security - In April 2021, the United States Department of Homeland Security’s Transportation Security Administration (TSA) released revised pipeline security guidelines that included broader definitions for the determination of pipeline “critical facilities.” In January 2026, we completed our 2025 annual review of our pipeline facilities according to the guidelines. The cost of compliance did not have a material impact on our operations, financial position or cash flows.

In July 2021, the TSA began issuing pipeline security directives to owners and/or operators of critical pipeline systems or facilities. Pursuant to those directives, our Cybersecurity Implementation Plan was last approved in November 2025, and our Cybersecurity Assessment Plan was last approved in September 2025. While compliance with the security directives requires significant internal and external resources, we do not expect it to have a material impact on our results of operations, financial position or cash flows.

HUMAN CAPITAL

Our business strategy includes attracting, selecting and retaining talent, advancing an inclusive, diverse and engaged culture and developing individuals and leaders.

As of December 31, 2025, we had 6,326 employees. Listed below is a summary of our human capital resources, measures and objectives that are collectively important to our success as an organization.

Values - Our success relies on the skills, experience and dedication of our employees. We are committed to cultivating an inclusive and dynamic work environment where people can find opportunities to succeed, grow and contribute to our success. Our employees work each day to provide safe and reliable services to a wide range of customers in the states where we operate. Our core values, listed below, guide our employee behaviors and the ways in which we conduct our business and operations.

•Safety & Environmental: we commit to a zero-incident culture for the well-being of our employees, contractors and communities and to operate in an environmentally responsible manner.

•Ethics: we act with honesty, integrity and adherence to the highest standards of personal and professional conduct.

•Inclusion & Diversity: we respect the uniqueness and worth of each individual, and we believe that an inclusive culture and diverse workforce are essential for a sense of belonging, engagement and performance.

•Excellence: we hold ourselves and others accountable to a standard of excellence through collaboration and continuous improvement.

•Service: we invest our time, effort and resources to serve each other, our customers and communities.

•Innovation: we create value by leveraging collaboration, ingenuity and technology.

Employee Engagement, Inclusion and Diversity - Our employee engagement, inclusion and diversity strategy is a cross-functional effort that draws upon contributions from employees at all levels of the organization and is focused on enhancing the workplace to attract and retain talent. The strategy is guided by a council composed of a diverse group of employees who represent different demographics, work locations, points of view, roles and levels of seniority. We also have a team within our human resources department that is wholly dedicated to supporting our employee engagement, inclusion and diversity efforts.

We provide support for four employee-led business resource groups (BRGs) that include a Racial/Ethnic Inclusion Resource Group, Veterans Resource Group, Women’s Resource Group and LGBTQ+ Resource Group. The purpose of these groups is to promote the attraction, development, engagement and retention of talented members of traditionally underrepresented groups in our industry and workplace in an effort to drive positive business outcomes. A key factor in the success of our BRGs is the active participation by officer-level executive sponsors and allies from outside the BRG’s underrepresented populations. All employees are invited to become supporters of our BRGs.

We embed employee engagement, inclusion and diversity concepts into our core leadership development curriculum and sponsor a number of internal programs intended to promote employee engagement, inclusion and diversity. In addition, we seek to give back to the communities where we operate by partnering on initiatives to support underrepresented community members and local charitable organizations.

We conduct employee engagement surveys, typically on an annual basis. In 2025, the annual employee engagement participation rate increased to 95% compared with 93% in 2024. The overall engagement mean increased to the 81st percentile and the ratio of engaged employees to actively disengaged also increased.

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Employee Safety - The safety of our employees is critical to our operations and success. By promoting the safety of our employees and monitoring the integrity of our assets, we are investing in the long-term sustainability of our businesses. We continuously assess the risks our employees face in their jobs, and we work to mitigate those risks through training, appropriate engineering controls, work procedures and other preventive safety programs. Reducing incidents and improving our personal safety incident rates are important, but we are not focused only on statistics. Low personal safety incident rates alone cannot prevent a large-scale incident, which is why we continue to focus on enhancing our Environmental, Safety and Health management systems and process safety programs, such as key risk/key control identification and knowledge sharing. We endeavor to operate our assets safely, reliably and in an environmentally responsible manner. We maintain mature and robust programs that guide trained staff in the completion of these activities, and we continue to enhance and improve these programs and our internal capabilities.

Health and Welfare - We provide a variety of benefits to help promote the health and welfare of our employees and their families. These benefits include medical, dental and vision plans, virtual health visits and engagement of third-party service providers to offer company on-site and near-site clinics in several of our operating areas. Eligible employees also have access, at no charge, to an employee assistance program, a medical second opinion service and a health care concierge service to assist with finding in-network providers and billing resolution. We offer full pay for maternity, paternity or adoption leave of up to six weeks per qualifying event. We also provide up to $10,000 for reasonable and necessary expenses of a qualifying adoption and/or surrogacy. Additional benefits available for the welfare of our employees include, among others, life insurance and long-term disability plans, health and dependent care flexible spending accounts, fertility benefits, disease prevention and management programs and full pay while on bereavement, military or personal and family care leave. On May 1, 2025, legacy EnLink employees received access to these ONEOK health and welfare benefits.

We also provide the opportunity for our employees to help fellow employees through the ONE Trust Fund by contributing donated vacation hours or monetary donations. The ONE Trust Fund is an independent nonprofit, charitable organization run entirely by employee volunteers, that serves our employees in times of personal crises due to natural disasters, medical emergencies or other hardships. Further, we provide volunteer opportunities and volunteer grants, as well as $10,000 of charitable giving matching, annually, through the ONEOK Foundation.

Personal and Professional Development - We provide various options to assist with career growth and development. For employees just entering the workforce who desire to advance their career and continue to learn or for the employees who are interested in developing their skills, we make available to all employees education and training in a variety of areas, including leadership, functional and industry-specific topics, professional development and skill-building opportunities.

We value education and assist eligible employees with the expense of furthering their education in job-related fields, including up to $5,250 per year in qualifying tuition expenses. We also may reimburse employees for certain job-related professional certification examination fees.

Recruiting - We make it a priority to attract, select, develop, motivate, challenge and retain the talent necessary to support our key business strategies. We use targeted recruitment events, maintain strong relationships with area technical schools, colleges and universities, and we offer compensation benefits and career opportunities that are designed to position us as an employer of choice. Employee engagement, inclusion and diversity continues to be a priority in recruiting, and we deploy strategies designed to access talent from many sources, skill sets and backgrounds.

Retirement - We maintain the ONEOK 401(k) Plan for our employees and match 100% of employee 401(k) Plan contributions up to 6% of each participant’s eligible compensation, subject to certain conditions and limits. We maintain three defined benefit pension plans, including the ONEOK Retirement Plan, covering certain legacy ONEOK employees, and the Magellan Pension Plan and the Magellan Pension Plan for USW Employees, each covering certain legacy Magellan employees. We also make profit-sharing contributions under our 401(k) Plan for employees who do not participate in our defined benefit pension plans. Effective January 1, 2025, quarterly profit-sharing contributions increased to 6% from 1% of each profit-sharing participant’s eligible compensation during the quarter. We may also make annual discretionary profit-sharing contributions of up to 2% of eligible compensation. As of December 31, 2025, 96% of eligible employees were contributing to our 401(k) Plan. For additional information about our retirement benefits, see Note L of the Notes to Consolidated Financial Statements in this Annual Report.

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS

All executive officers are elected annually by our Board of Directors. Our executive officers listed below include the officers who have been designated by our Board of Directors as our Section 16 executive officers.

Name and Position Age Business Experience in Past Five Years

2014 to 2021 President and Chief Executive Officer, ONE Gas, Inc.

2014 to 2021 Member of the Board of Directors, ONE Gas, Inc.

2017 to 2022 Executive Vice President and Chief Operating Officer, ONEOK

2017 to 2022 Senior Vice President, Natural Gas Liquids, ONEOK

No family relationships exist between any of the executive officers, nor is there any arrangement or understanding between any executive officer and any other person pursuant to which the officer was selected.

INFORMATION AVAILABLE ON OUR WEBSITE

We make available, free of charge, on our website (www.oneok.com) copies of our Annual Reports, Quarterly Reports, Current Reports on Form 8-K, Proxy Statements, amendments to those reports filed or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act and reports of holdings of our securities filed by our officers and directors under Section 16 of the Exchange Act as soon as reasonably practicable after filing such material electronically or otherwise furnishing it to the SEC. Copies of our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Director Independence Guidelines, Corporate Sustainability Report and the written charters of our Board Committees also are available on our website, and we will provide copies of these documents upon request.

In addition to our filings with the SEC and materials posted on our website, we also use social media platforms as additional channels of distribution to reach public investors. Information contained on our website, or posted on our social media accounts, including any corresponding applications, are not incorporated by reference into this report.

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ITEM 1A. RISK FACTORS

You should consider carefully the following discussion of risks, as well as all of the other information contained in this Annual Report. Our business, financial conditions, results of operations or prospects could be materially and adversely affected by any of these risks or uncertainties.

RISK FACTORS RELATED TO OUR BUSINESS AND INDUSTRY

If the level of drilling in the regions in which we operate declines substantially near our assets, our volumes and revenues could decline.

Our gathering and transportation pipeline systems are dependent upon production from natural gas and crude oil wells, which naturally decline over time. As a result, our cash flows associated with these wells may also decline over time. In order to maintain or increase throughput levels on our gathering and transportation pipeline systems and the asset utilization rates at our processing and fractionation facilities, we must continually obtain new supplies. Our ability to maintain or expand our businesses depends largely on the level of drilling and production by third parties in the regions in which we operate. Our natural gas, NGL and crude supply volumes may be impacted if producers curtail or redirect drilling and production activities. Drilling and production are impacted by factors beyond our control, including:

•demand and prices for natural gas, NGLs, Refined Products and crude oil;

•producers’ access to capital;

•producers’ finding and development costs of reserves;

•producers’ ability to secure drilling and completion crews and equipment;

•producers’ desire and ability to obtain necessary permits, drilling rights and surface access in a timely manner and on reasonable terms;

•crude oil and associated natural gas field characteristics and production performance;

•regulatory compliance and environmental or other governmental regulations;

•reserve performance; and

•capacity constraints and/or shutdowns on the pipelines that transport crude oil, natural gas, NGLs and Refined Products from producing areas and our facilities.

Commodity prices are subject to significant volatility. Drilling and production activity levels may vary across our geographic areas; however, a prolonged period of low commodity prices may reduce drilling and production activities across all areas. If we are not able to obtain new supplies to replace the natural decline in volumes from existing production or reductions in volumes because of competition, throughput on our gathering and transportation pipeline systems and the utilization rates of our processing and fractionation facilities would decline, which could adversely affect our business, results of operations, financial position and cash flows.

Our operating results may be adversely affected by unfavorable economic and market conditions.

Uncertainty or adverse changes in economic conditions worldwide, in the United States, or in the economic regions in which we operate, could negatively affect the crude oil and natural gas markets, resulting in reduced demand and increased price competition for our services and products, or otherwise adversely affect our business, results of operations, financial position and cash flows. Volatility in commodity prices may have an impact on many of our suppliers and customers, which, in turn, could have a negative impact on their ability to meet their obligations to us. Periods of severe volatility in equity and credit markets may disrupt our access to such markets, make it difficult to obtain financing necessary to expand facilities or acquire assets, increase financing costs and result in the imposition of restrictive financial covenants. Inflationary pressures have resulted in, and may continue to result in, additional increases to the cost of our materials, services and personnel, which could increase our capital expenditures and operating costs. In addition, future tariffs, trade restrictions or retaliatory measures could further increase our input costs, lengthen delivery schedules or disrupt the availability of key components, particularly if we are unable to manage lead times for materials and equipment used in constructing capital projects or to enter into procurement agreements for long‐lead items to mitigate such risks. Sustained levels of high inflation could cause the Federal Reserve System and other central banks to increase interest rates, which could cause the cost of capital to increase and depress economic growth, either of which, or the combination of both, could adversely affect our business, results of operations, financial position and cash flows.

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The volatility of natural gas, NGL, Refined Products and crude oil prices could adversely affect our earnings and cash flows.

Lower commodity prices could reduce crude oil, natural gas and NGL production, which could decrease the demand for our services. Additionally, a portion of our revenues are derived from the sale of commodities that are received or purchased in conjunction with our gathering, processing, fractionation, transportation and storage services. As commodity prices decline, we could be paid less for our commodities thereby reducing our cash flows. Historically, commodity prices have been volatile and can change quickly. It is likely that commodity prices will continue to be volatile in the future.

The prices we receive for our commodities are subject to wide fluctuations in response to a variety of factors beyond our control, including, but not limited to, the following:

•overall domestic and global economic conditions and uncertainty;

•changes in the supply of, and demand for, domestic and foreign energy, even if relatively minor;

•market uncertainty;

•the occurrence of wars (such as the Russian invasion of Ukraine), the activities of the Organization of Petroleum Exporting Countries (OPEC) and other non-OPEC oil producing countries with large production capacity, or other geopolitical conditions (including instability in the Middle East and Venezuela) impacting supply and demand for natural gas, NGLs, Refined Products and crude oil;

•production decisions by other countries, and the failure of countries to abide by agreements relating to production decisions;

•the availability and cost of third-party transportation, natural gas processing and fractionation capacity;

•the level of consumer product demand and storage inventory levels;

•ethane rejection;

•weather conditions;

•public health crises, including pandemics;

•domestic and foreign governmental regulations and taxes;

•the price and availability of alternative fuels;

•speculation in the commodity futures markets;

•the effects of imports and exports on the price of natural gas, NGLs, Refined Products, crude oil and liquified natural gas;

•the effect of worldwide energy-conservation measures;

•the impact of new supplies, new pipelines, processing and fractionation facilities on location price differentials; and

•technology and improved efficiency impacting supply and demand for natural gas, NGLs, Refined Products and crude oil.

These external factors and the volatile nature of the energy markets make it difficult to reliably estimate future prices of commodities and the impact commodity price fluctuations have on our customers and their need for our services, which could adversely affect our business, results of operations, financial position and cash flows.

Reduced volatility in energy prices or new government regulations could discourage our storage customers from holding positions in Refined Products, crude oil and natural gas, which could adversely affect our business.

The demand for our storage services has resulted in part from customers’ desire to have the ability to take advantage of profit opportunities created by the volatility in prices of Refined Products, crude oil and natural gas. Periods of prolonged stability or declines in these commodity prices could reduce demand for our storage services. If federal, state or international regulations are passed that discourage our customers from storing these commodities, demand for our storage services could decrease, in which case we may be unable to identify customers willing to contract for such services or be forced to reduce the rates we charge for our services. The realization of any of these risks could adversely affect our business.

We depend on producers, gathering systems, refineries and pipelines owned and operated by others to supply our assets, and any closures, interruptions or reduced activity levels at these facilities may adversely affect our business, results of operations, financial position and cash flows.

We depend on crude oil production and on connections with gathering systems, refineries and pipelines owned and operated by third parties to supply our assets. We cannot control or predict the amount of product that will be delivered to us by the gathering systems and pipelines that supply our assets, nor can we control or predict the output of refineries that supply our Refined Products pipelines and terminals. Changes in the quality or quantity of this crude oil production, outages at these refineries or reduced or interrupted throughput on gathering systems or pipelines due to weather-related or other natural causes,

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competitive forces, testing, line repair, damage, reduced operating pressures or other causes could reduce shipments on our pipelines or result in our being unable to receive products at or deliver products from our terminals, any of which could adversely affect our business, results of operations, financial position and cash flows.

Refineries that supply or are supplied by our facilities are subject to regulatory developments, including but not limited to low carbon fuel standards, regulations regarding fuel specifications, plant emissions and safety and security requirements that could significantly increase the cost of their operations and reduce their operating margins. In addition, the profitability of the refineries that supply our facilities is subject to regional and global supply and demand dynamics that are difficult to predict. A period of sustained weak demand or increased costs could make refining uneconomic for some refineries, including those directly or indirectly connected to our Refined Products and crude oil pipelines. The closure of a refinery that delivers product to or receives crude oil from our pipelines could reduce the volumes we transport. Further, the closure of these or other refineries could result in our customers electing to store and distribute Refined Products and crude oil through their proprietary terminals, which could result in a reduction in demand for our storage services.

Our operations are subject to operational hazards and unforeseen interruptions, which could adversely affect our business and for which we may not be adequately insured.

Our operations are subject to all the risks and hazards typically associated with the operation of gathering, transportation and distribution pipelines, storage facilities and processing and fractionation facilities, which include, but are not limited to, leaks, pipeline ruptures, damage by third parties, the breakdown or failure of equipment or processes and the performance of facilities below expected levels of capacity and efficiency. Other operational hazards and unforeseen interruptions include adverse weather conditions (including extreme cold weather), public health crises including a pandemic, cybersecurity attacks, geopolitical events, accidents, explosions, fires, the collision of equipment with our pipeline facilities (for example, this may occur if a third party were to perform excavation or construction work near our facilities) and catastrophic events such as tornados, hurricanes, earthquakes, floods and other similar events beyond our control. Similar operational hazards and unforeseen interruptions may also impact our producers or suppliers; for example, extreme cold weather can result in supply reductions from producer wellhead freeze-offs, as well as power curtailments or outages. A casualty occurrence may result in injury or loss of life, extensive property damage or environmental damage. The occurrence of operational hazards and unforeseen interruptions could adversely affect our business, results of operations, financial position and cash flows.

Premiums and deductibles for certain insurance policies can increase substantially, and, in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. Consequently, we may not be able to renew existing insurance policies or purchase other desirable insurance on commercially reasonable terms, if at all. Insurance proceeds may not be adequate to cover all liabilities or incurred costs and losses or lost earnings. Further, we are not fully insured against all risks inherent to our business. If we were to incur a significant liability for which we were not fully insured, it could adversely affect our business, results of operations, financial position and cash flows. Further, the proceeds of any such insurance policies may not be paid in a timely manner or reach the level of coverage purchased.

Continued development of supply sources outside of our operating regions could impact demand for our services.

Production areas outside of our operating regions may compete with natural gas, NGL, Refined Products and crude oil supply originating in production areas connected to our systems, which may cause products in supply areas connected to our systems to be diverted to markets other than our traditional market areas and may affect capacity utilization adversely on our pipeline systems and our ability to renew or replace existing contracts.

We do not hedge fully against commodity price risk or interest rate risk, including commodity price changes, seasonal price differentials, product price differentials or location price differentials. This could result in decreased revenues, increased costs and lower margins, adversely affecting our results of operations.

Certain of our businesses are exposed to market risk and the impact of market fluctuations in natural gas, NGL, Refined Products and crude oil prices. Market risk refers to the risk of loss of future cash flows and earnings arising from adverse changes in commodity prices. Our primary commodity price exposures arise from:

•the value of the commodities sold under fee with POP contracts of which we retain a portion of the sales proceeds;

•product price differentials;

•location price differentials;

•seasonal price differentials;

•the price risk related to electricity costs to operate our facilities; and

•the fuel costs and the value of the retained fuel in-kind in our natural gas pipelines and storage operations.

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We do not hedge fully against commodity price changes, and we therefore retain some exposure to market risk. Further, hedging arrangements for forecasted sales and purchases are used to reduce our exposure to commodity price fluctuations and may limit the benefit we would otherwise receive if market prices for natural gas, NGLs, Refined Products and crude oil differ from the stated price in the hedge instrument for these commodities. Finally, hedging instruments that are used to reduce our exposure to interest-rate fluctuations could expose us to risk of financial loss where we may contract for fixed-rate swap instruments to hedge variable-rate instruments and the fixed rate exceeds the variable rate.

A breach of information security, including a cybersecurity attack, or failure of one or more key information technology or operational systems, or those of third parties, may adversely affect our operations, financial results or reputation.

Our businesses are dependent upon our operational systems to process a large amount of data and complex transactions. The various uses of these information technology systems, networks and services include, but are not limited to:

•controlling our plants and pipelines with industrial control systems including Supervisory Control and Data Acquisition;

•collecting and storing customer, employee, investor and other stakeholder information and data;

•processing transactions;

•summarizing and reporting results of operations;

•hosting, processing and sharing confidential and proprietary research, business plans and financial information;

•complying with regulatory, legal, financial or tax requirements;

•providing data security; and

•other processes necessary to manage our business.

If any of our systems is damaged, fails to function properly or otherwise becomes unavailable, we may incur substantial costs to repair or replace them and may experience loss or corruption of critical data and interruptions or delays in our ability to perform critical functions, which could adversely affect our business and results of operations. Our financial results could also be adversely affected if our operational systems fail as a result of an inadvertent error or by deliberate tampering with or manipulation of our operational systems. In addition, dependence upon automated systems may further increase the risk that operational system flaws or employee or third-party tampering or manipulation of those systems will result in losses that are difficult to detect.

Due to increased technology advances and an increase in remote work arrangements, we have become more reliant on technology to help increase efficiency in our businesses. According to experts, there has been a rise in the number and sophistication of cyberattacks on companies’ network and information systems by both state-sponsored and criminal organizations and, as a result, the risks associated with such an event continue to increase. A significant failure, compromise, breach or interruption in our systems, or those of our vendors or counterparties, could result in a disruption of our operations, physical or environmental damages, customer dissatisfaction, damage to our reputation and a loss of customers or revenues. If any such failure, interruption or similar event results in the improper disclosure of information maintained in our information systems and networks or those of our vendors and counterparties, including personnel, customer, vendor and counterparty information, we could also be subject to liability under relevant contractual obligations, laws and regulations protecting personal data and privacy. Efforts by us and our vendors and counterparties to develop, implement and maintain security measures may not be successful in anticipating, detecting or preventing these events from occurring, due in part to attackers’ ever-changing methods and efforts to conceal their activities, and any network and information systems-related events could require us to expend significant resources to identify, assess and remedy such events. Cybersecurity, physical security and the continued development and enhancement of our controls, processes and practices designed to protect our enterprise, information systems and data from attack, damage or unauthorized access and to identify and appropriately report cyberattacks, remain a priority for us. Although we believe that we have robust information security procedures and other safeguards in place, including sufficient insurance, as cyberthreats continue to evolve, we may be required to expend additional resources to continue to enhance our information security measures and/or to investigate and remediate information security vulnerabilities.

Cyberattacks against us or others in our industry could result in additional regulations or cumbersome contractual obligations. Current efforts by the federal government, such as the Improving Critical Infrastructure Cybersecurity executive order, and the TSA security directives, have utilized significant internal and external resources, and any potential future statutes, regulations or orders could lead to further increased regulatory compliance costs, insurance coverage costs or capital expenditures. We cannot predict the potential impact to our business resulting from additional regulations.

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Terrorist attacks, including cyber sabotage, aimed at our facilities could adversely affect our business, results of operations, financial position and cash flows.

The United States government has issued warnings that energy assets, including our nation’s pipeline infrastructure, may be the future target of terrorist organizations or “cyber sabotage” events. Potential targets include our facilities, pipelines, databases or operating systems. A terrorist attack could create significant price volatility, disrupt our business, limit our access to capital markets or cause significant harm to our operations, including full or partial disruption to our ability to provide service to our customers. Acts of terrorism, as well as events occurring in response to or in connection with acts of terrorism, could also cause environmental repercussions that could result in a significant decrease in revenues or significant reconstruction or remediation costs. The potential for an attack may subject our operations to increased risks and costs, and any such terrorist attack or cyber sabotage on our facilities, pipelines, databases of operating systems, those of our customers, or in some cases, those of other pipelines could have a material adverse effect on our business, results of operations, financial position and cash flows.

Scrutiny and conflicting stakeholder expectations regarding ESG issues, including climate change, may impact our business.

Companies are subject to scrutiny from customers, investors, rating agencies, policymakers and other stakeholders regarding their management of ESG issues, including human capital and climate change. Changes in regulatory policies, public sentiment or widespread adoption of technologies that aim to address climate change through reducing GHG emissions may result in a reduction in the demand for hydrocarbon products, restrictions on their use or increased use of alternative energy sources. These changes could reduce the demand for our services, impacting our business, results of operations, financial position and cash flows. Certain capital providers could restrict or impose additional scrutiny on lending and investment in the energy sector, which could adversely impact the availability or cost of capital.

In addition, scrutiny regarding climate change and other ESG matters has resulted in an increased likelihood of governmental investigations, regulation, shareholder activism and private litigation by both advocates and opponents of such matters, which could increase our costs or otherwise adversely affect our business. For example, while some policymakers (including certain states and the SEC under the previous administration) have adopted, or are considering adopting, requirements for the disclosure of climate risks or other information, other policymakers have sought to constrain companies’ considerations of ESG matters. Any failure to successfully navigate stakeholder expectations, including regulatory developments, may result in reputational harm, increased costs or other adverse impacts.

We engage in various efforts to respond to stakeholder expectations; however, such efforts may not have the desired effect. Many of these efforts rely on methodologies, assumptions and data (including third-party information) that are subject to varying interpretations or that continue to evolve, including in ways we cannot control. Our approach may also continue to evolve, and we cannot guarantee that our approach will align with the expectations or preferences of any particular stakeholder. For example, our emissions reduction targets depend on a range of factors, and to the extent these do not manifest or we otherwise are unable to make progress on such targets or other initiatives, we may face additional costs or be unable to meet our targets, which could negatively impact our business and reputation. Various of our business partners and other stakeholders are subject to similar expectations on ESG matters, which may exacerbate or result in additional risks.

We may be subject to risks associated with the physical impacts of climate change.

The threat of global climate change may create physical and financial risks to our business. Some of our customers’ energy needs vary with weather conditions, primarily temperature. To the extent weather conditions may be affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of any changes. Increased energy use due to weather changes may require us to invest in more pipelines and other infrastructure to serve increased demand. A decrease in energy use due to weather changes may affect our financial condition through decreased revenues. Extreme weather conditions in general require more system backup, adding to costs, and can contribute to increased system stresses, including damage to our assets or service interruptions. Weather conditions outside of our operating territory could also have an impact on our revenues. Severe weather impacts our operating territories primarily through hurricanes, thunderstorms, tornados, floods, freezing temperatures and snow or ice storms. To the extent the severity or frequency of extreme weather events increases, this could increase our cost of providing services, including the cost of insurance, and the availability of certain insurance coverages could decrease. We may not be able to pass on the higher costs to our customers or recover all costs related to mitigating these physical risks. We are also subject to various transition risks associated with climate change; for more information, see our risk factor titled “Scrutiny and conflicting stakeholder expectations regarding ESG issues, including climate change, may impact our business.”

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Growing our business by constructing new pipelines and facilities or making modifications to our existing facilities subjects us to construction risk and supply risks, should adequate natural gas, NGL, Refined Products and crude oil supply be unavailable upon completion of the facilities.

To expand our business, we regularly construct new and modify or expand existing pipelines and gathering, processing, storage and fractionation facilities. The construction and modification of these facilities may involve the following risks:

•projects may require significant capital expenditures, which may exceed our estimates, and involve numerous regulatory, environmental, political, legal and weather-related uncertainties;

•projects may increase demand for labor, materials and rights of way, which may, in turn, affect our costs and schedule;

•we may be unable to obtain new rights of way or permits to connect our systems to supply or downstream markets;

•if we undertake these projects, we may not be able to complete them on schedule or at the budgeted cost;

•our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time, and we will not receive any material increases in revenues until after completion of the project;

•we may construct facilities to capture anticipated future growth in production or downstream demand in which anticipated growth does not materialize;

•opposition from environmental and social groups, landowners, tribal groups, local groups and other advocates could result in organized protests, attempts to block or sabotage construction activities or operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the construction or operation of our assets;

•we may be required to rely on third parties downstream of our facilities to have available capacity for our delivered natural gas, NGLs, Refined Products and crude oil, which may not be operational; and

•inflationary pressure, along with pressure that may arise from the imposition by the federal government of tariffs on non-U.S. produced construction materials, could increase our costs for construction materials, equipment or labor.

As a result, new facilities may not be able to attract enough natural gas, NGLs, Refined Products and crude oil to achieve our expected investment return, which could adversely affect our business, results of operations, financial position and cash flows.

Estimates of hydrocarbon reserves may be inaccurate, which could result in lower than anticipated volumes.

We may not be able to accurately estimate hydrocarbon reserves and production volumes expected to be delivered to us for a variety of reasons, including the unavailability of sufficiently detailed information and unanticipated changes in producers’ expected drilling schedules. Accordingly, we may not have accurate estimates of total reserves committed to our assets, the anticipated life of such reserves or the expected volumes to be produced from those reserves. In such event, if we are unable to secure additional sources, then the volumes that we gather, process, fractionate and transport in the future could be less than anticipated. A decline in such volumes could adversely affect our business, results of operations, financial position and cash flows.

We do not own all of the land on which our pipelines and facilities are located, and we lease certain facilities and equipment, which could disrupt our operations.

We do not own all of the land on which certain of our pipelines and facilities are located, and we are, therefore, subject to the risk of increased costs to maintain necessary land use. We obtain the rights to construct and operate certain of our pipelines and related facilities on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts on acceptable terms or increased costs to renew such rights, could adversely affect our business, results of operations, financial position and cash flows.

Measurement adjustments on our pipeline systems may be impacted materially by changes in estimation, type of commodity and other factors.

Product measurement adjustments occur as part of the normal operating conditions associated with our assets. The quantification and resolution of measurement adjustments are complicated by several factors including: (i) the significant quantities (i.e., thousands) of measurement equipment that we use across our systems, (ii) varying qualities of natural gas in the streams gathered and processed through our systems and the mixed nature of NGLs gathered and fractionated; and (iii) variances in measurement that are inherent in metering technologies and standards. Each of these factors may contribute to measurement adjustments that may occur on our systems, which could adversely affect our business, results of operations, financial position and cash flows.

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We face competition for supply and, as a result, we may have significant levels of excess capacity on our pipeline, processing, fractionation, terminal and storage assets.

Our pipeline, processing, fractionation, terminal and storage assets compete with other similar assets for natural gas, NGLs, Refined Products and crude oil supply delivered to the markets we serve. As a result of competition, we may have significant levels of uncontracted or discounted capacity on our assets, which could adversely affect our business, results of operations, financial position and cash flows.

Many of our assets have been in service for several decades.

Many of our assets are designed as long-lived assets. Over time the age of these assets could result in increased maintenance or remediation expenditures and an increased risk of product releases and associated costs and liabilities. Any significant increase in these expenditures, costs or liabilities could adversely affect our business, results of operations, financial position and cash flows.

Our operating cash flows are derived partially from cash distributions we receive from our unconsolidated affiliates.

Our operating cash flows are derived partially from cash distributions we receive from our unconsolidated affiliates, as discussed in Note N of the Notes to Consolidated Financial Statements in this Annual Report. The amount of cash that our unconsolidated affiliates can distribute principally depends upon the amount of cash flows these affiliates generate from their respective operations, which may fluctuate from quarter to quarter. We may be unable to unilaterally determine the cash distribution policies of our unconsolidated affiliates. This may contribute to us not having sufficient available cash each quarter to continue paying dividends at the current levels.

We may be unable to cause our joint ventures to take or not to take certain actions unless some or all of our joint-venture participants agree.

We participate in several joint ventures. Due to the nature of some of these arrangements, each participant in these joint ventures has made substantial investments in the joint venture and, accordingly, has required that the relevant charter documents contain certain features designed to provide each participant with the opportunity to participate in the management of the joint venture and to protect its investment, as well as any other assets that may be substantially dependent on or otherwise affected by the activities of that joint venture. These participation and protective features customarily include a corporate governance structure that requires at least a majority-in-interest vote to authorize many basic activities and requires a greater voting interest (sometimes up to 100%) to authorize more significant activities. Examples of activities requiring joint-venture participant approval are large expenditures or contractual commitments, the construction or acquisition of assets, borrowing cash or otherwise raising capital, transactions with affiliates of a joint-venture participant, litigation and transactions not in the ordinary course of business, among others. Thus, without the concurrence of joint-venture participants with enough voting interests, we may be unable to cause any of our joint ventures to take or not to take certain actions, even though those actions may be in the best interest of us or the particular joint venture.

Moreover, subject to contractual restrictions, any joint-venture owner generally may sell, transfer or otherwise modify its ownership interest in a joint venture, whether in a transaction involving third parties or the other joint-venture owners. Any such transaction could result in our being required to partner with different or additional parties who may have business interests different from ours.

We do not operate all of our joint-venture assets nor do we employ directly all of the persons responsible for providing administrative, operating and management services. This reliance on others to operate joint-venture assets and to provide other services could adversely affect our business and results of operations.

We rely on others to provide administrative, operating and management services for certain of our joint-venture assets. We have a limited ability to control the operations and the associated costs of such operations. The success of these operations depends on a number of factors that are outside our control, including the competence and financial resources of the operator or an outsourced service provider. We may have to contract elsewhere for outsourced services, which may cost more than we are currently paying. In addition, we may not be able to obtain the same level or kind of service or retain or receive the services in a timely manner, which may impact our ability to perform under our contracts and adversely affect our business and results of operations.

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Our ability to use net operating losses and certain other tax attributes to offset future taxable income may be limited.

We currently have substantial U.S. federal net operating loss (NOL) carry forward and other state tax attributes. Our ability to use these tax attributes to reduce our future U.S. federal and state income tax obligations depends on many factors, including our future taxable income, the timing of which is uncertain. In addition, our ability to use NOL carryforwards and other tax attributes may be subject to limitations under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”) and corresponding provisions of state law.

Under Section 382 of the Code and corresponding provisions of state law, if a corporation undergoes an ownership change, which is generally defined as a greater than 50 percent change in its equity ownership over a three-year period, the company’s ability to utilize U.S. NOL carryforwards and other tax attributes may be limited. We believe our historical U.S. NOL carryforwards and other tax attributes are not currently subject to a limitation as a result of an ownership change. However, it is possible that an ownership change may occur in the future, which may materially impact our ability to use our U.S. NOL carryforwards and other tax attributes to reduce U.S. federal and state taxable income. Such limitation could adversely affect our results of operations, financial position and cash flows. The historical EnLink NOL carryforward acquired upon the completion of the EnLink Acquisition is subject to limitations under Section 382 of the Code, however, the limitation is not material and will not have an impact on our overall ability to utilize tax attributes to reduce our future U.S. federal and state income tax obligations.

RISK FACTORS RELATED TO REGULATION

Our business is subject to regulatory oversight and potential penalties.

The energy industry is subject to heavy state and federal regulation that extends to many aspects of our businesses and operations, including:

•changes to federal, state and local taxation;

•regulatory approval and review of certain of our rates, operating terms and conditions of service;

•the types of services we may offer our counterparties;

•construction and operation of new facilities, and modifications and operation of existing facilities;

•the integrity, safety and security of facilities and operations;

•acquisition, extension or abandonment of services or facilities;

•reporting and information posting requirements;

•maintenance of accounts and records; and

•relationships with affiliate companies involved in all aspects of our business.

Compliance with these requirements can be costly and burdensome. Future changes to laws, regulations and policies in these areas may impair our ability to compete for business or to recover costs and may increase the cost and burden of our operations. We cannot guarantee that state or federal regulators will not challenge our safety practices or will authorize any projects or acquisitions that we may propose in the future. Moreover, there can be no guarantee that, if granted, any such authorizations will be made in a timely manner or will be free from potentially burdensome conditions.

Under the Natural Gas Act, which is applicable to our interstate natural gas pipelines, and the Interstate Commerce Act, which is applicable to our interstate Refined Products, crude oil and NGL pipelines, our interstate transportation rates are regulated by the FERC and many changes to our pipeline tariffs must be approved in a regulatory proceeding. Additionally, shippers, the FERC and/or state regulatory agencies may investigate our tariff rates which could result in, among other things, our being ordered to reduce rates or make refunds to shippers.

Failure to comply with all applicable state or federal statutes, rules and regulations and orders could bring substantial penalties and fines.

Rate regulation, challenges by shippers of the rates we charge for transportation on our pipelines or changes in the jurisdictional characterization of our assets or activities by federal, state or local regulatory agencies may reduce the amount of cash we generate.

The FERC regulates the rates we can charge and the terms and conditions we can offer for interstate transportation service on our pipelines. State regulatory authorities regulate the rates we can charge and the terms and conditions we can offer for intrastate movements on our pipelines. The determination of the interstate or intrastate character of shipments on our pipelines may change over time, which may change the regulatory framework and the rates we are allowed to charge for transportation

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and other related services. Shippers may protest our pipeline tariff filings, and the FERC or state regulatory authorities may investigate and require changes to tariff terms as a result of the protests or complaints. Further, the FERC may order refunds of amounts collected under interstate rates that are determined to be in excess of a just and reasonable level. State regulatory authorities could take similar measures for intrastate tariffs. In addition, shippers may challenge by complaint the lawfulness of tariff rates that have become final and effective. If existing rates are determined to be in excess of a just and reasonable level, we could be required to pay refunds to shippers, reduce rates and make other concessions.

The FERC’s ratemaking methodologies may limit our ability to increase rates by amounts sufficient to reflect our actual cost or may delay the use of rates that reflect increased costs. The FERC’s indexing methodology is based on changes in the producer price index for finished goods combined with an index adjustment. The methodology is subject to review every five years and currently allows a pipeline to change its rates each year to a new ceiling level. When the change in the ceiling level is negative, we are generally required to reduce our rates that are subject to the FERC’s indexing methodology.

The FERC and most relevant state regulatory authorities allow us to establish rates based on conditions in competitive markets without regard to the FERC’s index level or our cost-of-service. The tariffs on most of our long-haul crude oil pipelines are at negotiated rates but are still subject to regulation by the FERC or state agencies and subject to protest by shippers. If we were to lose our market-based rate authority, or if our negotiated rates were determined to not be just and reasonable, we could be required to establish rates on some other basis, such as our cost-of-service. Establishing our rates through a cost-of-service filing could be expensive and could result in tariff reductions, which would adversely affect our business.

Increased regulation of exploration and production activities, including hydraulic fracturing, well setbacks and disposal of wastewater, could result in reductions or delays in drilling and completing new crude oil and natural gas wells.

The crude oil and natural gas industries rely on supplies from nonconventional sources, such as shale and tight sands. Crude oil and natural gas extracted from these sources frequently requires hydraulic fracturing, which involves the pressurized injection of water, sand and chemicals into a geologic formation to stimulate crude oil and natural gas production. Legislation or regulations placing restrictions on exploration and production activities, including hydraulic fracturing and disposal of wastewater, or curtailment of water use for industrial or mineral development activities, could result in operational delays, increased operating costs and additional regulatory burdens on exploration and production operators. Any of these factors could reduce their production of crude oil and unprocessed natural gas and, in turn, adversely affect our revenues and results of operations by decreasing the volumes of crude oil, natural gas and NGLs gathered, treated, processed, fractionated, stored and transported on our or our joint ventures’ assets.

Our liquids blending activities subject us to federal regulations that govern renewable fuel requirements in the U.S.

The Energy Independence and Security Act of 2007 expanded the required use of renewable fuels in the U.S. Each year, the United States Environmental Protection Agency (EPA) establishes a Renewable Volume Obligation (RVO) requirement for refiners and fuel manufacturers based on overall quotas established by the federal government. By virtue of our liquids blending activity and resulting gasoline production, we are an obligated party and receive an annual RVO from the EPA. We typically purchase renewable identification numbers, called RINs, under the Renewable Fuel Standard Program to meet this obligation. Increases in the cost or decreases in the availability of RINs, as well as any volatility in such costs or availability, could have an adverse impact on our business.

We may face significant costs to comply with the regulation of GHG emissions.

GHG emissions in the midstream industry originate primarily from combustion engine and heater exhaust and fugitive methane gas emissions. International, federal, regional and/or state legislative and/or regulatory initiatives may attempt to control or limit GHG emissions, including initiatives directed at issues associated with climate change. Various federal and state legislative proposals have been introduced to regulate the emission of GHGs, particularly carbon dioxide and methane. In addition, there have been international efforts seeking legally binding reductions in emissions of GHGs.

We believe it is likely that future governmental legislation and/or regulation on the federal, state and regional levels, may further require us to limit GHG emissions associated with our operations, pay additional fees associated with our GHG emissions or purchase allowances for such emissions. In the past, the Inflation Reduction Act of 2022 (IRA) had directed the EPA to impose and collect payment of “Waste Emissions Charges,” or “Methane Fees,” for specific facilities that report more than 25,000 metric tons of carbon dioxide equivalent of GHG emissions per year and have a methane emissions intensity in excess of the relevant statutory threshold. However, the new administration issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise or rescind all agency actions that are unduly burdensome on the identification, development or use of domestic energy resources. The One Big Beautiful Bill Act, passed July 4, 2025,

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suspended the Methane Fee. Additionally, on February 12, 2026, the EPA issued a final rule eliminating the 2009 GHG endangerment finding, which underpins U.S. federal regulation of GHG emissions under the Clean Air Act. The final rule is expected to be subject to extensive litigation. Consequently, future implementation and enforcement of these rules remain uncertain at this time. Methane Fees, if implemented, and other legislative and/or regulatory initiatives that increase our costs or the complexity or compliance burden of business could make some of our activities uneconomic to maintain or operate. However, we cannot predict precisely what form these future legislative and/or regulatory initiatives will take, the stringency of such initiatives, when they will become effective or the impact on our capital expenditures, competitive position and results of operations. Further, we may not be able to pass on the higher costs to our customers or recover all costs related to complying with GHG legislative and/or regulatory requirements. Our future results of operations, financial position or cash flows could be adversely affected if such costs are not recovered or otherwise passed on to our customers.

Our operations are subject to federal and state laws and regulations relating to the protection of public health and safety and the environment, which may expose us to significant costs and liabilities. Increased litigation and activism challenging continued reliance upon oil and gas as well as changes to and/or increased penalties from the enforcement of laws, regulations and policies could adversely impact our business.

The risk of incurring substantial environmental costs and liabilities is inherent in our business. Our operations are subject to extensive federal, state and local laws and regulations relating to the protection of the environment. Examples of these laws include the:

•Federal Clean Air Act, as amended, and analogous state laws that impose obligations related to air emissions;

•Federal Water Pollution Control Act Amendments of 1972, as amended, and analogous state laws that impose requirements related to activities in and around certain state and federal waters, including requirements related to discharge of wastewater from our facilities into state and federal waters and discharge of dredge and fill materials, such as dirt and other earthy materials, into waters of the United States;

•Comprehensive Environmental Response, Compensation and Liability Act, as amended (CERCLA), the Oil Pollution Act (OPA) and analogous state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent waste for disposal;

•National Environmental Policy Act and analogous state laws that establish requirements for certain environmental analyses prior to major government actions, including discretionary permits;

•Endangered Species Act of 1973 and analogous state laws that impose obligations related to protection of threatened and endangered species; and

•Resource Conservation and Recovery Act, as amended (RCRA), and analogous state laws that impose requirements for the handling and discharge of solid and hazardous waste from our facilities.

Upon entering office, the new administration issued a series of executive orders that signal a shift in the United States’ energy, environmental and climate change policy. Among other directives, such executive orders: (i) direct federal agencies to identify and exercise emergency authorities to facilitate conventional energy production, transportation and refining and call for the use of emergency regulations to expedite energy infrastructure projects; (ii) promote energy explorations and production on federal lands and waters; (iii) mandate a review of existing regulations that may burden domestic energy development; and (iv) rescission of funds and programs related to the IRA and Infrastructure Investment and Jobs Act. We continue to assess the long-term impacts of such actions on our operations, if any. However, such actions may prompt various states and other policymakers to take more stringent action on such matters. Therefore, the net impact of any developments is difficult to predict with any certainty.

Various federal and state governmental authorities, including the EPA and the Department of the Interior, have the power to enforce compliance with these laws and regulations and the permits issued under them. Violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Joint and several, strict liability may be incurred without regard to fault under CERCLA, RCRA and analogous state laws for the remediation of contaminated areas.

There is an inherent risk of incurring environmental costs and liabilities in our business due to our handling of the products we gather, transport, process and store; air emissions and water discharge related to our operations; past industry operations and waste disposal practices, some of which may be material. Private parties, including the owners of properties through which our pipeline systems pass, may have the right to pursue legal actions to enforce compliance as well as to seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage arising from our current or historical operations. Some sites we operate are located near current or former third-party hydrocarbon storage and processing operations, and there is a risk that contamination has migrated from those sites to ours. In addition, increasingly strict laws, regulations and enforcement policies could increase significantly our compliance costs, penalties and other cost associated with any alleged noncompliance, and the cost of any remediation that may become necessary; some of these costs could be material

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and could adversely affect our business, results of operation, financial position and cash flows. Our insurance may not cover all of these environmental risks, and there are also limits on coverage. Additional information is included under Item 1, Business, under “Regulatory, Environmental and Safety Matters” and in Note O of the Notes to Consolidated Financial Statements in this Annual Report.

Increased litigation and activism challenging oil and gas development as well as changes to and/or increased enforcement of laws, regulations and policies could impact our business. These actions could, among other things, impact our customers’ activities, our existing permits, our ability to modify or obtain new permits for existing or new development projects and public perception of our company, which could adversely affect our business, results of operations, financial position or cash flows.

RISK FACTORS RELATED TO FINANCING OUR BUSINESS

Changes in interest rates could adversely affect our business.

We use both fixed and variable rate debt, and we are exposed to market risk due to the floating interest rates on our short-term borrowings. Our results of operations, financial position and cash flows could be affected adversely by significant fluctuations in interest rates.

Any reduction in our credit ratings could adversely affect our business, results of operations, financial position and cash flows.

OKE US Equity

OKE · 10-K · period ended 2025-12-31

ITEM 1. BUSINESS

ITEM 1A. RISK FACTORS

OKE US Equity☆

OKE · 10-K · period ended 2025-12-31

ITEM 1. BUSINESS

ITEM 1A. RISK FACTORS

OKE US Equity